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March 18, 2025March 24, 2025

Maryland Crossover Day Update: Bills Passed, Amended, Waiting

The Utility Transparency and Accountability Act was one of the dozens of bills the Maryland House of Delegates passed March 17, sending it to the Senate as part of the legislature’s “crossover day,” which begins a three-week countdown to the close of the 2025 session on April 7.

Otherwise known as HB 121, the bill would require the state’s electric utilities to file a yearly report on all their votes at PJM, or any other RTO, including votes taken at “any committee, user group, task force or other part of the regional transmission organization in which votes are taken.”

Votes are to be reported whether or not they are final votes or made by a person with decision-making authority, the bill says. HB 121 passed the House 128-8, while the Senate version, SB 37, passed with 45-0, on Feb. 27.

With energy a top priority for the Assembly’s Democratic leadership, the bills that crossed over, and the amendments needed for passage, were significant.

For example, SB 116 originally called for the state’s Department of the Environment and Energy Administration to work with the University of Maryland School of Business to produce a report analyzing the environmental, economic and energy impacts of data center development in the state.

But to gain Republican support — and a 46-0 vote — the language requiring the report to look at the energy impacts of data centers was stripped out of the bill.

The House version, HB 270, crossed over Feb. 17 on a 125-8 vote, with no amendments, which means final passage could depend on either the House accepting the Senate amendment or the Senate backtracking.

Amendments could take the teeth out of another bill, SB 149, and its House version, HB 128, a Democratic-sponsored proposal to create a Climate Change Adaptation and Mitigation Program that would require fossil fuel producers doing business in the state to pay fees that would be used to mitigate the impacts of climate change in Maryland.

A flurry of amendments on March 14 essentially rewrote the Senate version, which now would only require the state’s comptroller and Environment and Commerce departments “to conduct a study to assess the total cost of greenhouse gas emissions in the state.” The same amendments were adopted in the House, and both bills passed March 17.

Hoping to Cross Over

Not all state legislatures have crossover days, but among those that do, failure to pass one house by the specified date typically means a bill essentially is dead for the session. In Maryland, however, bills that do not cross over still can move forward with a special vote in the rules committee of either house.

Leaders in both houses appear to be relying on that strategy for the passage of three major energy bills, often referred to as “the leadership package.” The bills cover a range of issues critical for the state to meet its growing energy demand while ensuring affordability and reliability and cutting dependence on imported power, primarily from PJM. (See Ahead of Crossover Day, Energy Bills Stalled in Md. General Assembly.)

- The Energy Resource Adequacy and Planning Act (SB 909) would require the Maryland Public Service Commission to establish an Integrated Resource Planning Office, which would conduct a 25-year comprehensive energy forecast aimed at meeting state clean energy and emission reduction goals.
- The Renewable Energy Certainty Act (SB 931) would set rigorous standards for solar and storage projects seeking a certificate of public necessity and convenience from the PSC, to ensure careful siting and community engagement. The bill also would prohibit city or county governments from passing zoning or other laws blocking solar and storage projects. 
- The Next Generation Energy Act (SB 937) would promote the development of nuclear energy, and the extension of the licenses of existing reactors, as a matter of state policy, while also encouraging regional collaboration between states to share costs on the development of new reactors. The bill also calls for the procurement of 3,100 MW of “dispatchable energy generation capacity” and a temporary expedited permitting process for these projects.

None of the bills crossed over on March 17, but energy advocates and lawmakers like Del. Lorig Charkoudian (D) have said negotiations over possible amendments are ongoing. Speaking with NetZero Insider on March 13, Charkoudian said, “I think what you’re going to see, when they kind of come out or start going through the process in committee, is just a lot of amendments to add, to improve, take the best ideas and move them on.”

She is sponsoring another bill, the Abundant, Affordable Clean Energy (AACE) Act (HB 398, SB 316) which calls for major new procurements of energy storage and solar in the state, as well as better transmission planning for offshore wind and license extensions for existing nuclear plants. Charkoudian said she is working on proposing some of the bill’s provisions as amendments to SB 937.

Distribution and Transmission Planning

Katie Mettle, policy principal for Maryland at Advanced Energy United, is promoting another non-crossover, SB 908 and HB 1225, which would require the state’s utilities to submit detailed distribution system plans to the PSC every three years. The bill calls for these plans to include demand-side management options such as virtual power plants, as well as non-wires solutions for improving reliability.

Mettle remains “cautiously optimistic” it still could move forward. “We love it because it has the potential to save rate payers a lot of money on their electricity delivery costs over time,” she said. “Just building out infrastructure in the most cost-effective way possible … will also lower demand on the grid and really make the grid a lot more reliable.”

Other bills crossing over included:

- HB 155, which would allow the state’s Community Development Administration to provide loans for energy efficiency and clean energy upgrades for multifamily, low- and moderate-income buildings. The loans could be 0% interest, with deferred repayment plans lasting 15 to 40 years. The Senate version, SB 247, still is in committee.
- HB 49, which provides exclusions to the state’s building performance standards in special cases, such as not counting emissions related to the production of steam used for sterilizing medical instruments or from backup generation at a health care facility. The bill also gives building owners the option of paying a compliance fee if they cannot meet the state’s performance standards.
- HB 829, another Charkoudian bill, would require transmission developers seeking approval for a new line to provide the PSC with evidence they had considered alternatives, such as grid-enhancing technologies or distribution system upgrades that would defer the need for a new line. The bill does not have a Senate version.

March 18, 2025March 19, 2025

ACEEE State Efficiency Scorecard Gives California Top Marks

California earned the top score in the American Council for an Energy Efficient Economy’s 2025 State Energy Efficiency Scorecard, released March 18.

The scorecard showed state spending on efficiency rebounded last year to set a record of $8.8 billion, with 90% of the increase coming from five states: Massachusetts, Missouri, New Jersey, New York and Pennsylvania. California scored 93.5 out of 100 points in ACEEE’s rankings, followed by Massachusetts at 80.5 and New York at 79.5, with Maryland and Vermont tied for fourth place at 77.

“Leading states are reducing costs and cutting pollution through energy savings measures, but many other states are stagnating,” Mark Kresowik, ACEEE senior policy director and lead author of the scorecard, said in a statement. “American families have endured years of rising costs and need relief. Energy efficiency upgrades lower utility bills, and now is the time for state policymakers and regulators to help more families see those savings.”

Louisiana was the most improved state, jumping nine places to No. 37 after it adopted a strong building code, which was primarily motivated by skyrocketing insurance costs for homes due to extreme weather, ACEEE said.

Wyoming was at the bottom of the list at just 5.5 points, with Alabama (6 points) and Mississippi (6.5 points) coming in just ahead of it.

Colorado reached the top 10 for the first time, jumping six spots to reach No. 7 after it adopted policies for clean vehicles and a new efficiency standard to cut energy consumption in large buildings and enacted a range of efficiency standards.

“The top states are consistently advancing efficiency across every category, typically receiving at least half of the available points in each sector,” the report said. “The second tier is making considerable progress, but more inconsistently across sectors.”

ACEEE has been releasing the scorecard for 16 years, and it sees a new focus on efficiency due to rising energy bills, with a bigger focus on helping low-income consumers. Efficiency programs invested more than $2 billion last year to make efficiency upgrades that cut their monthly bills, but more than 75% of that was from just four states: California, Massachusetts, Michigan and New York.

“In the wake of rapidly rising energy prices and electricity bills, several states are recognizing energy efficiency’s important role in keeping energy affordable by helping homeowners and businesses reduce costs, by improving living conditions, and by creating jobs, all while supporting increasingly ambitious state and local goals to reduce carbon emissions,” the report said.

States are ranked in six primary policy areas: utility and public benefits programs, transportation policies, building efficiency policies, state government-led policies, industrial energy efficiency and appliance and equipment standards.

Points used to be allocated solely to policies that saved the most energy, but since 2022, the scorecard has started including carbon benefits, which means that policies such as vehicle electrification and building decarbonization generate more points.

States can get 100 points, with 29 from utility programs, 26 from transportation programs, 24 relating to building efficiency policies, nine points to state-led initiatives, six points for industrial programs and six points for state appliance and equipment standards.

Most states have room for improvement on the building energy code because only six have adopted the latest model. Nine states have no code at all, though among them, Colorado requires localities to adopt building codes.

The codes apply to new buildings and can require existing buildings to save energy. Four states and the District of Columbia have adopted standards requiring large buildings to cut energy consumption and climate pollution over time.

A dozen states have adopted clean vehicle standards first developed by California, requiring automakers to sell more zero-emissions cars. An additional 15 states have signed deals to start moving medium- and heavy-duty vehicles to zero-emissions.

March 18, 2025March 30, 2025

DC Circuit Reverses Course on Vacating FERC Approvals of 2 LNG Sites

The D.C. Circuit Court of Appeals on March 18 reversed its vacatur of FERC’s approvals of two LNG export facilities in Texas, having been convinced on appeal that the commission’s procedural errors were not as serious as it initially judged.

The court had vacated FERC’s 2019 approvals of the Brownsville Shipping Channel and Rio Grande LNG in Cameron County, Texas, and remanded them for additional proceedings in 2024. (See DC Circuit Vacates FERC Approval of Two LNG Facilities in Texas.) The court’s vacatur, along with another decision, led then-Chair Willie Phillips to consider changes to how FERC was reviewing natural gas infrastructure. (See DC Circuit Orders Could Lead FERC to Rethink its Natural Gas Policies.)

The three-judge panel’s initial decision held that while the vacatur might cause significant disruptions to the projects, that did not outweigh the seriousness of the commission’s procedural defects in the case. Among them was that, having its approvals already remanded in 2021, FERC did not conduct new environmental impact statements for the projects.

The court followed a precedent that vacatur is warranted when an agency commits a “fundamental” procedural error, such as skipping an environmental review altogether.

“The procedural steps the commission skipped here were important, but they were not ‘fundamental’ in the same sense,” the same panel said. “The commission has already issued extensive final environmental impact statements reflecting more than three years of review and public comment.”

While the decision reversed the vacaturs, FERC must undertake some additional environmental reviews of specific subjects, like Rio Grande’s proposal to add carbon capture and storage to its facility.

“Against that backdrop, the seriousness of the reauthorization orders’ deficiencies does not outweigh the disruptive effects of vacatur,” the court said. “This court never doubted that vacatur would impose significant disruptive consequences … and respondent-intervenors have provided more details about those consequences in their rehearing petitions.”

The complex, large-scale projects have been in development for more than eight years. The court agreed that vacatur would upend their construction schedules, prevent developers from meeting contractual obligations, and stall their ability to get financing and finalize labor contracts — impacting thousands of jobs.

President Donald Trump’s executive orders on energy also have changed some of the legal questions, but the court declined to resolve new issues they brought up because doing so would not have changed its decision that vacatur was not warranted, it said.

March 18, 2025March 30, 2025

7th Circuit Lifts Injunction on Indiana ROFR, Remands LS Power’s Case

The 7th U.S. Circuit Court of Appeals has tossed a temporary injunction against Indiana’s right of first refusal law and sent the case back to a lower court, leaving plaintiff LS Power with more work ahead of it to increase competitively bid transmission projects in MISO.

The court decided LS Power’s arguments were directed at the wrong party and said the company should have named MISO, not the Indiana Utility Regulatory Commission (IURC), as the source depriving it of the chance to bid on long-range transmission projects. The appeals court remanded the case to the district court that issued a preliminary injunction against the right of first refusal (ROFR) law and vacated the injunction (25-1024). The controversy again awaits proceedings from the U.S. District Court for the Southern District of Indiana.

The higher court concluded in its March 13 order that LS Power lacked standing to request the injunction because MISO is the entity responsible for assigning projects from its long-range transmission portfolios to developers. The court also said that because the preliminary injunction was meant for Indiana regulators alone, MISO isn’t beholden to the ban.

The case has raised questions about who administers Indiana’s ROFR law.

LS Power, a competitive transmission developer in MISO, has claimed for months that Indiana’s ROFR is unconstitutional and violates the dormant commerce clause by treating in-state developers differently from out-of-state developers. The company won a preliminary injunction barring Indiana regulators from enforcing the law in December 2024, days before MISO approved a $21.8 billion long range transmission plan for MISO Midwest, raising doubts on who could build projects in the state. (See “Indiana ROFR Reversal Complicates Project Assignment,” MISO Board Endorses $21.8B Long-range Transmission Plan.)

‘An Unusual Situation’

The 7th Circuit acknowledged the case presented “an unusual situation,” with gray area over whether IURC has the authority to enforce the state’s ROFR. It eventually sided with counsel for the Indiana commissioners, who said commissioners are powerless to designate or reassign developers to the regional transmission projects MISO plans and approves.

“Even the subsections of the statute that mention the IURC make clear that the IURC functions only as a notice repository, not as an enforcer of the rights of first refusal,” the court said of the IURC’s role in the ROFR. It said a “genuine redress would have to operate against” MISO.

However, the district court reasoned months before that because IURC enforces the ROFR, MISO would “no longer be permitted to recognize an incumbent’s right of first refusal” and would treat the law as void.

But the 7th Circuit said incumbents taking advantage of their right to first dibs on construction only file notices of intent and descriptions of construction with the state regulatory body, noting that they don’t ask permission.

Furthermore, the court said a preliminary injunction of a state law “does not change the applicability of the law in question to non-parties.”

MISO, meanwhile, has no intention of competitively bidding the Indiana share of its long-range transmission projects.

In an amicus brief in the case, MISO said it did not view itself as bound by the injunction, even though its tariff requires it to follow all applicable state laws. The RTO said the district court’s preliminary injunction “does not direct MISO to take any action, nor does it prohibit MISO from taking any action.”

The court agreed and said because LS Power named Indiana commissioners as defendants and failed to mention MISO in its request for injunctive relief, the company ensured the lower court “could not operate against MISO directly.”

LS Power has attempted to close that gap through FERC. The company in February filed a complaint against MISO, arguing the grid operator should be forced to obey preliminary injunctions of state laws and should open about $1 billion in new long-range transmission projects in Indiana for competitive solicitation. (See LS Power Files Complaint Against MISO over Indiana ROFR.)

The apparent uncertainty over the IURC’s authority drew a dissenting opinion from Circuit Judge Michael Scudder, who argued that ROFR enforcement can be traced to Indiana regulators. Scudder said Indiana law provides “every indication” that IURC has the power to prevent an incumbent transmission owner from building and operating a transmission project in the state.

“Everyone agrees that the commission is the regulatory agency with authority over public utilities in Indiana,” he wrote. “Everyone agrees that HEA 1420 is a law ‘relating to public utilities.’ … It defies belief that the Indiana General Assembly vested the commission with broad enforcement authority, but the commissioners are nevertheless powerless to impose any limitation on a utility company’s ability to construct, own, operate or maintain electric transmission facilities within the state. To adopt that view is to conclude that Indiana law does not mean what it says.”

Scudder said he would have affirmed the district court’s preliminary injunction.

But the 7th Circuit’s majority judges agreed that ordering the IURC to block construction of interstate, MISO-approved transmission lines “would force the IURC into a power struggle with FERC over whether legitimately assigned and important projects” could be built.

“The dissenting opinion would in effect conscript the IURC to enforce the dormant commerce clause rather than carry out its more general duties to enforce Indiana public utility laws,” the court said.

March 18, 2025

NJ Legislators Seek AI Data Center Energy Rules

A key New Jersey Senate committee has backed two measures seeking to limit the energy that artificial intelligence data centers can take out of the transmission and distribution system.

Forecasts predict the state will struggle to meet a dramatic surge in electricity demand in the next two decades.

The Senate Environment and Energy Committee backed S4143, which would require power for data centers to be from clean energy sources or nuclear power plants, or a combination of both. It also requires “no net decrease of verifiable … renewable energy and energy from nuclear power plants supplied to the transmission and distribution system.”

The bill, which passed March 17 on a 3-2 party line vote, also would require that AI data centers seeking local permits submit an energy use plan to the New Jersey Board of Public Utilities (BPU) for approval.

Sen. Bob Smith (D), chair of Senate Environment and Energy Committee | © RTO Insider

In a separate 3-2 vote, the committee also backed a nonbinding resolution, SR125, that urges all states within the PJM region to “enact policies that will require data centers to obtain their electricity from new zero- or low-emission sources of energy.”

The two measures highlighted the state’s growing concern over handling the expected increase in data centers and AI facilities, as well as the conflicting desire to reap the economic benefits of the high-investment facilities.

Chairman Sen. Bob Smith (D), who co-sponsored the bill and the resolution, said after the hearing that data and AI centers consume 10 to 20 times as much energy as other facilities. While the state “would love to have them,” the centers need to pay their way, he said.

“These bills are designed to put some logic and sanity into future development in AI data,” he said. “My contention is that we, the ratepayers of New Jersey, shouldn’t be paying for them. We should require that they bring their own energy, not consume the energy we’re already using and the energy storage that we already paid for, the transmission lines that we already paid for. They need a bigger financial responsibility.”

He said he expects to promote the resolution to other states in the PJM region to pass similar resolutions and pressure PJM to comply.

Supply Shortfall

The committee’s vote followed the March 13 release of the first draft of the next state Energy Master Plan, which predicts a 66% increase in electricity demand by 2050 if the state pursues the same strategy outlined in the 2019 master plan. The new plan predicts much greater increases if the state follows one of the three suggested paths detailed in the plan, which advocates for greater electrification.

State and PJM officials say the dramatic future power imbalance stems from the slow pace of new energy sources coming online and the faster rate fossil fuel generators are closing. The expected development of data centers and AI facilities, with their heavy use of electricity, is another key driver of the demand surge. (See NJ Releases Electrification-focused Energy Master Plan.)

New Jersey officials say the supply shortfall is a key reason behind a 20% hike in residential electricity rates set to take effect in June as a result of a Basic Generation Service (BGS) auction in February. (See NJ Conference Confronts Electricity Demand Squeeze.)

Environmental group members who spoke at the nearly three-hour hearing in Trenton welcomed the two measures, with some saying that without the protection of S4143, the state could end up using carbon-emitting generation sources.

“This data center growth could derail New Jersey’s progress toward clean energy goals and lead to increased fossil fuels,” said Taylor McFarland, conservation manager for the Sierra Club’s New Jersey chapter. “It’s critical for New Jersey to be ahead of the curve and already have regulations and restrictions in place for these data centers so that our environment and our wallets are protected.

“The only way to best tackle the challenge is by requiring data centers to operate through additionality of power instead of (it) being extracted” from existing sources. “Most importantly, this additional power must come from clean energy sources so that we avoid the addition of extracted and polluting fossil fuel driven power.”

Deterrent Effect

Business groups, however, expressed concern the requirements of the bill would deter AI and data center developers from coming to the state.

Ray Cantor, a lobbyist for New Jersey Business & Industry Association (NJBIA), one of the state’s largest business groups, said he agreed with the sentiment of the bill but said the requirements would be excessive and prompt developers to look to other states.

“AI centers coming to New Jersey need to have their own source of power,” he said. “They are enormous drains or energy users, and we are a net importer of energy. We don’t have enough power generated in New Jersey … to supply these AI data centers.”

Ray Cantor, New Jersey Business & Industry Association | © RTO Insider

But he worried that the bill put “certain impediments in place.”

“It requires an energy usage plan. That energy usage plan is not just saying you have to use have your own energy. It’s talking about how you construct your building. It’s talking about the water systems you must use, and other facets of that building,” he said. “It’s just another regulatory process, another regulatory approval that is really not needed … for these facilities to be located. I think they know how to build their own facilities well enough without us telling them.”

Michael Egenton, a lobbyist for the New Jersey State Chamber of Commerce, suggested the state consider offering incentives to companies that want to put AI and data centers in the state if they use renewable energy.

“We should be encouraging them to open up operations in our state, and not placing hurdles, impediments, mandates and fines for compliance,” he said.

Reporting Emissions

The committee also backed S4117, the Climate Corporate Data Accountability Act, which would require companies with annual revenues of $1 billion or more to report their annual greenhouse emissions to the New Jersey Department of Environmental Protection (DEP) and nonprofits selected by the DEP.

The bill requires the companies to report for four years their “Scope 1” emissions, or the direct emissions by the company, and their “Scope 2” emissions, those that stem from the company’s electricity, heat and cooling systems. The companies after five years would have to report their “Scope 3” emissions, which includes those from purchased goods and services, business travel, employee commutes, and the processing and use of sold products.

The bill also enables the DEP to set a fee on the companies to recover administration costs.

Doug O’Malley, executive director of Environment NJ, said the $1 billion threshold ensures only large companies would be affected, and the emissions reporting requirements would force them to calculate how much pollution they generate.

Doug O’Malley, Environment NJ | © RTO Insider

That will “ensure that the largest companies know what their emissions are, with the idea that obviously knowledge is power, sunlight is the best disinfectant,” he said. “And then with that knowledge, we can ultimately look to reductions from the largest emitters in this country.”

Business groups expressed concern at the burden reporting would place on companies, especially small and medium-sized business and especially if they had to report in other states with similar requirements, such as California, as well.

Cantor, of the NJBIA, which opposes the bill, said reporting emission on “Scope 3 is extremely difficult.”

“It’s costly, it’s expensive, it’s confusing, and I don’t believe that this sort of gets us to where we want to go,” he said. “It’s going to require those customers and suppliers to do their own investigation, and they may not be sophisticated enough to do that, to report back to you. It’s going to impact a lot of New Jersey businesses.”

March 18, 2025

NEPOOL Reliability Committee Briefs: March 18, 2025

Load Power Factor Audits

Dean LaForest of ISO-NE presented the results of the RTO’s 2023/24 load power factor (LPF) audit, which found most regional LPF areas to be noncompliant with the standards for low-load, high-voltage conditions.

The system generally graded out better on the standards applying to high-load, low-voltage conditions. However, within regional areas found to be compliant with the standards, regional entities frequently were out of compliance with the standards, ISO-NE found.

LaForest said ISO-NE found “no significant improvement year-over-year in LPF zone compliance.” He said gaining more insight into transmission and distribution operators’ systems “should help focus efforts on where compliance improvements within a zone are needed the most.”

He noted that ISO-NE will share more specific details of the audit directly with the region’s transmission and distribution operators.

Transmission Cost Allocations

Also at the NEPOOL Reliability Committee (RC), stakeholders approved transmission cost allocations for a pair of Eversource infrastructure replacement projects.

The projects, located in Connecticut, include relay replacements on a substation and replacements of aging and deteriorating transmission structures. The projects combined have an estimated $15 million in pool transmission facility costs.

Transmission Outage Scheduling

Anthony Stevens of ISO-NE discussed a series of minor changes to the RTO’s operating procedures governing transmission outage scheduling. The changes will explicitly allow the RTO to approve long-term transmission outages without first having to issue an interim approval of the outages. The changes also clarify the definitions of outage statuses and add language about “alternate dates” used for repositioning outages.

Stevens also presented changes to the RTO’s operating procedures for metering and telemetering criteria. ISO-NE proposes to expand the equipment temperature range to allow for “additional conditions in which data center type HVAC redundancy is in place,” Stevens said.

ISO-NE plans to seek a vote on the operating procedure changes at the RC in April.

Also at the meeting, stakeholders voted to support changes to ISO-NE operating procedures regarding protection outages, settings and coordination. ISO-NE proposes to “add language clarifying that automatic sectionalizing schemes do not require OP-24 Appendix D forms.”

March 17, 2025

EPA Puts Hold on Atlantic Shores OSW Permit

After receiving final approval in October 2024, Atlantic Shores, New Jersey’s sole remaining offshore wind project, has suffered a new setback and is on hold pending an EPA review and reevaluation of federal offshore wind leasing and permitting practices.

On March 14, EPA’s Environmental Appeals Board granted the agency’s motion for a “voluntary remand” on the air quality permit for the project, essentially returning it to EPA for re-evaluation in light of President Donald Trump’s Jan. 20 executive order on offshore wind.

The order withdrew all areas in the U.S. Outer Continental Shelf from offshore wind leasing and ordered a “temporary cessation and review of federal leasing and permitting practices.” However, the order states that “nothing in this withdrawal affects rights under existing leases in the withdrawn areas. With respect to such existing leases, the secretary of the Interior, in consultation with the attorney general as needed, shall conduct a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases.”

EPA’s motion for remand claims Atlantic Shores had not received a final permit and therefore was subject to review and re-evaluation.

In its rebuttal to EPA’s motion, Atlantic Shores argued the voluntary remand should not be granted solely on the basis of Trump’s broadly worded executive order. The project had, in fact, received a final permit, and the agency “has not provided good cause for its motion, failing to identify any permit condition it seeks to substantively change or any element of the permit decision it wishes to reconsider,” the rebuttal said.

EPA also has not identified any provisions of the Clean Air Act or OCS air permitting regulations “that would justify a remand,” Atlantic Shores said.

However, the board’s panel of three judges rejected Atlantic Shores’ argument, saying EPA need not cite specific provisions in a permit it wants to review.

“The board treats requests for voluntary remand liberally and is not limited to circumstances where [EPA] provides specific substantive changes to the final permit or specific elements of the permit decision it seeks to reconsider. …

“The board has generally exercised its broad discretion to grant a permit issuer’s voluntary remand request where the permitting authority is reevaluating its permit decision, because in this situation ‘it would be highly inefficient for the board to issue a final ruling on a permit.’”

The ruling also stated that the board would not accept any appeals of the final permit decision resulting from the remand.

EDF Renewables North America, the developer behind Atlantic Shores, has said it remains committed to the project.

“In a time where the demand for electricity is surging, it is imperative that all forms of power production contribute to deliver all-of-the-above solutions,” said Ryan Pfaff, executive vice president for grid-scale power at EDF. “The Atlantic Shores offshore wind project stands as a frontrunner in advanced energy initiatives, poised to supply substantial megawatt-hours to the grid and bolster American energy dominance,”

“Unfortunately, the recent EPA decision has resulted in a significant setback, erasing years of progress and investment in a complex permitting process,” Pfaff said in an email to NetZero Insider.

EPA has yet to provide details on its process for reviewing and reevaluating the Atlantic Shores permit, whether the process will include opportunities for public and stakeholder input and how long the review might take.

State Support Lags

Atlantic Shores has faced multiple challenges over the past decade. The original federal auction for the Atlantic Shores lease sites was held Nov. 9, 2015, and the sale agreement was finalized in March 2016, according to the Bureau of Ocean Energy Management’s web pages on the project.

The project actually includes two lease sites, Atlantic Shores 1 and 2, to include 197 locations where turbines, undersea substations and a meteorological tower would be built. At its closest point, the project would be 8.7 miles from the New Jersey coastline.

Atlantic Shores 1 was approved by the New Jersey Board of Public Utilities for 1,510 WM. The capacity for the second project still is being determined, but BOEM said the two projects together could provide 2,800 MW.

Transmission lines for the project would come ashore in Atlantic City and Sea Girt, N.J. Local opposition to Atlantic Shores has been ongoing since it was announced, with concerns raised by the fishing and tourism industries and shoreline communities concerned about the project’s impact on “viewsheds” and local economies.

BOEM issued its notice of intent to conduct an environmental review of the project in September 2021. The draft environmental impact statement was issued in May 2023, followed by a series of in-person and virtual public hearings. The final EIS was issued in May 2024, and the permit for construction and operation in October. (See BOEM Approves NJ’s Atlantic Shores OSW Project.)

The 560-page FEIS found that the project would impact the commercial and recreational fishing sector through a range of activities, including anchoring, cable emplacement, noise, port use and structure presence. Beyond its closest point, the project would be about 10 miles offshore.

But the FEIS also concludes the area would suffer major environmental impacts even if the project were not built. Those impacts would stem from factors including fishery management measures taken to ensure the volume of fish caught is sustainable; the impact of climate change from ocean warming, sea level rise and ocean acidification; and non-OSW construction on land. 

Likewise, the study found that though the project would have a major scenic impact on the area — on the open ocean, seascape, and landscape character and views — the coast would suffer strong scenic impacts regardless due to onshore development and construction activities, offshore vessel traffic and the effects of other OSW projects. 

However, market conditions and uncertainty have presented steeper challenges. In January, Atlantic Shores lost a key partner when Shell New Energies U.S. withdrew from the project. (See Shell Quits Atlantic Shores Offshore Wind Project in NJ.)

The New Jersey Board of Public Utilities withdrew its fourth offshore wind solicitation in February, citing the Shell withdrawal and general uncertainty triggered by Trump’s executive order reflecting his well-known antipathy to offshore wind.

While Gov. Phil Murphy (D) said he supported the BPU’s decision, he still called offshore wind a “once-in-a-generation opportunity” to build a new industry and create jobs. “The offshore wind industry is currently facing significant challenges, and now is the time for patience and prudence,” he said.

March 17, 2025March 17, 2025

Overheard at CERAWeek 2025

Pattern CEO Armistead Says Transmission is Being Overlooked

HOUSTON — CERAWeek 2025 by S&P Global, held March 10 to 15, examined the changing energy landscape through 14 themes, from policy and regulation to climate and sustainability.

None seemed to draw more focus from the more than 10,000 attendees (a record) representing 89 countries than the rapid expansion of artificial intelligence technologies and their potential to transform the industry.

Almost four dozen presentations — some that conflicted with each other — included AI in their titles during the conference, including “democratizing AI” or “accelerating AI.” It was no surprise given the projected electricity demand of AI data centers and their potential for producing and managing and consuming power — as well as for helping energy systems become more efficient and sustainable.

Pattern Energy CEO Hunter Armistead | © RTO Insider

“Every time we come to CERA, you kind of think about themes that are going on in the conference,” Pattern Energy CEO Hunter Armistead said. “My next slide will be, of course, a mandatory slide talking about AI driving the flow of goods. I think everyone has to have that slide.”

Armistead was joking. But while AI may be reshaping the future of energy production, someone still must get the power from the source to where it’s needed.

“I’m a little surprised so far that when we talk about responding to [AI], there hasn’t been enough discussion about the critical role that transmission can play in delivering resiliency and actual capacity for this new load that’s coming,” he said. “We need to think bigger and faster, just like we talked about ‘all-of-the above,’ as far as energy resources that can deliver and meet this amazing challenge.”

Armistead’s company, which he co-founded, is in the business of building HVDC transmission lines to deliver those resources. Pattern has a development pipeline of over 25 GW of renewable energy and transmission projects, but Armistead is most proud of the company’s SunZia Wind and Transmission Project — a 550-mile, 525-kV line capable of moving 3.5 GW of renewable energy between New Mexico and Arizona.

“Spoiler alert: We’re crushing it. … It’s on-time and on-budget,” he said. “I’ve always said, when you’re building an $11 billion project, you better do it well because everyone’s watching.”

Construction began on SunZia in 2023. Armistead said it will begin commercial operations in 2026.

“For the last 20 years, we really had almost flat to no load growth. It’s been super hard to have a discussion with either rate-based entities or ISOs about the absolute need for increased transmission,” he said. “That’s all changing, and that’s super exciting. There’s actually now a catalyst that basically says we need to expand our grid and we need to expand our energy resources. And the part that I think the transmission provides for this is it allows efficient utilization.”

Pattern’s other U.S. HVDC project is the Southern Spirit Transmission, a 320-mile, 525-kV line able to transmit 3 GW of renewable energy to Mississippi and the Southeastern Regional Transmission Planning region. Pattern filed an application with FERC more than a decade ago and has cleared regulatory hurdles in Texas. Construction is targeted to begin in 2028, but Pattern must still negotiate with landowners and gain approval in Mississippi. (See ERCOT, PUC Adamant: Southern Spirit Doesn’t Interconnect Texas.)

Armistead said the developers have found a way around a Louisiana law that would have hindered the use of expropriation to secure private land for the line’s right of way.

“It’s embarrassing to say both these deals have taken 12 years to get to this point where they’re ready to go, but that’s where we are,” Armistead said. “The bigger challenge is getting the utilities of the Southeast to see why this helps them serve their customers that are coming in now. What we’re seeing is the huge load growth within the Southeast has the utilities and those customers saying, ‘Please, get Southern Spirit online.’ So, we see a lot of traction to actually deliver this.”

The Need for Speed

Armistead and Pattern have support in high places, including FERC Commissioner Judy Chang. Speaking on a panel discussing how to meet the power surge (The U.S. Energy Information Administration projects 4.6% demand growth in 2025, the highest in decades.), Chang said there is a need for speed.

FERC Commissioner Judy Chang | © RTO Insider

“From a regulator’s perspective, we want to move fast,” she said. “We encourage the utilities and any folks that can serve the new demand to move fast at the same time to protect existing customers, or all customers, and to make sure that we do this with an efficiency in mind and reliability in mind, and with a long-term view of where this whole industry, where the whole demand growth is going.”

“What do we need?” said fellow panelist Amanda Peterson Corio, Google’s head of data center energy, clean energy and power. “We need everything. … We need more grids. We have to find a way to be fast. Speed is the name of the game.”

Ever the optimist, Chang said the “unprecedented growth” in demand is creating an opportunity for the industry.

“It’s not an option to serve or not to serve this customer, whether it’s AI or manufacturing. We built a sector to serve customers,” she said.

Chang said she looks at the situation through “the lens of opportunities” around how the entire supply chain of the power industry — from generation to distribution — can serve these customers.

“From a regulator’s perspective, we have to make sure … we have secure energy and reliable energy and efficient use of energy. We want to make sure there’s equity and fairness in the way the cost of the network, the cost of the resources, are being paid for,” she said.

Christie: CC Gas Units the Key

Stressing the need for dispatchable resources to maintain grid reliability, FERC Chair Mark Christie relied on a statement that he’s made before: “We have a rendezvous with reality.”

FERC Chair Mark Christie | © RTO Insider

“We’re simply not ready to run a grid where we don’t have dispatchable resources,” Christie said. “That’s just the reality. We need to deal with it. We need to act accordingly.”

“I would say that’s not just a rendezvous with reality; it’s a rendezvous with a stark reality,” CERAWeek Chair Daniel Yergin said.

Christie bolstered his case by referring to PJM’s performance during the week of Jan. 20, when the RTO set a new winter peak at just over 145 GW. He ticked off the resources that made up the fuel mix at the pre-dawn peak: natural gas at 44%, and nuclear and coal at 22% each. (See PJM Sets Record Winter Peak Load.)

“What those numbers tell us is not that wind and solar don’t ever have an important role to play at different times, but when PJM, the largest grid operator in America, hit their winter peak, the resources that were keeping the lights on and the heat pumps running so people didn’t freeze were 88% dispatchable,” he said.

Christie acknowledged the lengthy time it can take to build combined cycle gas units but said they are vital sources of baseload power.

“The [PJM] combined cycle gas units were running like a top,” he said. “It doesn’t take long to get the combined cycle gas as your baseload generating resource of choice. It’s going to have to be, and if it takes seven years [to build], it takes seven years. It’s not an argument not to proceed with building combined cycle gas.”

After all, “I think it was Churchill who said, nothing concentrates the mind like being told you’re going to be shot at dawn,” Christie said. (He was actually paraphrasing Samuel Johnson: “When a man knows he is to be hanged in a fortnight, it concentrates his mind wonderfully.”)

Nuclear Hub in Texas?

Texas is taking quick action on its drive to become a “global nuclear energy hub,” as posited by a 2024 report.

Bills have been filed in the Texas Legislature that would set up a Texas Advanced Nuclear Energy Authority and create a $2 billion fund to offset construction costs, provide grants for reactors and fund research into nuclear power development. (See Texas Now Wants to be No. 1 in Nuclear Power.)

But even that may not be quick enough.

During a panel on the state’s Texas-sized ambitions, Dale Klein, former Nuclear Regulatory Commission chair and now a mechanical engineering professor at the University of Texas at Austin, said Gov. Greg Abbott has been proactive and recently hosted a reception for an industry group.

“When he heard it might be 2030 before new nuclear [could] be in Texas, he said, ‘That’s too late,’” Klein said. “He wants it earlier, but the federal government licenses reactors.”

In the meantime, Texas A&M University has asked the NRC for an early site permit that would allow up to five 10- to 200-MW reactors to be built on its campus. The commission approved Abilene Christian University’s request in 2024 to build and test a 1-MW advanced nuclear reactor (ANR) that will be cooled by molten salt. Along the Gulf Coast, Dow Chemical and X-energy plan to develop four gas-cooled ANRs at a large chemical plant.

“We do everything big in Texas,” said former Texas Public Utility Commissioner Jimmy Glotfelty, who oversaw the report. “We don’t believe that the report is success. Success is steel in the ground, concrete in the ground, people working and building a plant. That is the end goal.”

Texas has two nuclear sites, Comanche Peak and the South Texas Project. Each generates about 2,500 MW of power and has room for two additional reactors.

“We want enough new nuclear megawatts in the state to help the economy continue to hum as it has been for a long time, but we also want to have a role in the production of all of the nuclear plants around the United States and around the world,” Glotfelty said.

“The momentum in the legislature is tremendous,” said Jeff Miller, vice president of business development at Bill Gates’ nuclear energy startup TerraPower. The company has partnered with the U.S. Department of Energy to build a reactor in Wyoming, using its sodium-cooled fast-reactor technology. “We are very bullish on Texas.”

Think Local Supply Chains

The U.S. Economic Policy Uncertainty Index may be one of the best measures of uncertainty for investors. With the Trump administration’s use of tariffs potentially starting a global trade war, the index has reached levels not seen since the COVID-19 pandemic and the global financial crisis in 2008.

Not to worry, said NextEra Energy CEO John Ketchum.

“We’ve been dealing with tariffs in our industry for a number of years. Tariffs are not a new thing for our industry,” Ketchum said, noting that the Biden administration kept some of the first Trump administration’s tariffs on solar panels. “Our supply chains have all adjusted to respond accordingly. But one thing that has changed is that our supply chains are largely American today.”

Ketchum said 90% of wind turbines being installed in the U.S. are made domestically, and the industry has been able to pivot to a nearly 100% domestic supply chain for batteries.

“When you turn this to solar, we’re buying more and more here in the U.S.,” he said. “We have been able to really diversify the supply chain. This is an industry that is an American industry. It’s a trillion-dollar American industry.”

“One thing which is important for us as big investors, since we build generation capacity on this side and the other side of the Atlantic, is the current geopolitically more tense environment,” said Markus Krebber, CEO of global renewables provider RWE. “It is very important to keep an eye on your supply chain, not only where the capacity is available, but also where it comes from, with risk around tariffs, trade wars and so on. Building a local supply chain is much easier and safer to build local than to rely on imports.”

“Anything that you import increases the amount of uncertainty that you have,” said GAF Energy President Martin DeBono, whose solar firm sells solar shingles.

Stacy Ettinger, a senior vice president with the Solar Energy Industries Association, said her organization has been working with its members to help them understand “what actually is happening.”

When it comes to tariffs, members are asking about the content of the measures, when they apply and what they apply to, so they can use the information when considering their own supply chain and procurement needs, Ettinger said.

March 17, 2025March 19, 2025

PJM Market Monitor Publishes Mixed Views in Annual Report

PJM’s markets provided reliable service in 2024, but tightening supply and demand are laying bare design flaws that have inhibited the competitiveness of the RTO’s markets, the Independent Market Monitor wrote in its 2024 State of the Market Report on March 13.

During a press briefing ahead of the publication of the report, Monitor Joe Bowring detailed several drivers behind the total price of wholesale power increasing 4.6% in 2024. Those include transmission service costs increasing from $10.7 billion in 2023 to $11.8 billion in 2024 and day-ahead energy costs going from $23.9 billion to $26.2 billion.

The real-time load-weighted average LMP was $33.74 in 2024, an 8.6% increase that Bowring largely attributed to PJM improperly applying the transmission constraint penalty factor (TCPF). He said that when lines are close to being overloaded, RTO staff will reduce their ratings by 5% in the security-constrained economic dispatch software, which leads to the TCPF being triggered more frequently and pushing prices to the $2,000/MWh cap. That practice, he said, accounted for $3.01 of the average LMP and 52.4% of the increase in 2024. Ancillary service redispatch costs contributed an additional 31.2%, and higher fuel and consumable costs accounted for 18.9%.

PJM spokesperson Jeff Shields said staff have not validated the Monitor’s analysis on the impact the TCPF had on prices, adding that in the past those estimates were not “true ‘but for’ analysis.” Since the Monitor’s recommendation also has included different line ratings, he said it’s not clear that constraints would no longer bind at the TCPF.

“PJM does not believe the implementation of the transmission constraint penalty factor is improper, but rather reflects actual operator actions to maintain transmission system reliability in prices,” Shields said.

The report found the energy market was overall competitive and effective, though increased ownership concentration in the local market led it to not be competitive, and the aggregate market was only partly so. In the more granular markets, the Monitor wrote that transmission constraints can create opportunities for market power. Market participant behavior was competitive, the Monitor wrote, with marginal units typically making offers close to their marginal costs — though some economic withholding was identified both under normal market conditions and at high demand.

The report said market sellers have been able to avoid being mitigated to their cost-based offers by submitting inflexible parameters or positive markups, an issue it said had LMPs. It also argued there are no mitigation protections in the aggregate market and that the application of market power rules in the local market need improvement. It recommended that PJM expeditiously implement its proposal to schedule any resources that fail the three-pivotal-supplier market power test on their cost-based offers. (See “Schedule Selection Formula Endorsed,” PJM MRC Briefs: July 24, 2024.)

Bowring noted another of the Monitor’s recommendations is being pursued by PJM in a joint package of proposals that would revise how uplift and deviation charges are assessed. It would prevent resources not following dispatch from receiving uplift payments and introduce a Tracking Ramp Limited Desired MW metric looking at how resources respond to instructions over time. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.)

Capacity Market

The Monitor’s outlook on the capacity market was dimmer. Overall, aggregate and local market structure was determined to be noncompetitive, as was participant behavior. The report faulted PJM’s rollout of marginal effective load-carrying capability for resource accreditation; resources categorically exempt from the requirement that market sellers offer into Base Residual Auctions withholding their capacity; gas generators being capped at their summer ratings; resources operating on reliability-must-run contracts not being required to offer into the market; and a maximum price set at the gross cost of new entry rather than 1.5 times net CONE.

The Monitor said the ELCC paradigm adds risk and volatility to the capacity market and recommended revising the model to use unit-specific data; match supply and demand in every hour of the year; and recognize actual unit performance and availability, rather than modeling performance simulated on data from a limited number of past performance assessment intervals. During the Critical Issue Fast Path process in 2023, the Monitor’s proposal to increase the granularity of the capacity market centered around evaluating resources’ ability to deliver capacity in every hour. Unit-specific accreditation remains a topic of discussion at the ELCC Senior Task Force. (See “Monitor Proposes Hourly Model with Annual Pricing,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

While the Monitor lauded FERC’s Feb. 20 approval of a PJM proposal to eliminate the categorical must-offer exemption for intermittent and storage resources, it faulted an element of the package allowing market sellers to request a unit-specific offer cap set at a unit’s Capacity Performance quantifiable risk value without any net revenue offset. In comments on the filing, it argued that not accounting for energy and ancillary service revenues in the offer cap would undermine the purpose of the capacity market: to provide the missing money resources require to be available as capacity (ER25-785).

While supply and demand are tightening, Bowring said capacity prices in the 2025/26 BRA were double what would reflect a competitive offer under the market conditions. He attributed much of that to the exclusion of intermittent, storage and RMR resources from the supply stack, as well as the capping of gas generators at their summer ratings. Given that the majority of reliability risk is now concentrated in the winter, when gas units may perform better, he argued that as much as 20% of gas capacity is not recognized. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

Bowring expressed support for an agreement PJM reached with Pennsylvania Gov. Josh Shapiro to set the maximum capacity clearing price at $325/MW-day, which would be roughly in line with the Monitor’s recommendation that the maximum price be defined as 1.5 times net CONE. The inclusion of a $175/MW-day price floor, however, could distort market outcomes, he said. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)

Bowring said market signals cannot incentivize new generation without changes to PJM’s interconnection planning processes. He said the Monitor strongly supports the RTO’s Reliability Resource Initiative, which FERC approved to allow 50 projects ranked on their capacity contribution and in-service dates to be added the Transition Cycle 2 (TC2). The initiative’s goal of expediting resources that can quickly bring large amounts of capacity could be expanded by creating a permanent process that fast tracks new projects that would mitigate defined reliability needs. While Bowring said that could include general resource adequacy, it could also mitigate the need for transmission expansion and RMR agreements when generators retire. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

The synchronized reserve market and its regional elements were determined to be noncompetitive because of ownership concentration in the Mid-Atlantic Dominion subzone. The market design was rated as flawed because of PJM unilaterally extending the operating reserve demand curve with a 30% adder in 2023. Deputy Monitor Catherine Tyler said the report includes new recommendations on reserves: Require that resources have automatic generator control (AGC) technology installed to be eligible to be synchronized and primary reserves, and eliminate the adder. During the March 6 Operating Committee meeting, PJM presented a plan to scale the adder back if reserve performance improves across three consecutive deployments, with the hope that changes to how it uses AGC during reserve deployments will improve performance. Tyler said that so long as not all reserve resources are required to have electronic communications installed, the impact of those changes will be muted. (See PJM OC Briefs: March 6, 2025.)

Bowring said that when the Monitor reached out to underperforming resources, it found that some were not getting the all-call phone call for as long as seven to eight minutes into a 10-minute deployment.

“The technology was outdated. … There’s been some improvements there, but not enough, and that requirement needs to be extended to everybody,” he said.

Bowring also argued that significant amounts of congestion revenue that is owed to consumers is being diverted through financial transmission rights auctions. If load held recognized property rights over congestion, some customers might be willing to sell variable congestion in return for a more predictable payment. But without the ability to set strike prices or receive all revenues from a sale, that capability does not currently exist. Total congestion in 2024 amounted to $1.75 billion, up 64.2% over the prior year, but 69.9% of that was paid to customers through auction revenue rights and the self-scheduled FTRs revenues offset.

“The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay. Customers have received $4.6 billion less in congestion revenues than load should have received, from the 2011/2012 planning period through the first seven months of the 2024/2025 planning period, as a result of flaws in the PJM FTR market design,” the Monitor said in the report’s announcement.

March 17, 2025

In Conversation with ISO-NE’s First Community Affairs Policy Adviser

As the Trump administration pulls federal support for environmental justice programs across the country, Ruben Flores-Marzan, ISO-NE’s first environmental and community affairs policy adviser, remains optimistic about the RTO’s efforts to engage with communities that historically have been absent from energy policy and planning discussions.

The RTO established the new position in response to a 2023 request from five of the six New England states for a position to help “provide an EJ and equity lens to ISO-NE’s management and staff; inform the development of ISO-NE initiatives, rules and operations; and engage EJ communities and stakeholders.” (See States Call for an Executive-level EJ Position at ISO-NE.)

The states wrote that the position should “serve as a critical bridge” between the RTO and the communities it serves, including the neighborhoods most affected by energy infrastructure. The request was supported by environmental advocacy groups, which have long called for a wider range of voices in ISO-NE’s decision-making processes.

ISO-NE hired Flores-Marzan, who has extensive professional experience as an urban planner, in July 2024. He has spent his first months on the job meeting with a wide range of community groups to listen to concerns; discuss ISO-NE’s role, abilities and limits; and take input on the RTO’s direction going forward.

“I’m talking to everyone, because the input of everyone is important to where we want to go,” Flores-Marzan told RTO Insider. “That’s a major part of what I’ve been doing: listening, reflecting, getting back in the engagement process with you to say, ‘Did I get that right?’”

He said his job is “essentially to reach out to different constituencies, learn from them, educate them about what the ISO does and does not do, and come up with different ways to continue engaging with them.”

Connecticut, Maine, Massachusetts, Rhode Island and Vermont have all passed laws intended to protect EJ communities. While the statutes and definitions vary, the laws generally aim to ensure that low-income communities, people of color and non-English speakers are provided equal opportunity to meaningfully participate in planning and policymaking processes.

EJ communities typically are located closer to energy infrastructure and face increased exposure to hazardous pollutants, including fine particulate matter and nitrogen oxides. A 2024 study by a coalition of advocacy groups found that about 80% of polluting generation facilities in Massachusetts are located within a mile of a state-designated EJ community. (See Report Shows Uneven Burdens of Power Infrastructure in Mass.)

Ruben Flores-Marzan, ISO-NE | ISO-NE

Low-income residents typically are also more vulnerable to the impacts of cost increases, although low-income discounts are available across all six New England states.

As an RTO, ISO-NE has significant constraints around what it can do to address EJ issues. It does not have jurisdiction over infrastructure siting and has indicated that it would need support from all six states to put a price on carbon or air pollution within its wholesale markets.

All six states also participate in the Regional Greenhouse Gas Initiative, which adds emissions compliance costs that ultimately affect prices within the markets.

Despite its constraints, the RTO is free to engage with the public on transmission planning, grid studies and market changes that could affect communities on the ground.

“What I can bring to the fold is that ability to embrace and incorporate people that haven’t been part of those discussions in the past,” Flores-Marzan said.

Flores-Marzan was born and raised in Puerto Rico and previously worked as a city planner in San Juan, working to procure wind and solar power to help the city decarbonize. In the mainland U.S., he has worked for the municipal governments of Providence, R.I.; Ware, Mass.; and East Windsor, Conn., where he helped site a 120-MW solar project.

He said his experience in Puerto Rico has helped him understand the importance of power system reliability, along with strong communication with the public about the issues that grid operators are facing.

“Energy drives everything; having that reliability is so important,” Flores-Marzan said.

Flores-Marzan is bilingual and said he hopes to boost the RTO’s outreach to Spanish speakers who face significant barriers to participating in ISO-NE’s public forums. While some state agencies across the region have implemented language access requirements for proceedings, ISO-NE public meetings are typically conducted only in English.

“A lot of Spanish speakers don’t know what the ISO is,” he said, adding that ISO-NE is translating some of its key documents into the language.

New England EJ advocates praised Flores-Marzan’s willingness to listen to community concerns and said the creation of the position is a step in the right direction for ISO-NE.

“I think the community affairs team has been working hard to listen to us and other community leaders … and to put in a best effort to answer our questions and understand our concerns,” said Mireille Bejjani, a community organizer who leads the Fix the Grid campaign. “I don’t think there was as much of that communication even just a few years ago.”

“We see this as a genuine commitment and a good first step,” said Susan Muller, senior energy analyst at the Union of Concerned Scientists. She said she is not aware of a comparable position that exists at any other RTO and expressed her hope that the role will serve as a model for other grid operators to follow. “They are rightly proud to be a leader.”

Moving forward, the advocates said they hope ISO-NE will increase its engagement with local communities, not just regionwide advocacy groups.

Bejjani said she hopes to see the “the buildout of a team at ISO-NE” focused on engaging EJ communities. At a higher level, Bejjani urged the RTO to open all the meetings of its Board of Directors to the public and put more resources into advertising its public meetings to increase participation.

“These are positive steps, but there’s more work to be done,” said Phelps Turner, a senior attorney at the Conservation Law Foundation. He added that it is “very important for the ISO to increasingly provide information that is more accessible that the everyday electricity consumer can understand and weigh in on.”

At the federal level, Trump administration has taken aim at EJ initiatives in its broader effort to remove support for diversity, equity, inclusion, and accessibility programs and protections. EPA Administrator Lee Zeldin has directed all regional EPA offices to eliminate their offices of environmental justice.

Eric Johnson, executive director of external affairs at ISO-NE, said he does not anticipate the change in federal policy affecting the new environmental and community affairs position or the RTO’s overall approach to community engagement.

“We created this position to be broader than environmental justice,” Johnson said, “and it’s really driven by the engagement we have with our states here in New England.

“The state’s priorities are not changing, and I don’t see our priority in that space changing. I think we’re just going to continue to build on this, and we’ll deal with whatever happens at the federal level.”