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April 17, 2025

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Feds Move to Halt Construction of Empire Wind 1

The Trump administration is moving to halt offshore construction off the New York coast of the fully permitted Empire Wind 1 offshore wind farm.

Interior Secretary Doug Burgum posted April 16 on “X” that he had directed the Bureau of Ocean Energy Management to bring an immediate halt to all construction activities on the $7 billion project until it could undergo further review.

The move would appear to be the first stop-work order issued under a president who vowed to block offshore wind development during his campaign.

Hours after his inauguration Jan. 20, President Trump issued a memorandum halting new offshore wind leasing activity, directing a cessation of new permitting, and ordering a review of all permitting practices.

In his post, Burgum said Interior was following those directives and said there is a suggestion the Biden administration rushed through its approval of Empire Wind without sufficient analysis.

While BOEM did engage in a flurry of activity as Biden was a lame duck — culminating in the rapid approval of SouthCoast Wind’s construction and operations plan the last full weekday of Biden’s presidency — Empire Wind has been on track for much longer.

BOEM approved the construction and operation plan for Empire Wind in February 2024.

Developer Equinor has been through some major financial gyrations with the project — it canceled the New York offtake contracts for Empire Wind 1 and 2, renegotiated a much more expensive contract for Empire 1 and paused Empire 2.

But it did have its regulatory ducks in a row.

Despite the potentially existential threat Trump was holding over the entire offshore wind sector, Equinor took a final investment decision on Empire 1 in late 2024 and announced the close of $3 billion in financing at the start of 2025. The 810-MW facility had an expected 2027 commercial operation date.

Equinor had little to say April 16. A spokesperson told NetZero Insider via email:

“We have just received a notification from the Bureau of Ocean Energy Management regarding our Empire Wind 1 project, which has been in construction since 2024. We will engage directly with BOEM and the Department of Interior to understand the questions raised about the permits we have received from authorities. We will not comment about the potential consequences until we know more.”

The renewable energy community was aghast at the development and had more to say.

Ocean Network CEO Liz Burdock commented:

“Stopping work on the fully federally permitted Empire Wind 1 offshore project should send chills across all industries investing in and holding contracts with the United States Government. Preventing a permitted and financed energy project from moving forward sends a loud and clear message to all businesses — beyond those in the offshore wind industry — that their investment in the U.S. is not safe. We urge the Department of Interior to lift this order immediately to restore a predictable and equitable environment for the buildout of critical energy resources that help secure our energy future and independence.”

American Clean Power Association CEO Jason Grumet said:

“Halting construction of fully permitted energy projects is the literal opposite of an energy abundance agenda. With skyrocketing energy demand and increasing consumer prices, we need streamlined permitting for all domestic energy resources. Doubling back to reconsider permits after projects are under construction sends a chilling signal to all energy investment.”

Several New York organizations said jointly:

“By halting construction for Empire Wind I, President Trump is threatening Long Island’s energy independence and reliability, putting laborers out of work, undermining our efforts to combat coastal erosion that puts entire communities at risk, and causing dirty air and environmental degradation. … The Administration is breaking the law while prioritizing the interests of their fossil fuel donors at the expense of working families — a reckless, dangerous move that turns back the clock on progress.”

New York Gov. Kathy Hochul (D) cited the benefits Empire Wind already is yielding to the Empire State and said:

“As Governor, I will not allow this federal overreach to stand. I will fight this every step of the way to protect union jobs, affordable energy and New York’s economic future.”

Equinor secured the lease area in the New York Bight in March 2017 and has been working since then to develop it.

Work began onshore first, including New York City port construction that was launched with great fanfare using an army of more than a thousand workers at a cost approaching $900 million.

More recently, and with no fanfare at all, Equinor moved to begin laying rock that will stabilize turbine foundations.

That may be what prompted Burgum’s instructions to BOEM.

U.S. Rep. Chris Smith (R), a strong offshore wind opponent representing the New Jersey shore, wrote April 1 to Burgum about Equinor planning to start construction despite Trump’s memorandum and asking him to “do everything in your power to halt Equinor’s underhanded rush to begin piledriving and block construction until the critical assessment can be completed.”

In a subsequent news release, Smith said:

“It’s an alarming development that flies in the face of the comprehensive review of offshore wind ordered by President Trump in his January 20th executive order. The Norwegian company’s intention here is clear, it is trying to push through its questionable project based on the rubber-stamp approval received from the Biden Administration.”

In comments to Bloomberg on March 6, Burgum reiterated the administration’s criticisms of offshore wind but said that existing late-stage projects would be reviewed differently from the early stage projects, implying perhaps that they might have a better chance at proceeding through construction.

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NERC Standards Committee Approves IBR Posting

At their monthly meeting April 16, members of NERC’s Standards Committee agreed to post several reliability standards and associated materials aimed at satisfying a FERC directive on inverter-based resources for formal comment and balloting.

The four proposed IBR standards all arise from FERC’s Order 901, issued in 2023, which required NERC to develop standards to improve the reliability of IBRs, including solar, wind, fuel cell and battery storage facilities. (See FERC Orders Reliability Rules for Inverter-Based Resources.) NERC separated its work under the order into four milestones, the second of which concerns data sharing and model validation for all IBRs, whether or not they are registered with NERC. This milestone must be met by November.

Three of the standards were developed by the team for Project 2022-02 (Uniform modeling framework for IBRs):

    • MOD-032-2 — Data for power system modeling and analysis (found on page 52 of the meeting agenda)
    • IRO-010-6 — Reliability coordinator data specification and collection (page 94)
    • TOP-003-8 — Transmission operator and balancing authority data and information specification and collection (page 113)

Also approved for posting were MOD-033-3 (Steady-state and dynamic system model validation, found on page 21), a product of Project 2021-01 (System model validation with IBRs), and definitions for “model verification” and “model validation” developed by Project 2020-06 (Verifications of models and data for generators).

For all three projects, NERC requested that the SC grant waivers to authorize reducing the normal 45-day comment and ballot periods. In the case of the Project 2022-02 and Project 2021-01 standards, this meant a potential reduction to as few as 30 calendar days; for the Project 2020-06 definitions, the proposed timeline could be as few as 25 days. NERC Director of Standards Development Jamie Calderon explained that the comment periods needed to be shortened so the project teams have time to review comments ahead of a workshop planned for the summer.

Several members warned that setting the comment periods so short could put pressure on industry stakeholders, particularly because all three projects covered similar ground and would require comment from the same set of subject matter experts. Attendees worried the experts might not be able to give each project the time it needed.

To prevent overloading industry, Sean Bodkin of Dominion Energy suggested that NERC post the projects with staggered deadlines. After debate between committee members and NERC staff, the SC eventually agreed to modify the waivers for each posting to allow as few as 25 calendar days for comment on the Project 2020-06 definitions, 35 days for the Project 2021-01 standards and 30 days for the Project 2022-02 standards.

Members also expressed concerns that development on the three projects had proceeded slower than expected, creating the need to shorten commenting timelines. Michael Brytowski, standards specialist at Great River Energy, recalled that NERC held a workshop in January dedicated to the upcoming Milestone 3 IBR projects, and he wondered why the ERO had not been able to post them earlier.

“Back in January … we were looking at a decent amount of time to process this,” Brytowski said. “Now we’re up against the wall with these three projects posted simultaneously. What has happened in that 90 days [since the workshop] that has put us in this position?”

Calderon said that because the three projects were so closely related, the ERO needed “to make sure that [it] put in a robust amount of information,” which required close coordination with all three drafting teams.

“These are complicated projects, [and] coming out of the workshop this January, we did identify that there was a substantive amount of information that we had to consider,” Calderon said. “So all of that was part of what led to the delay here, and [why] it was brought forward in April as opposed to March.”

Updates to CIP, Cold Weather Standards

After dealing with the IBR issues, the SC attended to two more relatively minor standards actions.

First, members voted to approve errata changes to five Critical Infrastructure Protection standards that NERC’s Board of Trustees submitted to FERC in July 2024. (See NERC Sends Virtualization Standards to FERC.) The standards are currently awaiting approval from the commission.

At issue in the CIP standards was the term “electronic access control and monitoring system” (EACMS), which NERC Manager of Standards Development Alison Oswald explained should have been written with an “or” instead of “and” to match the definition that Chair Todd Bennett, of Associated Electric Cooperative Inc., noted has been in NERC’s Glossary of Terms “for quite some time now.”

The committee approved correcting the submitted standards, which will require a supplemental filing to FERC but not any further industry comment or ballot.

Finally, the SC voted to accept a standard authorization request for a project that will revise EOP-012-3 (Extreme cold weather preparedness and operations), which NERC recently submitted to FERC. This project will focus on tweaking the standard from a Canadian perspective “to reflect the geographical differences” between Canada and the U.S., and the varying regulatory frameworks between Canadian provinces.

The SC agreed to authorize posting of the SAR for a 30-day formal comment period and to authorize solicitation of members for the drafting team. Oswald explained that NERC “would specifically be soliciting for Canadian members” for the team.

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PG&E Wildfire Plan Relies on Proven Strategies, Newer Tech

A new three-year wildfire mitigation plan from Pacific Gas and Electric incorporates tried-and-true strategies such as undergrounding power lines, as well as some newer approaches, such as pole-mounted sensors. 

PG&E filed its 2026-2028 Wildfire Mitigation Plan with the California Office of Energy Infrastructure Safety this month.  

The plan takes aim at each step in a “chain reaction” that can lead to a catastrophic wildfire, PG&E said. An equipment failure creates a spark that ignites flammable material, followed by flames that can quickly spread over a wide area. 

“Our Wildfire Mitigation Plan employs multiple layers of protection we’re using to stop catastrophic wildfires in our hometowns,” PG&E Chief Operating Officer Sumeet Singh said in a statement. 

PG&E equipment has been blamed for a number of large California wildfires, including the deadly Camp Fire of 2018, the 2020 Zogg fire and the 2021 Dixie Fire. 

But PG&E said its wildfire mitigation efforts have been paying off: No major wildfires were sparked by the company’s equipment in 2023 and 2024.  

Ignition Prevention

PG&E’s priority is preventing ignitions in areas at high risk for wildfires, the company said in its plan.  

That means using operational measures such as public safety power shutoffs when fire danger is high. A PSPS is “a last-resort tool to prevent fires during extreme weather,” PG&E said in a release. 

Another tool is enhanced powerline safety settings (EPSS), which shut down power in a split second if a problem is detected, such as a tree branch falling onto a line. EPSS reduced CPUC-reportable ignitions by 72% in 2024 compared with 2018-2020 averages, the company reported. 

Because PSPS and EPSS create reliability issues for customers, PG&E said it’s working to minimize the impacts of their use. The average duration of outages on an EPSS-enabled circuit fell 17% in 2024 compared to the prior two-year average. 

Another step to reduce ignition risk is undergrounding of power lines. PG&E plans to bury an additional 1,077 miles of lines during the plan period. 

The plan also includes overhead system upgrades, such as installing covered conductor, strengthening poles and using wider crossarms. PG&E is planning overhead upgrades across 190 circuit miles each year of the plan, for a total of 570 miles. 

“Our key resilience mitigations — undergrounding and system hardening — will continue at a steady pace to provide more permanent risk reduction,” the company said in its plan. 

PG&E also plans to expand its remote grid program, in which the company removes overhead power lines and implements standalone energy systems for small clusters of homes and businesses at the end of long distribution lines that run through fire-prone areas. Eleven remote grids were in operation in 2024, and 20 more were under development. (See PG&E Building ‘Remote Grids’ in Fire-prone Areas.)  

Pole-mounted Sensors

In July 2024, when California was in a record-setting heat wave, a Gridscope sensor mounted on one of PG&E’s power poles alerted the company that something was wrong.  

A troubleshooter traveled to the location and found vegetation smoldering on an energized line, according to PG&E, which is now eyeing a wider Gridscope deployment as part of its three-year plan. 

Gridscope sensors can detect vibrations, sounds and light that could sense problems that could start a fire. PG&E started testing the Gridscope in 2023, expanding to more than 10,000 sensors across 900 circuit miles last year. 

PG&E is also looking at expanding its use of Early Fault Detection, a pole-mounted radio frequency monitoring technology. The sensors may find hard-to-detect issues such as damaged conductor strands or invasive vegetation. 

Electrical corporations in California such as PG&E are required to prepare and submit Wildfire Mitigation Plans (WMPs) to the Office of Energy Infrastructure Safety. The office, also known as Energy Safety, was established through state legislation following devastating wildfires in 2017 and 2018. Energy Safety reviews and approves the submitted plans. (See Calif. Agency Seeks to Transform Wildfire Safety Culture and Western Commissioners Ramp up Wildfire Efforts.)  

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GAO Study Flags Impacts of Offshore Wind Development

A U.S. Government Accountability Office study has concluded that offshore wind energy development carries both potentially positive and negative impacts and flags gaps in federal oversight of its development. 

But because the industry is only in its early stages in U.S. waters, the authors write, the extent of some of these impacts is unknown, and there is further uncertainty about the long-term or cumulative impacts of multiple wind farms. 

The independent nonpartisan watchdog agency performed the study at the request of 21 members of the House of Representatives and issued the results April 14. Its immediate impact is unclear, as President Donald Trump has halted the progress of federal regulatory reviews. 

The GAO cites several potential impacts from construction and operation of offshore wind turbines, including:

      • effects on marine life and ecosystems through acoustic disturbance and changes to marine habitats;
      • disruption of commercial fishing;
      • job creation and economic investment in nearby communities;
      • global climate and public health benefits;
      • interference with radar;
      • alteration of search-and-rescue methods; and
      • alteration of historic or cultural landscapes.

These are not new revelations. The lead federal preconstruction regulator of U.S. offshore wind, the Bureau of Ocean Energy Management, routinely flags these potential effects in the environmental impact statements it prepares as it reviews construction and operation plans submitted for proposed wind farms. 

BOEM often outlines those effects in imprecise terms, however, as the specific degree of positive or negative changes is unknown — particularly when considering the cumulative impact of multiple wind farms in a region where none currently exists. 

As of January, BOEM had leased 39 wind energy development areas on the Outer Continental Shelf. A small wind farm is completed and operating on one lease area, and larger facilities are under construction on four others. Construction had been authorized but not commenced on six lease areas, and permitting was in process on five others, before Trump in a Jan. 20 memorandum halted federal leasing and permitting for offshore wind. 

The GAO examined not just the effects of offshore wind but also the effectiveness of BOEM’s review process. The study notes that:

      • Tribal nations feel BOEM has not engaged with them as fully or effectively as they would like.
      • Fisheries stakeholders are concerned BOEM has not adequately considered or addressed their concerns, and the bureau has not shown how it will ensure wind power developers address impacts to the fishing industry.
      • BOEM requires lessees to submit community engagement plans but does not monitor or enforce compliance with those plans.
      • BOEM and the Bureau of Safety and Environmental Enforcement have not ensured they have resources in place for effective oversight — neither has a physical presence in the North Atlantic region, which is the epicenter of U.S. offshore wind development.

The office made five recommendations to address these points. The U.S. Department of the Interior, parent agency to BOEM and BSEE, concurred with the recommendations and agreed generally with the report’s findings. Its only objection was to the use of “Gulf of Mexico,” rather than “Gulf of America.” Interior also noted that its actions on offshore wind would be guided by Trump’s Jan. 20 memorandum. 

The GAO also recommended that Congress consider amending legislation to allow BOEM to better involve tribal organizations in the offshore wind leasing process. 

The agency carried out the study from August 2023 to April 2025. 

Two New Jersey Republicans who signed the request for the study — both firm critics of offshore wind development — continued their attacks, citing parts of the study. 

Rep. Chris Smith said the potential radar interference from the hulking wind turbines provides additional scientific justification for Trump’s pause. “Ocean wind energy development is an egregiously flawed and dangerous initiative and must be stopped,” he said in a statement. 

Rep. Jefferson Van Drew cited the potential effects the GAO flagged on defense, aviation, safety and ecology in a statement, saying: “The Biden administration ignored the warnings, ignored the experts and ignored the local communities who raised legitimate concerns. Now we have an independent, nonpartisan report that makes it clear: These risks are very real. President Trump did the right thing by putting these projects on hold, and it is time to put an end to them once and for all before more damage is done.” 

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Western Utilities Prep for Wildfire Season with New Initiatives, Tech

As the months get warmer, utilities in the West are gearing up for another wildfire season, equipped with new technology and lessons learned from recent fires in Los Angeles they hope can assist in mitigation work.

“The January 2025 windstorm and fires have driven SCE to further mature and evolve its wildfire mitigation efforts,” Southern California Edison spokesperson Jeff Monford told RTO Insider on April 15. “Based on these experiences, we have developed a forward-looking strategy that addresses both immediate and long-term wildfire risks.”

The L.A. wildfires erupted on Jan. 7 following a windstorm. The fires collectively destroyed thousands of homes and businesses in the Altadena, Malibu and Pacific Palisades communities, killing more than 20 people, according to Cal Fire. (See No Grid Impact from LA Fires, CAISO Says.)

SCE has stated its equipment may have been involved in the cause of the Eaton Fire, which burned more than 14,000 acres and engulfed parts of the Altadena community.

On April 11, SCE announced plans to underground more than 150 miles of transmission lines in Altadena and Malibu after the fires. The cost of the rebuild is estimated at $860 million to $925 million, according to a news release.

The effort comes after California Gov. Gavin Newsom suspended environmental laws to accelerate the undergrounding and hardening of utility equipment in communities ravaged by the Los Angeles wildfires. (See Newsom Issues Order to Speed Undergrounding of Lines in Los Angeles.)

SCE has already allocated $5.4 billion to implement its 2023-2025 Wildfire Mitigation Plan. Additionally, between 2018 and 2024, the utility installed more than 200 cameras with artificial intelligence capabilities, over 1,700 weather stations and approximately 6,400 circuit miles of covered conductor, while carrying out “more than two million tree trimmings and removals,” according to Monford.

SCE will share its 2026-2028 Wildfire Mitigation Plan in May, Monford added.

On March 24, Cal Fire completed an update to its fire hazard severity zone map for the first time since 2011. The updated map shows large swaths of Southern California falling under “very high fire hazard” zones.

Other utilities RTO Insider spoke with have ramped up their wildfire mitigation work in the face of increased risks.

For example, San Diego Gas & Electric launched its Wildfire and Climate Resilience Center in the fall of 2024.

“The center is essentially a focal point of SDG&E’s climate resilience strategy,” Alex Welling, communications manager at SDG&E, told RTO Insider in March, before Cal Fire issued the updated maps.

The center is a hub for research, development and implementation of wildfire mitigation tools built on AI and predictive modeling and information sharing with emergency responders, Welling explained.

SDG&E also uses data from the California Public Utilities Commission’s High Fire Threat District maps to power its modeling software. The software “helps prioritize wildfire mitigation projects by considering both wildfire risk and public safety power shutoff risk to determine the likelihood of either a wildfire or PSPS taking place, its subsequent impacts and then recommends proactive mitigation measures” Welling said.

Pacific Northwest

Information sharing has become increasingly important in the wake of the L.A. fires, Ryan Murphy, director of electric operations at Puget Sound Energy (PSE), told RTO Insider.

“Wildfire has changed the risk paradigm for utilities,” Murphy said. “We used to be a relatively low-risk industry. That is no longer the case — we now have become extremely high-risk because of wildfire.”

Because of changing weather conditions, PSE has stepped up its wildfire mitigation work and expanded its Wildfire Mitigation and Response Program, Murphy said.

For example, the utility uses AI to improve fuel models, consults with a third-party fire science expert and uses weather stations, cameras and insights from field crews to get a “much more granular and local level where to focus grid hardening and vegetation management work,” Murphy said.

“We have also added a meteorologist in the last year, giving us much greater visibility into the varied weather conditions across our service area and how those might impact operations,” he added.

Still, with recent trends of longer, hotter and drier summers, the wildfire threat in 2025 “has the potential to be very high,” Murphy said.

“If timely rains arrive across the region throughout spring, it will help delay the start of peak wildfire risk into late June or July, thereby shortening the overall risk duration,” according to Murphy. “However, if spring plays out to the warmer and drier side across Washington, the potential for earlier and active wildfire threat should be expected.”

In Oregon, investor-owned utilities must by June file wildfire mitigation plans for approval by the Oregon Public Utilities Commission. Utilities presented their plans in February.

Portland General Electric, Idaho Power and PacifiCorp, all of which serve customers in Oregon, have started undergrounding lines, building out networks of wildfire cameras and installing weather stations to gather wind speed data, among other efforts, according to their February presentations. (See Oregon Utilities Enter 2025 With Ambitious Wildfire Plans.)

There were 64,897 reported wildfires in 2024 that burned approximately 8.9 million acres nationwide, compared to 2.7 million acres in 2023. Oregon saw nearly 1.8 million acres burned due to wildfires, according to the National Interagency Coordination Center.

Oregon PUC spokesperson Kandi Young told RTO Insider in an email that this year “Oregon utilities are improving their outreach and communication to customers as the more extensive use of sensitive or enhanced safety settings reduces the risk of ignitions but also degrades the reliability experienced by customers with less advance warning than a [PSPS].”

“Communities are seeking more clarity about why outages occur and how long an outage is likely to last, whether due to these settings, a PSPS, or due to approaching wildfires and the need for turning off the power so fire suppression resources can operate,” Young added.

The PUC is also paying attention to the fire events in L.A., Young said.

“We continue to see extreme fire behavior and urban conflagrations under high wind conditions, regardless of the source of the ignition,” Young said. “Power is often turned off during these conditions, complicating the response. Public safety partners, entities that provide critical services such as communications, and community members need to be preparing for wildfire, even if they are not in a designated high fire risk zone.”

Federal Workforce Reductions

Layoffs among federal agencies initiated under the Trump administration have caused uncertainty within the power industry. The layoffs have also reached agencies like the National Oceanic and Atmospheric Administration that monitor wildfire activity and produce seasonal outlooks. (See BPA to Restore 89 ‘Probationary’ Staff, Agency Confirms.)

Young said workforce reductions among agencies “raise concerns about both off-season mitigation activities and fire-season readiness. We expect the utilities to incorporate any reduced federal prediction and response capabilities in their seasonal and operational risk assessments.”

Murphy with PSE said the utility monitors changes within the federal workforce and recognizes “the situation remains fluid. We consult with a number of agencies and third-party vendors for modeling in addition to federal agencies.”

SDG&E is less concerned, Welling said.

The utility’s monitoring systems, weather forecasting models and cameras “ensure we maintain the highest level of situational awareness,” according to Welling. “These capabilities allow us to independently monitor and predict wildfire behavior, ensuring our operations remain efficient and effective.”

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ISO-NE Cuts Winter, Summer Peak Load Forecasts for 2033

ISO-NE plans to cut its winter peak load projection for 2033 by 7.2% and its summer peak projection by 1.8%, Victoria Rojo, supervisor of load forecasting at ISO-NE, told the NEPOOL Reliability Committee (RC) on April 16. 

The cuts are driven largely by significant reductions to ISO-NE’s electrification projections for heating and transportation, which Rojo discussed at length with stakeholders at the RC in March. (See ISO-NE Scales Back Vehicle, Heating Electrification Forecasts.) 

The RTO has broadly overhauled the methodology behind its Capacity, Energy, Loads and Transmission (CELT) reports to incorporate more granular hourly demand forecasting and climate-adjusted weather data across 70 weather years. 

While ISO-NE still anticipates that demand growth will accelerate in the coming years, the results show a significant drop in expected demand relative to the RTO’s forecasts from the past few years. Compared to its 2024 forecast, ISO-NE has cut its 2033 summer peak projection by 474 MW and its 2033 winter projection by 1,937 MW. It also reduced its annual net energy projection for 2033 by 9.3%. 

Rojo also presented the RTO’s final draft forecast for behind-the-meter (BTM) solar. ISO-NE anticipates that BTM solar production will nearly double between 2025 and 2034, growing by about 570 GWh annually.  

ISO-NE plans to use its previous load forecasting methodology to calculate the installed capacity requirement for its 2026/27 and 2027/28 annual reconfiguration auctions. It will roll out the new methodology for the 2028/29 capacity commitment period in coordination with a proposed overhaul of its capacity market. (See ISO-NE Gives Updates on Prompt, Seasonal Capacity Market Changes.) 

Because the new methodology incorporates energy efficiency into the base forecast and eliminates the need to separately forecast energy efficiency, using the old methodology will prevent “unintended market outcomes that could arise from a midstream transition,” the RTO wrote in a memo published in late March. 

The forecast values are subject to change; ISO-NE plans to finalize and publish its CELT forecast May 1. 

Regional Energy Shortfall Threshold

Also at the RC, ISO-NE said it plans to focus its regional energy shortfall threshold (REST) on the most extreme 0.25% of modeled reliability scenarios, a risk level that equates to one event occurring every 90 winter seasons. 

The REST is intended to quantify New England’s “level of risk tolerance with respect to energy shortfall during extreme conditions in a season” and help “inform regional decision-making about managing potential energy shortfalls.” 

ISO-NE has proposed metrics related to shortfall duration and magnitude, which it will use to evaluate shortfall risks for the most extreme 21-day cases ISO-NE models. (See ISO-NE Details Regional Energy Shortfall Threshold Metrics.) Jinye Zhao said basing the REST threshold on the 0.25% tail of cases would enable the RTO to focus on high-impact cases that have a reasonable chance of occurring.  

The RTO plans to propose initial threshold values for these duration and magnitude metrics at the RC in June. 

Operating Procedure Changes

Also at the meeting, the RC voted to support changes to the RTO’s operating procedures for transmission outage scheduling and metering and telemetering criteria.  

The metering changes would allow an increased equipment temperature range “if data center-type HVAC redundancy is in place,” and add new automatic voltage regulator rules for composite units. 

The transmission outage scheduling changes would “clarify that Long-Term Transmission Outages may be approved without having to first be interim approved at the discretion of the ISO,” Anthony Stevens of ISO-NE said.  

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2 More Projects Fall out of TEF Loan Program

The troubled Texas Energy Fund has lost two more projects from its original list of applicants, raising questions about its ability to quickly add 10 GW of gas-fired dispatchable resources to the ERCOT grid.

Connie Corona, executive director of the Texas Public Utility Commission, said in identical filings April 15 that both applicants had “failed to meet due diligence requirements.” The orders are not subject to rehearing or appeal requests, she said (56896).

The loss of the two gas-fired projects from the list of applicants takes another 1,056 MW out of the TEF’s In-ERCOT portfolio. The 14 remaining applications total 7,284 MW of capacity and about $3.96 billion in requested loans, a PUC spokesperson said.

One of the projects belonged to EmberClear and Jupiter Island Capital, which proposed two 900-MW projects west of Houston. The other was proposed by Frontier Group of Companies for the Lone Star Industrial Park in East Texas, comprising two gas units with 162 MW of capacity. A 40-MW natural gas unit, commissioned in 1954 and once operated by Southwestern Public Service, sits in the park.

Four other companies have also withdrawn projects since 2025 began. (See Texas Loan Program Loses 2 More Gas Projects.)

The PUC has said staff intend to advance additional applications to due diligence review at a future open meeting. The commission next meets April 24.

Stoic Energy’s Doug Lewin said the TEF’s travails only emphasize the need for renewable energy and storage. He said that given ERCOT’s current projections of 44 GW of demand growth in the next four years (“As their midline,” he noted), Texas will still be 34 GW short even if the fund meets its 10-GW goal.

“It’s going to be even harder to meet rising demand without robust renewable and storage growth. There’s just no other resource else that can be developed that quickly,” he told RTO Insider.

More than 5,712 MW of capacity has been withdrawn or denied from the original submitted applications. More than 40% of the projects (4,965 of 12,249 MW) advanced to due diligence now have been withdrawn or denied.

The state legislature created the TEF in 2023 to add more dispatchable generation to the grid. Voters approved it later that year. Managed by the PUC, it is designed to provide grants and loans to finance construction, maintenance, modernization and operation of electric facilities in the state.

The fund comprises four programs: In-ERCOT Generation Loans, In-ERCOT Completion Bonus Grants, Outside-ERCOT Grants and the Texas Backup Power Package.

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NJ, Md. Officials Target PJM After Critical Report

A Washington, D.C.-based environmental group argues electricity prices will rise by 60% in the PJM region if the RTO does not reform its permitting system to allow more clean energy. 

The Evergreen Collaborative and consultant Synapse Energy Economics of Massachusetts released a report April 15 that predicts a 60% hike in residential bills will be reached by 2036 to 2040 if PJM continues on its current path. Residential rates could decline by 7% over the same period if PJM adopts interconnection reforms, such as accelerating the timeline by which new clean energy sources are approved, providing cheaper energy, the report claims. 

“With swift action to resolve the interconnection queue, it can reduce electricity prices while bringing on new resources to power new demand and enable economic growth,” the report says. Evergreen Collaborative, founded in 2020 by supporters and staffers of former Washington state Gov. Jay Inslee (D), aims to create an “all-out national mobilization to defeat the climate crisis and create millions of jobs in a clean energy economy.” 

The report drew vigorous support from Maryland and New Jersey officials. New Jersey ratepayers will experience a 20% hike in the average bill June 1 due to the basic services generation auction in February. 

State officials say that auction was shaped by record-high prices in the PJM capacity auction in July 2024. An imbalance of supply and demand was the result of several factors: a surge in expected demand due to AI data center developments; limited supply due to the RTO’s slow rate of approval for new clean energy sources; and the faster pace at which fossil fueled generators are closing. (See PJM Capacity Prices Spike 10-fold in 2025/26 Auction.) 

The sudden price hike and expected supply shortfall have triggered heated words from New Jersey officials, who say PJM failed to anticipate the demand increase. The RTO says the shift was so sudden it couldn’t have been anticipated. (See NJ Lawmakers Sound Energy Supply Alarm.) 

PJM, responding to the Evergreen report, said it has taken “multiple actions, working with stakeholders, to make as much generation capacity available to the grid as quickly as possible.” (See PJM Board Initiates Fast-track Process to Address Reliability.) 

“PJM has already established an expedited process, which recently cleared 18 GW to finalize agreements to interconnect to the grid,” the RTO said in a statement released by spokesperson Jeffrey Shields. “We have about 66 GW of active projects that we will complete in 2025 and 2026 as part of the reform transition period.” 

Leaving PJM

Representatives of New Jersey and Maryland, who took part in a press conference marking the release of the report, titled “Tackling the PJM Electricity Cost Crisis,” said the RTO needs to do a lot more, or see participating states look for alternative energy sources. 

“We’re at a fork in a road. We can’t afford for PJM to continue down the same path,” said Eric Miller, executive director of New Jersey Gov. Phil Murphy’s Office of Climate Action and the Green Economy. “My office is calling on PJM to clear the queue as quickly as possible, adopt reforms that make interconnection timelines more predictable and leverage next generation grid-enhancing technologies.” 

Paul G. Pinsky, director of the Maryland Energy Administration, called PJM “one of the largest obstacles” to the state’s efforts to reach 100% clean energy and “reduce soaring energy bills.” 

“I’m not here to say we’re going to pull out of PJM,” Pinsky said. “PJM is an RTO of importance. But it’s trailing a lot of the other organizations around the country in how quickly they can bring online new energy, and, in our belief, clean energy. So we want to bring as much pressure to bear.” 

New Jersey state Sen. Andrew Zwicker (D) said the reality laid out in the report is that “PJM is sitting on hundreds upon hundreds of renewable and affordable energy projects that, in the end, would lower the bill for New Jersey families and families across the PJM area.” 

Asked by a reporter if he considers the situation so bad that New Jersey and Maryland should consider leaving the RTO, Zwicker said “everything’s on the table right now.” 

“New Jersey doesn’t plan to be rash about this, and we have to do a very careful analysis of what the impact would be on New Jersey ratepayers,” he said. “But it has to be part of the discussion at this point, that’s for certain.”    

Rate Counsel Complaint

New Jersey officials say the high cost of power from PJM stemmed in part from “flawed” modeling by the RTO in the run-up to the July 2024 auction. There was a failure to properly include all the clean capacity expected to come online, they say, leading bidders to think there was less new capacity in the pipeline than in reality. 

The New Jersey Division of Rate Counsel and the Maryland Office of People’s Counsel on April 14 filed a complaint with FERC, arguing PJM’s auction produced “demonstrably unjust and unreasonable outcomes that the commission must now remedy.” 

The complaint alleged that “defective market rules either ignored or allowed market participants to withhold thousands of megawatts of existing capacity, while interconnection delays, a compressed auction forward period, and other entry barriers prevented the participation of new supply capable of disciplining incumbent market power.” 

The complaint demands that PJM redo the 2024 capacity auction, changing the rates for energy not yet delivered and fixing the defects in the process for the next auction. “What is at stake is an enormous and unlawful transfer of wealth from customers to owners of capacity resources: at least $4 [billion to $]5 billion in excess charges resulting from the subset of artificial supply constraints” in the auction, the complaint argues. 

System Reforms

Looking to the future, the Evergreen Collaborative report calculates the average residential household costs under the “status quo,” with the RTO operating as at present, and with the queue reforms suggested in the report implemented. The report does so for seven states and Washington, D.C. 

Under these scenarios, the average annual New Jersey residential bill would be $2,003 if the status quo continues, falling to $1,598 if the suggested reforms are adopted. The average Maryland bill would be $2,358 in the status quo and $1,813 with the reforms, according to the report. The average residential household cost across PJM would be just under $3,000 in the status quo over the period, and $1,062 less with reform implementation, the report says.  

The reforms suggested by Evergreen include:  

    • Requiring PJM to approve projects within a 150-day timeline. A Synapse Energy Economics consultant said this timeline is required by FERC under its Order 2023. But PJM is asking FERC for approval for a timeline of one to two years.
    • Implementing the first-ready, first-served cluster study approach on time for the regular-order queue.
    • Using realistic modeling assumptions for energy storage behavior rather than assuming energy storage will charge during peak periods and require associated transmission upgrades.
    • Studying grid enhancing technologies as part of transmission planning.
    • Making it easier for developers to use interconnection agreements held by existing power plants and continue to use them after the existing plants retire.

     
    PJM, noting that it began “significant interconnection process reform in July 2023,” said it since has “relieved the interconnection backlog by 60% and placed more than 6 GW of new generation into service.”

    PJM suggested the high auction bids confirmed its analysis that “the supply/demand balance has been tightening.” And the RTO added that it “will fully comply with Order 2023 but [has] also petitioned FERC to allow [it] to fit the order to PJM’s already approved and implemented rules.” 

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MISO Forming 4th Tx Planning Scenario Based on Supply Chain Barriers

MISO is on its way to installing a fourth, 20-year future to inform transmission planning in case supply chains remain unsteady.

During an April 14 teleconference to develop MISO’s first new planning future in six years, RTO staff said they are approximating annual build limitations on new capacity. They also said the Trump administration’s tariff decisions could introduce further instability that makes the fourth scenario more difficult to pin down.

MISO Senior Manager of Policy and Regulatory Planning RaeLynn Asah said the RTO sees “fairly impactful constraints” on all types of generation into the future.

The RTO is revising its trio of 20-year futures scenarios that it relies on to plan transmission. It has said it must incorporate aggressive load growth and create a fourth scenario specifically designed to study the footprint if fraught supply chains continue to impede new generation construction. (See MISO Aims for 4 New Tx Planning Futures in 9 Months and MISO Fields Divergent Calls for Stronger South Planning, IRA Reversal in Tx Futures.)

MISO has tentatively called the new scenario its “Supply Shift” future. It would contemplate continued “supply frictions” that limit the pace of capacity expansion. MISO envisions that load growth might have to be managed through keeping existing generation online and establishing more demand-side resources.

MISO created its current trio of futures in 2019 and last updated them in 2022. A decade ago, the grid operator used as many as 10 different futures to plan long-range transmission.

DL Oates, MISO executive director of markets and grid research, said the RTO is calculating annual capacity build limits by resource type for its fourth future through an assessment of U.S. manufacturing capability, labor constraints and tariff impacts. It multiplied the limits it found by its share of U.S. installed capacity.

“Preliminary results reveal some tension between member-submitted planned units and projected regional supply constraints,” Director of Economic and Policy Planning Christina Drake told stakeholders.

MISO acknowledged that President Donald Trump’s tariffs could add hurdles for generation and said it wants to adopt a wait-and-see approach on whether they have a material impact on generation expansion.

“What we would like to do is let this information settle,” Drake said.

Oates said MISO put its initial assessment together when the country-specific tariff rates were “volatile.”

“This is a shifting situation with these tariffs, so you’ll have to give us a little leeway to figure out what makes the most sense,” Oates said.

MISO does not plan to apply an age-based retirements assumption on its existing fleet for the supply-squeezed future. The RTO would assume some retirement delay announcements.

The Sustainable FERC Project’s Natalie McIntire said it did not seem realistic for MISO to forgo any age-based retirements. She asked it to maintain the same retirement assumptions it applies to the fleet in its three other futures.

“It doesn’t make sense to me to hardwire it into the model,” McIntire said.

Oates said that if members can’t build enough new generation, they may be forced to put off retirements.

“Our working hypothesis is that we’re not going to be able to balance generation and load,” Drake said. She added that MISO will “keep an eye on” whether age-based retirements might make sense in the scenario.

Even with retirement delays, MISO envisions the future would hold a minimum of 60% in emission reductions from 2005 levels, the same as its middle-of-the-road “Stated Policy” future. That would hold unless MISO finds that throttled build rates stand in the way of reducing greenhouse gases. The RTO’s most dynamic, “Higher Load Growth” future estimates a minimum 80% reduction from 2005 emissions levels.

MISO engineer Brad Decker said an enduring labor force pinch can “be a drag” on capacity expansion, especially to stand up labor-intensive solar farms.

Decker said MISO is contemplating tariffs on solar components anywhere from 17 to 37%, not the 145% the Trump administration has publicized.

“China doesn’t really export a lot of solar to the United States. They send materials through intermediate countries,” he explained, adding that MISO would factor in those intermediate countries’ reciprocal tariffs.

Despite wind component sourcing being largely U.S.-based, recent closures of plants that produce blades have shrunk manufacturing capability, Decker said, “posing a risk to scaling wind deployment until domestic production is expanded.”

Decker said small modular reactors likely won’t be a commercial option for at least 10 years.

“A lot of things have to happen between now and then to make these viable,” Decker said. For example, he said, the nuclear industry needs to stand up a market for high-assay low-enriched uranium to fuel the new type of plants. Decker said SMR projects and demonstrations have lurched in a “stop-and-start trajectory, marked by cost overruns and project cancellations due to undersubscribed offtake agreements.”

The Union of Concerned Scientists’ Sam Gomberg said he worried that MISO was being too “rosy” on SMR emergence within a decade and that its estimates would be biased if it relied on the “shiny FAQ sheets” from nuclear developers. He said the nuclear industry has a poor track record in meeting goals and announcements when bringing new capacity online.

Decker said there is a reluctance among gas turbine manufacturers to ramp up production because they remember overcommitting production in the early 2000s. Oates noted growing order backups for General Electric, Siemens, Mitsubishi and other suppliers because of surging, AI-driven demand for firm generation.

The supply crunch future also would consider a small-scale emergence of 12-hour, long-duration battery storage from advanced lithium-ion batteries and up to 100 hours of stored energy from iron-air batteries.

MISO said it won’t factor in other emerging technologies like extended-duration batteries that can last more than 100 hours, green hydrogen, combined-cycle plants with carbon capture and sequestration, and new geothermal technologies. Those likely are too far down the road to be considered in this round of futures, staff said.

The RTO is taking stakeholders’ reactions to its resource assumptions in its fourth future through April 28. It will refine the futures through the fall before using them in 2026 to plan more long-range transmission.

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SEEM Opponents Urge FERC for Clarification

The Sierra Club, Southern Alliance for Clean Energy and 11 other opponents of the Southeast Energy Exchange Market (SEEM) called on FERC to either clarify its March 14 order to update the market’s agreement or allow a rehearing of what they described as a novel legal theory put forward by the commission (ER21-1111-006, et al.).

The April 14 requests by the opponents, jointly filing as the ad hoc Public Interest Organizations (PIOs), arrived the same day as a response filed by SEEM members to FERC’s order. (See SEEM Members File Market Agreement Update.)

That response was an update to the SEEM agreement confirming that utilities may participate in the market via pseudo-ties, addressing a concern of the D.C. Circuit Court of Appeals about the agreement’s requirement that participants have a source or sink physically located within the market’s territory.

The PIOs’ filing concerns a different part of the March 14 order, which FERC issued following briefings from supporters and opponents of SEEM. In the order, FERC affirmed its earlier decision that SEEM’s open access transmission tariff is “consistent with or superior to the pro forma OATT,” justifying the assessment on the basis of the commission’s comparability standard, which FERC said “requires that comparable service be provided to comparable customers.”

This description of the comparability standard is the crux of the PIOs’ filing, which accused FERC of inventing a new definition by adding the term “comparable customers.” The PIOs noted that when FERC initially articulated the standard in 1994, it said that an OATT “should offer third parties access on the same or comparable basis, and under the same or comparable terms and conditions, as the transmission provider’s uses of its system.” At no point since then has the commission used the “comparable customers” language, the PIOs said.

“Nothing in the March 14 order indicates that the commission intended to modify its precedent regarding” the comparability standard or the alternative undue discrimination analysis of “whether utilities and their native load customers are similarly situated to third parties,” the PIOs continued.

Further, they argued that the same paragraph seems to switch between the two frameworks, finding that “entities located outside the SEEM footprint are not similarly situated to [those within], which justifies SEEM’s requirement that the former utilize a pseudo-tie to participate.” The discrepancy indicates that FERC’s order “did not intend to apply the comparability standard at all,” they said.

To address this “potential confusion,” the PIOs said FERC should clarify the March 14 order. They suggested doing so by removing the sentence that mentions the comparability standard, which would confirm that only the undue discrimination analysis should be applied.

If the commission did intend to apply the comparability standard, it should allow a limited rehearing of the relevant sentence and “modify the discussion to retract this unexplained and unjustified departure from its practice and precedent,” the PIOs argued. Such action is needed to address what they called FERC’s arbitrary and capricious redefinition of the standard.