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April 18, 2025

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NYISO Cancels 2033 Reliability Need for NYC

NYISO ended the Operating Committee’s meeting April 17 with a surprise announcement: The ISO is no longer concerned about a violation of reliability criteria in New York City in 2033 and has canceled its search for a solution.

Zack Smith, senior vice president of system and resource planning, told the committee that updates to assumptions used in demand forecasting and demographic trends had eliminated the need over the 10-year horizon. Margins are still shrinking because of plant retirements, he said, but not enough to trigger the reliability need.

NYISO had officially made the declaration in November 2024 as part of its 2024 Reliability Needs Assessment. It triggered a process in which the ISO solicits solutions, including transmission-based from the local transmission owners, and generation and demand response from market participants. (See NYISO Publishes Final RNA Showing Reliability Need for NYC.)

Kevin Lang, a partner with Couch White who represents the city at the ISO, asked if the forecast included the completion of Empire Wind 1, an offshore wind project that just the day before was ordered to halt construction by the Trump administration. (See Feds Move to Halt Construction of Empire Wind 1.)

Smith affirmed that it was and that NYISO was confident that even a “significant delay” would not have changed the finding. And even if the project ultimately does not go forward, it would not significantly impact the ISO’s reliability margins, he said.

There will be a full discussion of the findings at the Electric System Planning Working Group’s next meeting, currently scheduled for May 6, Smith said.

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Northwest Faces Increased Fire Risk in July, BPA Says

The Northwest faces “above-normal, significant wildland fire potential” in July 2025, and the Bonneville Power Administration is taking steps to enhance mitigation efforts like public safety power shutoffs (PSPS) and improving communication. 

Citing a seasonal outlook by the National Interagency Fire Center, Kelly Miller, supervisory land surveyor at BPA, said the region is “looking pretty good until … July.” 

“In July, the significant wildland fire potential increases quickly, and we’re doing our best to prepare prior to that,” Miller said during an April 17 public update on BPA’s wildfire mitigation and PSPS processes. 

BPA is working on updates to the fourth iteration of its wildfire mitigation plan, slated for release in May 2026. However, the agency has continuously improved mitigation processes through lessons learned since the release of the first BPA wildfire plan in 2021, Miller said. 

The burn area in BPA’s service territory equaled 40.8% of the national burn area. More than 3.2 million acres burned by the end of FY24, an almost three-fold increase over the 10-year average, BPA stated in its 2024 annual report. (See BPA Hit FY24 Reliability Targets Despite Wildfires, Load Records.) 

BPA has identified several areas for improvement following extensive tests and training exercises, according to Miller. 

“We don’t always have ample advanced warning about impending weather,” Miller said. “Sometimes weather comes on very quickly, as you can imagine, and we have to make some very quick decisions. We also realize that there are many downstream load effects on the energy system that are hard to quantify, and we are working with our distribution customers to have a better understanding of that.” 

| National Interagency Fire Center

“Communication is a big piece of our public safety power shutoff events, and so we continue to make improvements to that, again, both internally and externally, how we can have more awareness for our customers,” Miller added. 

BPA issued PSPS four times in 2024, which led to five line de-energizations, according to the presentation. 

BPA closely collaborates with other agencies in its wildfire mitigation work. For example, the U.S. Department of Energy’s Pacific Northwest National Laboratory provides wildfire modeling to BPA. BPA also coordinates wildfire efforts with the U.S. Forest Service, among others. 

The agency also has explored different technological solutions, like weather sensors and smoke detection cameras “to see how we might be able to improve in the future,” Miller said. 

BPA follows industry standards and has created its own design and construction standards specific to its transmission assets, according to Miller. One notable standard implemented in 2024 includes placing fire-resistant wraps around transmission poles and installing more non-wood poles. 

Miller noted the new standards helped save multiple poles during a fire near Keller, Wash., in July 2024. 

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FERC OKs Final SPP Markets+ Compliance Filing

FERC said in a letter order April 17 that it has accepted SPP’s proposed compliance revisions to its Markets+ tariff that clarify five issues (ER24-1658). 

The commission accepted SPP’s tariff in January 2025 but asked the grid operator for further clarification in five areas: transmission availability, transmission opt-outs, Markets+ transmission contributor responsibilities, resource-aggregation mitigation and the seasonal hydroelectric offer curve’s mitigation methodology. 

FERC said the proposed revisions comply with its directives in the January order and accepted the modifications. 

SPP’s legal counsel told RTO Insider the compliance filing amounted to clarifying six sentences in its application. One of those was the same sentence written twice. 

SPP first filed its Markets+ tariff in March 2024. FERC responded in July with a deficiency letter outlining 16 issues to be addressed. The RTO’s response in January resulted in the commission’s approval. (See SPP Markets+ Tariff Wins FERC Approval.) 

Operations Review

FERC on March 31 granted in part and denied in part Basin Electric Power Cooperative’s request for transmission rate incentives for three 345-kV projects in North Dakota’s portion of the Bakken Formation (EL24-140). 

The commission granted Basin’s request for abandoned-plant and hypothetical capital structure incentive for two of the projects but denied the latter incentive for the third, the 33-mile Roundup-Kummer Ridge project.  

FERC found Basin’s request for a 50-50 debt-to-equity hypothetical capital structure incentive for the Roundup-Kummer Ridge project had not demonstrated the project had any remaining risks or challenges given that the in-service date was in the past. The line was energized in December 2024. 

All three projects were identified as part of the SPP 2021 Integrated Transmission Planning’s 10-year assessment. 

Commission Chair Mark Christie both concurred and dissented in part with a separate statement. He agreed with the capital structure incentive’s denial for the Roundup-Kummer Ridge project and dissented with the approval of the other two incentives. Christie said he dissented on the same reasoning as his prior dissents on the topic, where he has argued FERC should revisit granting such transmission incentives because they unfairly transfer wealth and risk. 

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End Users Push MISO for More Intensive Cost Overrun Evals on Tx Projects

MISO’s end users continue to call for a more stringent variance analysis, the review process MISO uses to investigate transmission projects that incur cost overruns or encounter other difficulties. 

At MISO’s April 15 cost allocation meeting, attorney Ken Stark, representing end-use customers, called for more “insight and transparency into” the variance analysis as well as a lower, 10% threshold on cost overruns to trigger the analysis. 

Stark said the Organization of MISO States (OMS), or the Independent Market Monitor, could play a role in evaluating project costs as part of the analysis. He said OMS and the IMM could sit in on MISO’s confidential initial inquiry stage, then offer advice to the RTO.  

Stark said MISO’s Board of Directors could use an expanded authority to review and issue a final determination on triggered projects, either accepting cost increases, recommending changes or making the call to suspend or cancel projects. 

The end-use sector said MISO also should consider incorporating a “feedback loop,” where after a variance analysis, MISO publishes a proposed mitigation plan open to stakeholders’ reactions over 30 days. Stark also said the RTO could file an annual report with FERC summarizing any variance analyses it performed.  

The end-use customer sector and the Coalition of MISO Transmission Customers have said MISO’s 25% cost overrun trigger to study regional projects is too high and should be lowered to about 10%. (See Stakeholders Want More from MISO on Tx Project Cost Containment.)  

MISO staff perform variance analyses on regionally cost-shared transmission projects that encounter schedule delays, permitting challenges or significant design changes or experience at least a 25% cost increase from original estimates. The studies also are triggered when developers find themselves unable to complete the project or if they default on the terms of their developer agreement. 

After completing the analysis, MISO can either let a project stand, develop a mitigation plan for it, cancel it or assign it to different developers if possible. A committee of MISO employees selected by executives makes calls on how to deal with such projects. 

Stark said SPP’s business practice manuals require projects to get a check-in at a 10% overage and undergo a review at 20%.  

“Given the sheer investment that’s happening, even a 10% overrun is significant from a cost standpoint,” Stark said. “We feel very strongly that the trigger should be lower given the lack of projects that go through the process.”  

Werner Roth, an economist with the Public Utility Commission of Texas, said he was uncomfortable with OMS conducting an additional review on cost increases in cases where projects haven’t yet been assigned a proceeding at a state commission.  

Sustainable FERC Project’s Natalie McIntire said she’s concerned a more sensitive study process would have MISO reviewing otherwise routine cost increases.  

“There are a variety of reasons for all kinds of cost increases for all products we use day to day,” she said. “We don’t want to have this sort of thing triggered for every project MISO approves.”  

Stark agreed that he didn’t want MISO to be “bogged down.”  

Other stakeholders said the IMM shouldn’t be prescribed transmission monitoring duties at a time when MISO is seeking to clarify with FERC whether the IMM should be involved in its transmission planning activities at all. (See MISO Intent on Answers as to IMM Role in Tx Planning.)  

Stark said another independent third party could evaluate projects. He said MISO could benefit from a set of “third party, disinterested eyes” to make sure MISO gets the best transmission construction outcomes.  

Some transmission owner representatives said they weren’t sure if dropping the threshold would accomplish much. American Transmission Co.’s Greg Levesque said it seems the RTO would spend more money for an independent review just to conclude the projects are necessary and should continue. 

ITC’s Cynthia Crane said the end-use customers haven’t presented a “compelling case” that MISO’s current setup is lacking. Crane said it doesn’t seem worth upending the roles and responsibilities of state regulators, the IMM and the MISO board.  

Stark said there should be more attention on containing costs for transmission projects.  

MISO maintains it doesn’t need to increase its threshold to evaluate projects. “We think we’re at the right spot,” Jeremiah Doner said.  

MISO has said it can indicate more clearly to stakeholders when it completes a variance analysis or develops an action plan. But it warned it can’t always share confidential project information. 

Staff plan to appear before stakeholders at the May cost allocation meeting with some minor edits to its variance analysis. The amendments would focus on MISO’s notification and communication commitments to stakeholders when it’s conducting a variance analysis. 

MISO is conducting one variance analysis now, investigating a 2.5-time jump in costs on one of its long-range transmission projects from its first portfolio. Incumbent developer Northern Indiana Public Service Co.’s 345-kV Morrison Ditch-Reynolds-Burr Oak-Leesburg-Hiple line in Illinois and Indiana now is expected to cost $675 million, up from an estimated $261 million. (See Cost Overruns on Project in 1st LRTP Prompt MISO Analysis.)  

“We will get to a determination this year,” Vice President of System Planning Aubrey Johnson said during March board week, though he didn’t have a specific date to expect MISO’s conclusion.  

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Louisiana PSC Scraps Statewide Energy Efficiency Program

The Louisiana Public Service Commission abruptly pulled the plug on its long-awaited, statewide energy efficiency program weeks after selecting a contractor to measure savings.

The commission voted 3-2 along party lines at an April 16 meeting to “cease working toward” its statewide energy efficiency program that was more than a decade in the making. A companion vote that would have directed commission staff to draft new energy efficiency rules for a public entity program failed, with Commissioner Jean-Paul Coussan flipping his vote for the second roll call due to what he called confusing language. Commissioners Foster Campbell and Davante Lewis voted against cutting the statewide program and the new rule directive.

The commission terminated its contracts with APTIM to administer the program and Tetra Tech to measure savings of the program. The decision came less than a month after commissioners selected Tetra Tech’s bid for measurement and verification of energy savings. (See Louisiana PSC Leaves Statewide Energy Efficiency Program As Is For Now.)

Chair Mike Francis, who introduced the motion to end the program through a supplemental agenda published fewer than 48 hours prior to the meeting, said an independently operated energy efficiency program appeared to be too confusing and too expensive.

The meeting took place at a golf resort in Many, La., a more than three-hour drive from the PSC offices.

Commissioner Lewis pointed out the commission was cutting the program before even receiving APTIM’s proposal or modeling. The contractor would have submitted details on its program design May 1.

The third-party, statewide program had been in the works at the PSC since 2010, when the commission retained a consulting firm to draft rules. The PSC finally authorized the program in April 2024.

Logan Burke, of consumer watchdog Alliance for Affordable Energy, said it’s illogical for the commission to cancel a statewide program when “residential utility bills are unaffordable for hundreds of thousands of people in our state.” Burke pointed out that Louisiana households on average use 46% more electricity than the average American household.

“Why would the commission consider ending the only program that residents and businesses have to manage their bills and keep the lights on?” she asked rhetorically at the meeting. “We are decades behind on addressing energy waste. And so, it doesn’t matter how low the rate is if we’re just throwing our money out of the cracks around our doors and windows.”

Burke said the “rational” thing to do is to finishing standing up the energy efficiency program.

“When will we acknowledge that what we’ve been doing isn’t working?” she said. “What is a more conservative value than eliminating waste?”

“Don’t vote to end the program that you barely got started,” Lake Charles resident James Hiatt urged. He said the vote seemed emblematic of a “backwoods, back deal, good ol’ boys” system. Hiatt added that utilities may have their “thumb on the scale” when it comes to designing programs, suggesting it’s not in their interest to help ratepayers lessen usage.

After the meeting, Burke called the vote “a betrayal of the process and the people.” Burke said a third-party model could have delivered six times the savings of utilities’ programs at about half the cost per kilowatt hour.

The alliance called on the public to contact their commissioners to reverse the vote.

Cleco Power counsel Mark Kleehammer requested the commission to continue allowing utility-led programs, saying they’re the most inexpensive means of implementing energy efficiency. Kleehammer estimated about 5% of customers participate in Cleco’s in-house energy efficiency program.

Larry Hand, vice president of regulatory and public affairs at Entergy Louisiana, estimated that anywhere from 5-8% of customers participate in the utility’s energy efficiency program. Entergy Louisiana uses APTIM to supervise the program.

Louisiana’s utility-led program is set to expire at the end of 2025. The current program allows utilities to recoup revenue when sales volume drops due to efficiency measures.

Commissioner Eric Skrmetta suggested it’s not fair that most customers are paying for the efficiency efforts of such a small slice of ratepayers.

Skrmetta also said the commission was merely canceling the third-party administration model, not eliminating an efficiency program altogether.

“We are going to have an energy efficiency program, but we’ve got to look at what we’re going to do,” he said.

Lewis said the utilities’ low participation rates reinforce the need for a standardized, statewide program that’s better publicized and understood.

At one point, Commissioner Campbell referred to the motion as “gobbledygook” because it wasn’t clear whether the vote also would terminate Louisiana’s current utility-led, quick-start program. Commissioners ultimately separated the failed directive into its own motion and amended it to make it clearer that utility-led programs would remain an option as the PSC worked toward a different program.

Campbell repeatedly asked for a monthlong stay on the vote to better understand what he was voting for.

Lewis pointedly asked Kleehammer and Hand whether they would recommend a public entities program model nationwide. The question led to a heated exchange over whether the directive motion as written would exclude utility-led efficiency programs from consideration under whichever new paradigm the commission adopts. Other commissioners cut off Lewis’ line of questioning.

“I understand the night is late, but this is what we get when we add an agenda item 48 hours before that’s extremely important. So, I mean if that’s the way we’re going to start doing business around here, it’s going to be a different game. Because I have issues … and I’m not going to be disrespected just because I have questions,” Lewis said of the five-and-a-half-hour meeting.

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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.

Oceantic 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 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 concern 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 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 2026/28 Wildfire Mitigation Plan with the California Office of Energy Infrastructure Safety in April.  

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 spread quickly 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 several 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 to 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 plans 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 now is eyeing a wider Gridscope deployment as part of its three-year plan. 

Gridscope sensors can detect vibrations, sounds and light and 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 also is 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 already has allocated $5.4 billion to implement its 2023/25 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 2026/28 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 about 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 also is 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 also have 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.”