Climate/Weather Risk Mitigation

U.S. electricity customers experienced an average of 11 hours of power outages in 2024, nearly twice as many as the annual average across the previous decade, according to a new report from the Energy Information Administration.

Hurricanes accounted for 80% of those lost hours, with most of last year’s outages resulting from major weather events like hurricanes Beryl, Helene and Milton, EIA said in the report released Monday.

“Interruptions attributed to major events averaged nearly nine hours in 2024, compared with an average of nearly four hours per year in 2014 through 2023,” EIA said. “Service interruptions that aren’t triggered by major events routinely average about two hours per year.”

Customers in South Carolina were significant outliers in terms of outage duration, the report said, experiencing an average of 53 hours of outages in 2024. Much of this was due to last September’s Hurricane Helene, which left 1.2 million customers in South Carolina without electricity.

The report appears to build on a growing body of evidence that extreme weather is taking a heavier toll on the electric power system in parts of the country. In October, JD Power released a report that found the average length of the longest outages are getting longer and concluded that disasters have become a “fact of life” for many utility customers. 

Helene, in particular, caused severe damage to utility systems in the U.S. Southeast and Mid-Atlantic.

Duke Energy said after the hurricane that transmission infrastructure in upstate South Carolina “was severely damaged and, in many cases, destroyed” and would need to be entirely rebuilt.

Three days after the hurricane struck, 900,000 Duke customers remained without power across North Carolina and South Carolina, the utility said. Following hurricanes Helene and Milton, Duke reported needing to replace around 16,000 transformers — more transformers than utilities generally require in an entire year, WoodMac Senior Analyst Ben Boucher said in February.

South Carolina, along with North Carolina and Florida, “dealt with strong winds and flooding from Hurricane Helene that affected transmission and distribution power lines as well as substations leading to prolonged power outages,” EIA said. The following month, Hurricane Milton “left 3.4 million customers in Florida without power,” it added. 

“In contrast, customers in states such as Arizona, South Dakota, North Dakota, and Massachusetts experienced, on average, less than two hours of service interruptions in 2024,” EIA said

While Hawaii averaged less than 10 hours of total outages throughout the year, the state saw more frequent interruptions — an average of 4.4 interruptions per customer, compared to the U.S. average of 1.5, “mainly due to adverse weather, volcanic activity, unexpected outages at oil-fired plants, and issues connecting new generating capacity,” EIA said.

Peak demand on the bulk power system will be 20 GW higher this winter than last, but total resources to meet the peak have only increased 9.4 GW, according to a report released Tuesday by the North American Electric Reliability Corp.

Despite the mismatch, all regions of the bulk power system should have sufficient resources for expected peak demand this winter, NERC said in its 2025-2026 Winter Reliability Assessment. However, several regions could face challenges in the event of extreme weather.

There have been 11 GW of batteries and 8 GW of demand response resources added to the bulk power system since last winter, NERC said. Solar, thermal and hydro have also seen small additions, but contributions from wind resources are 14 GW lower following capacity accounting changes in some markets. 

NERC officials described a mixed bag heading into the winter season.

"The bulk power system is entering another winter with pockets of elevated risk, and the drivers are becoming more structural than seasonal,” said John Moura, NERC’s director of reliability assessments and performance analysis. "We're seeing steady demand growth, faster than previous years, landing on a system that's still racing to build new resources, navigating supply chain constraints and integrating large amounts of variable, inverter-based generation.”

Aggregate peak demand across NERC’s footprint will be 20 GW, or 2.5%, higher than last winter. “Essentially, you have a doubling between the last several successive [winter reliability assessments],” said Mark Olson, NERC’s manager of reliability assessment.

Nearly all of NERC’s assessment areas “are reporting year-on-year demand growth with some forecasting increases near 10%,” the reliability watchdog said.

The U.S. West, Southeast and Mid-Atlantic — areas with significant data center development — have highest growth rates, NERC said. “Demand growth is contributing to lower reserve margins and signaling need for more resources,” according to a presentation on the report.

But some types of new resource additions are slow to come online. Just 3 GW of thermal or hydro generation was added since last winter. Solar nameplate capacity rose 11 GW since last winter, but is expected to contribute only about 1 GW towards meeting peak demand.  

Bringing resources online more quickly will require changes to policy and markets, according to the Electric Power Supply Association.

“We need permitting reform, predictable market rules, and policies that support private investment,” EPSA President and CEO Todd Snitchler said in a statement. The group represents competitive generators.

An increasingly complex resource mix “brings additional challenges for operators,” NERC said, particularly in extreme or extended cold weather.

In the Maritimes region, imports may be needed to meet peak demand, NERC said. New England could see gas shortages in extended extreme conditions. In areas of the Southeast, reserves may not be sufficient for high demand scenarios, or resource shortages may occur during early morning hours with high demand.

In the Electric Reliability Council of Texas footprint, “strong load growth is contributing to continued risk of supply shortfalls in extreme cold,” NERC said. In parts of the Northwest, resources may not be sufficient during wide-area cold weather that causes thermal plant outages and wind performance issues.

“Winter reliability is improving in some aspects, but the system is still being tested by conditions outside historical norms,” Moura said.

NERC’s assessment includes several recommendations: grid operators should review seasonal operating plans; generation owners should complete winter readiness and weatherization efforts; and balancing authorities should implement generator fuel surveys to monitor the adequacy of fuel supplies.

“Gas production and supplies going to generators strongly impacts how well the bulk power system can perform during winter conditions,” Olson said. “These two systems are inextricably linked.”

The United States has accused Southern California Edison of negligently failing to maintain power infrastructure in a pair of lawsuits seeking approximately $77 million for damages stemming from two deadly fires in the Los Angeles area since 2022.

The complaints, filed by the U.S. Attorney's Office for the Central District of California, allege that fires in Eaton Canyon and Riverside County triggered by SCE infrastructure burned tens of thousands of acres of National Forest, damaging popular trails and campgrounds and impacting water quality. The suits seek compensation for wildfire suppression costs and restoration of federal lands and property.

SCE already faces a myriad of lawsuits for this year's Eaton Fire, including suits from L.A. County and the cities of Sierra Madre and Pasadena also seeking compensation for damage to public properties. The official cause of that fire remains under investigation.

A pair of multimillion dollar lawsuits against SCE will recover taxpayer dollars and aim to initiate cultural change within the utility company, according to a DOJ statement issued Thursday.

“The lawsuits filed today allege a troubling pattern of negligence resulting in death, destruction, and tens of millions of federal taxpayer dollars spent to clean up one utility company’s mistakes,” Acting United States Attorney Bill Essayli said. “We hope that today’s filings are the first step in causing the beginnings of a culture change at Southern California Edison, one that will make it a responsible, conscientious company that helps – not harms – our community. Hardworking Californians should not pick up the tab for Edison’s negligence.”

SCE spokesperson Gabriela Ornelas described the Eaton Fire as “heartbreaking” and said the company would respond to the DOJ lawsuit through the appropriate legal channels. SCE also plans to launch a Wildfire Recovery Compensation Program this fall for victims of the Eaton Fire.

“We continue our work to reduce the likelihood of our equipment starting a wildfire,” she said. “SCE is committed to wildfire mitigation through grid hardening, situational awareness, and enhanced operational practices.”

Although the official cause of the 2025 Eaton fire remains under investigation by the L.A. County Fire Department, the complaints point to SCE’s own public statements and filings to state and federal regulators, including the U.S. Securities and Exchange Commission. 

“While SCE has not conclusively determined that its equipment caused the ignition of the Eaton Fire, concerning circumstantial evidence suggests that SCE’s transmission facilities in the preliminary area of origin could have been associated with the ignition of the fire,” the company said in a July 31 SEC filing, according to the lawsuit. “Absent additional evidence, SCE believes that its equipment could have been associated with the ignition of the Eaton Fire.”

SCE has warned investors that the company faces a “probable loss” in connection with the Eaton Fire.

In the case of the 2022 Fairview fire in Riverside County, the complaint cites an incident investigation report issued by the California Public Utility Commission that concluded SCE “violated several requirements” of public utility code for overhead electric line construction. 

The DOJ estimated the cost of fire suppression and rehabilitation stemming from the Eaton fire at more than $40 million, and the Fairview fire at about $37 million. 

The California Fire Victims Law Center, which has filed a class action lawsuit against SCE on behalf of residents who lost their homes in the Eaton Fire, heralded the DOJ lawsuit as evidence of the company's “unconscionable pattern of negligence.”

“The pattern has cost lives, destroyed homes, and left entire communities contaminated with toxic chemicals,” attorney Kiley Grombacher, co-founder of the California Fire Victims Law Center, said in a statement. “The California Fire Victims Law Center stands with every victim in demanding full accountability and just compensation for the destruction SCE has wrought upon our neighborhoods.”

The Public Utility Commission of Texas on Thursday approved a slimmed-down version of CenterPoint Energy’s system resiliency plan, ultimately approving about $2.7 billion for strategic hardening investments over the next three years.

Texas lawmakers in 2023 required electric utilities to submit resiliency plans to improve grid reliability. Oncor Electric’s $3 billion plan was the first to be approved, in November, and Entergy’s $137 million plan was approved in January.

CenterPoint’s original resiliency plan, filed in January, came in with a price tag of $5.75 billion. A June settlement cut the ask to $3.2 billion, and at the PUCT open meeting last week more was removed by commissioners.

Commissioner Courtney Hjaltman said she wanted to “remove a few measures that ... seem more about replacing materials that have come to the end of their useful life,” and make changes to how the cost of some vegetation management is recovered.

Hjaltman filed a memo on Wednesday discussing her proposed reductions to the plan. She raised concerns about the level of detail in CenterPoint’s vegetation management plan and how the costs to transition from a five-year to a three-year tree-trimming cycle would be recovered. She said the utility’s proposal looked more like an “augment” to its base vegetation management budget and that “the lack of verifiable details for the individual programs leaves us unable to sufficiently distinguish the resiliency investment.”

“To be clear, I am supportive of [the vegetation management projects] but consumers deserve transparency between increased base budgeting and the unique investments made through these resiliency plans,” Hjaltman said in her memo.

The day of the open meeting, CenterPoint filed a memo responding that “increasing the regulatory asset threshold as suggested would leave the Company unable to collect $30.67 million per year in incremental vegetation management expenses required to transition to a 3-year cycle” during the resiliency plan period.

At the meeting, Hjaltman said she was unconvinced.

“I still feel that CenterPoint is using base rates to cover the cost of implementing the resiliency plan, and to me that blurs the lines of what should already be done and what is the purpose of the resiliency plan, which is the ‘above and beyond,’” she said.

The PUCT voted 3-0 to approve the plan, in line with Hjaltman’s proposed changes. It includes more than two dozen resiliency projects for the 2026-2028 period, the utility said.

”These programs will benefit our customers and communities by avoiding more than 755 million outage minutes and increasing our system's ability to take a punch from extreme weather events and get back up more quickly after storms,” CenterPoint said in an emailed statement. “We look forward to beginning work this fall.”

The United States has already experienced more wildfires this year than it has over the same period in any other year this decade, according to the National Interagency Fire Center.

With the risk of fire expected to grow due to climate change and other factors, utilities have increasingly turned to technology to help them keep up. And those efforts could get a boost following President Donald Trump’s June 12 executive order calling on federal agencies to deploy technology to address “a slow and inadequate response to wildfires.”

The order directed agencies to create a roadmap for using “artificial intelligence, data sharing, innovative modeling and mapping capabilities, and technology to identify wildland fire ignitions and weather forecasts to inform response and evacuation.” It also told federal authorities to declassify historical satellite datasets that could be used to improve wildfire prediction, and called for strengthening coordination among agencies and improving wildland and vegetation management.

Additionally, the order laid out a vision for consolidating federal wildfire prevention and suppression efforts that are currently spread across agencies. The White House’s proposed 2026 budget blueprint would create a new, unified federal wildland fire service under the Department of Interior.

So far, Trump’s directive has drawn a mixed response from wildfire experts. While some said it could empower local governments and save utilities money, others said the order’s impact will be limited.

“I think some people read into the order more than is there, and some people read less,” said Chet Wade, a spokesperson for the Partners in Wildfire Prevention coalition. “I don't know exactly what will come of it, but getting technology into the right hands could be very helpful.”

Fire prevention goes high tech

Since the 2018 Camp Fire that bankrupted PG&E and set a nationwide precedent for suing utilities that trigger large fires, energy companies around the U.S. have invested billions of dollars in grid hardening and undergrounding power lines. Public safety power shutoffs are now routine during high-risk weather for many utilities, especially in the West. Many utilities have invested in new monitoring equipment and artificial intelligence to better detect and prevent fires.

Abhishek Singh, CEO and co-founder of AiDash, which builds software for monitoring wildfire risk, said technology has allowed utilities to make significant strides in areas like tree management, where AI paired with satellite imagery can help them identify high-risk areas. Trump’s executive order, he said, could make this technology even cheaper by releasing satellite imagery that companies like AiDash can use to train their AI models.

That, in turn, could make AI monitoring more accessible to local governments and firefighting agencies with limited budgets, Singh said. He believes more government monitoring will allow utilities to relax their own surveillance efforts, freeing resources for other concerns like hardening grid infrastructure.

Former FERC commissioner and chairman Neil Chatterjee, who has accepted a role as an advisor to AiDash, shares Singh’s views on the potential of technology to mitigate wildfire risk. The executive order, he said, could “modernize wildfire prevention and bring federal policy in line with the technology that is available.”

Technology advances as risk grows

While Wade said he hoped the federal government improves coordination between agencies and increases access to public lands for vegetation management, he expressed skepticism the executive order would have much impact.

For one, he said, it calls for giving more authority to local governments, but it doesn’t say anything about ensuring those communities have the resources they need to address wildfires.

The president’s budget blueprint calls for funding the new federal fire service with $3.7 billion, plus $2.8 billion for a wildfire suppression reserve fund. But it would eliminate funding from other agencies and programs that have historically played a role in addressing wildfires, including grants to support local firefighting efforts and the management of state and privately-owned forests.

“While the budget provides robust support for Federal wildland fire management activities alongside States and local partners, these partners should be encouraged to fund their own community preparedness and risk mitigation activities,” the proposed budget states. 

U.S. Forest Service Chief Tom Schultz confirmed in testimony before lawmakers on the Senate Energy and Natural Resources Committee last week that the administration still has not released some firefighting funds to states for the current fiscal year, saying, “We’re still in discussion.” 

Trump has walked back his earlier calls to eliminate the Federal Emergency Management Agency in recent days. But the tax and spending bill he signed into law July 4 cuts funding for research and forecasting of climate-related threats. Partners in Wildfire Prevention said it was too early to determine what the cuts mean for wildfire mitigation.

Andrew Dressel, a power industry consultant and vice president at Charles River Associates, cautioned that even as utilities prepare and technology advances, the risk of fire continues to increase as well.

While the order focuses on prescribed burns and wildland management, he said recent urban fires like those that devastated Los Angeles have called attention to the need to harden homes and yards against fire. They have also raised concerns about the role of idle power lines in starting fires. But moving, upgrading or removing power lines is expensive and time-consuming, and utilities are facing these costs at a time of unprecedented projected load growth.

“An executive order can only do so much,” Dressel said. “We need legislation, federal legislation or state legislation or both, to really move the needle on these things.”

 

When we talk about physical climate risk in the utility sector, we almost exclusively picture the catastrophe as a category 5 hurricane snapping transmission towers, or an unprecedented freeze shutting down the grid. These events are tragic, visible and mobilize immediate regulatory support.

But while we prepare for the 1-in-100-year event, we’re bleeding cash on the 1-in-5-year reality.

Most utilities are currently mispricing physical risk because existing reliability models often treat weather as a static baseline. They assume that the "average" day in 2030 will look like the average day in 2000. It won't.

As heat and precipitation baselines shift, they create a "silent derating" of grid assets — eroding efficiency, increasing fault rates and driving up operating expenditures long before a named storm ever makes landfall.

We recently analyzed an approximately $1.5 billion grid portfolio in Europe comprised of 37,000 miles of overhead lines and 13 critical substations to quantify this financial impact. The data was stark: Under a "business as usual" climate scenario (RCP 8.5), climate hazards threaten to erode 30.57% of the portfolio’s gross value by 2050.

This value destruction doesn't happen all at once. It happens incrementally, accumulating as average annual loss, or AAL. Unlike a singular major event, AAL captures the steady financial drip of efficiency losses and minor outage repairs that fly under the radar until they impact the bottom line.

All emissions scenarios lead to higher costs

One of the most critical insights for utility planners is the divergence (or lack thereof) between climate scenarios. Often, utilities delay resilience investments hoping that global mitigation efforts will reduce the need for local hardening. Our analysis suggests this is a dangerous gamble.

In the analyzed portfolio, while the "business as usual" path leads to a ~30% value erosion, even the "climate protection" scenario (RCP 2.6) still results in a 21.54% value risk by 2050. The gap between these scenarios indicates the financial benefit of climate protection, but it also proves that significant physical risk is already baked into the system.

Whether we follow a high-emissions or low-emissions trajectory, the hazards arrive, differing primarily in their steepness and timing. For instance, operational expenditure losses under “business as usual” climb noticeably faster after the 2040s, mirroring increased interruptions and emergency maintenance. However, under both scenarios, the trajectory is upward. Waiting for global policy to solve local grid reliability is not a viable strategy; the "climate tax" is coming regardless of the emissions pathway.

The silent derating of the grid

The most dangerous risks are the ones current models don’t flag. Standard asset management often focuses on age-related degradation, but climate stress accelerates this aging.

Our analysis found that unadapted overhead lines were uniquely vulnerable. Heavy precipitation acts as a key trigger for outages, with chronic stresses like wind and heat modulating baseline fault rates across seasons. In our portfolio analysis, gross revenue losses driven by these hazards were projected to climb over 12,000% by 2050 compared to today’s baseline under a high-emissions scenario.

This isn't so much a storm problem as it is a conditions problem. For this operator, damp, heavy air increases vegetation contact and conductor clashes. While overhead lines drive the majority of operational loss through fault frequency and restoration time, substations bear the concentrated risk of catastrophic damage from flood inundation. If a utility’s rate case assumes historical fault averages rather than projected AAL, it is under-collecting on the true cost of future reliability. 

The ROI of resilience

The good news is that unlike vague "climate mitigation" goals, adaptation has a calculated, defensible return on investment. When we move from generic "exposure heatmaps" to calculating the reductions in AAL, we can identify exactly when a resilience measure pays for itself.

However, utilities cannot simply harden everything. The capital constraints require a prioritization framework. In our study, we mapped adaptation measures on a scatter plot comparing implementation cost against technical benefit (reduction of faults). This revealed two distinct categories of investment that utilities should prioritize:

The "no regret" move: hardening overhead lines

For medium-voltage (15 kV) lines exposed to heavy precipitation, the fix is often converting bare conductors to semi-insulated compact conductors (AAC 95 mm²) or aerial bundled cables (ABC). This is not a massive engineering overhaul; it’s a targeted upgrade. In our analysis, specific "no regret" feeder segments showed a financial breakeven between year three and year five. The payback comes not from surviving a hurricane, but from the daily reduction in transient faults and the avoided penalties of energy not supplied.

The defensive asset: flood-proofing substations

Substations are capital-intensive nodes where risk is concentrated. Our modeling of specific substations exposed to 1-1.6 foot flood depths showed that relatively simple interventions such as raising foundations or installing deployable barriers cost between about $180,000 to $1.4 million (€150,000 to €1.2 million). Crucially, these investments showed a breakeven point around year six. By quantifying the AAL avoided by preventing these floods, we prove that these measures turn physical protection into a defensive financial asset.

Data-driven defense

The era of treating climate adaptation as a "nice-to-have" or a "storm surcharge" is ending. Regulators and investors are beginning to demand granular proof that capital plans are robust against future weather baselines.

For utilities, the path forward is to stop viewing resilience as a cost center. By quantifying the AAL on their portfolios, specifically the operational expenditure drag of silent derating and the capital expenditure risk of flash floods, they can build a rate case that is financially defensive and operationally prudent.

We have the technology to calculate the payback period of a thicker cable or a higher flood wall. It's time we started using it to justify a stronger, smarter grid.

As fires raged across the Los Angeles region in January, regional electric utility Southern California Edison cut power to more than 360,000 customers. Some remained without service for weeks.

The event was one of dozens of public safety power shutoffs tracked by California’s public utility regulator over the past year. Power lines are more prone to failure in hot, windy weather, sometimes sparking fires that quickly burn out of control, the California Public Utilities Commission says. Electric companies deenergize them to reduce the risk of devastating events like 2018’s Camp Fire, which killed 85 people and pushed Northern California utility Pacific Gas and Electric into bankruptcy. 

“Any time you get hot weather and winds, you’re going to see PSPS events,” said Marc Starkey, a California-based account executive in Schneider Electric’s sustainability business. Some vulnerable areas see up to 10 PSPS events per year, he said. 

In response, municipal governments and school districts across California are setting up microgrids that enable them to maintain critical infrastructure and services using locally produced power. Ojai Unified School District, for example, tapped Schneider to deploy a microgrid powered primarily by solar panels and batteries. The project will provide backup power for a school facility that is a designated evacuation site and served as a Red Cross shelter after a 2017 wildfire.

But as Republicans in Congress push through a budget reconciliation bill that could remove key federal backing for clean energy resources, local resilience efforts, like those from Ojai’s school district, face an uncertain and potentially more expensive future, Starkey said. 

Financial threats and opportunities for microgrid customers

As passed by the House, the reconciliation bill would effectively eliminate clean energy tax credits worth 30% or more of qualified investments in projects that begin construction 60 days after it’s signed into law. President Trump supports the bill and has said he wants Congress to pass it by July 4. Though some lawmakers are skeptical about hitting that deadline, Schneider isn’t taking any chances, Starkey said.

“Our strategy is … you have to have your project in construction in September to qualify for the investment tax credit,” Starkey said. “As we’re getting customers under contract, if we can procure solar panels well in advance of the design being finalized and in construction, we do that.”

For now, tax-exempt entities like city governments and school districts can tap those federal tax credits using the “direct pay” framework created by the Inflation Reduction Act of 2022.

The GOP budget would also rescind billions in clean energy funding authorized by the Inflation Reduction Act, which provides loan guarantees and grants to microgrid projects in California and elsewhere across the U.S.. 

The good news for municipalities, school districts and other facility operators interested in microgrids is that they can often turn to state or local grants, utility rebates and other low-cost financing. 

That’s on top of the potentially significant utility bill savings from powering regular operations with on-site solar and batteries, which Schneider can then leverage in longer-term structured performance contracts, Starkey said. 

Also known as energy savings performance contracts and often involving energy-efficient upgrades like LED lighting, new HVAC and digital building controls, those contract arrangements help mitigate the upfront costs of major energy-related upgrades and insulate customers from future utility rate hikes, the U.S. Department of Energy says. 

ESPC customers generally own their energy systems, allowing them to depreciate the investment over time. Energy-as-a-service agreements, or EaaS, offer a turnkey alternative for customers not interested in financing and maintaining the infrastructure themselves. 

Most Schneider customers prefer direct ownership, which is fine with the company — but it’s also willing to work with those that just want to buy power generated on-site, Starkey said. 

Schneider offers two EaaS solutions, AlphaStruxure and GreenStruxure, in partnership with private equity firms Carlyle Group and Blackstone. The average AlphaStruxure customer requires more than 5 megawatts of power, the equivalent of 5,000 typical homes, while GreenStruxure is a zero-carbon solution for commercial and industrial customers that spend at least $500,000 per year on electricity, Schneider says.

Keeping the lights on when it really matters

Beyond direct financial savings, microgrids have indirect benefits like fewer operational disruptions, Starkey said. Some PSPS events anticipate actual wildfire emergencies, as in Los Angeles this winter, but many do not. Without reliable, backup power, schools and municipal service providers may need to close or curtail activities during longer shutdowns.

“[Our customers] are saying, ‘Hey, we want to keep our students in school,’” Starkey said.

Because states fund schools based on average daily attendance, extended or repeated closures may result in significantly less revenue over the course of a school year, Starkey said. And in an actual emergency — or even abnormally hot weather, when schools and other municipal facilities may double as cooling centers — backup power is critical to ensure vulnerable residents have a safe place to go, he said.

Most microgrids combine renewable energy sources like solar panels with fossil-fuel generators and batteries for backup power, Schneider says. But Starkey said it’s easy enough to tailor the mix of power sources to the needs of a particular site or user, including those with strict emissions-reduction goals.

“We definitely want to meet the vision of the customer in terms of their sustainability and climate action goals,” he said. Schneider’s solar-powered parking shelters and two-way “vehicle-to-grid” ports support the growing number of California customers that need to run electric fleet vehicles — or use them as mobile backup batteries — when the grid is down.

On the other hand, some customers already have diesel generators and want to be able to plug them into new microgrids. Schneider’s microgrid at the Ojai Unified School District offers this flexibility, Starkey said. Solar-and-battery combos can provide reliable backup power for relatively long periods in sunny California, but customers with mission-critical needs generally want to have generators on hand for added resilience in multiday outages, he said.

Regardless of their sustainability or technology preferences, Starkey tells facility operators to spend time on the front end figuring out which systems and functions truly need to be backed up. A municipal customer might go into a project expecting to back up its entire civic center, then consult with someone like Starkey and settle on a smaller system to serve just critical functions like IT and public works, he said.

Realistic outage duration and frequency projections are important too, Starkey said. In areas not prone to long PSPS events or general grid unreliability, that exercise keeps costs in check without compromising performance.

“The last thing we want to do is spend a bunch of money oversizing a solar and battery system to last for days when really you need [one] a fraction of that size,” Starkey said.

When Michael Wara, a senior research scholar at the Stanford Woods Institute for the Environment, helped set up the California Wildfire Fund in 2019, he suggested the fund aim to save $40 billion in order to have enough to pay off claims against Southern California utilities that triggered catastrophic wildfires. He also believed, at the time, that $40 billion might be too high.

“I was being conservative about how fast utilities could improve” their wildfire mitigation, Wara said in an interview this month.

While utilities have ramped up their wildfire mitigation and grid hardening spending to tens of billions per year, significantly reducing the risk of ignition, the overall risk of wildfire has outstripped their efforts, Wara said. Fires across the nation and in Southern California in particular continue to grow in size and intensity as a result of rising temperatures and increasingly severe drought conditions. And with the latest round of fires in the Los Angeles area, investors in the state's largest utilities have begun to worry that the growing scale of utilities' wildfire liabilities may have already outstripped the fund's $21 billion target capacity.

Those investors are not wrong to be worried, Wara said. The Eaton Fire, if it was in fact connected to Southern California Edison's equipment, could deplete the fund's current reserves, leaving little in the bank for the next catastrophic fire. California utilities and their investors have already called on the state legislature to expand the fund, but Wara and other experts believe that at this point, any such expansion would just be a stop-gap in the absence of a broader societal solution.

“Competing against [the fund's growth] is the fact that the wildfire situation in California appears to be getting worse due to climate change. You can run faster, but the treadmill is speeding up so that you may still fall off the back,” Wara said, later adding that he recently told the state wildfire commission that “we cannot insure our way out of this problem.”

The ‘go-forward' problem

The cause and cost of the Eaton Fire remain under investigation, and so it remains to be seen whether Southern California Edison will need to tap the California Wildfire Fund to cover lost property claims — or how much they will need. But some back-of-the envelope math illustrates why investors have raised the issue during recent conference calls with all three of southern California's largest investor-owned utilities.

The fund currently has more than $12 billion in liquid assets, and has so far reimbursed one utility, Pacific Gas and Electric Company, $168 million for the 2021 Dixie Fire, according to a spokesperson for the California Earthquake authority, which manages the fund. Based on the most recent 10-Q report by PG&E, the fund expects to pay a potential $925 million for that fire.

Officials are still working on loss estimates related to the Eaton Fire, and wherever the figure lands, the wildfire fund wouldn't expect to pay for the entire sum, Wara said. According to a spokesperson for the California Wildfire Fund, utilities must pay the first $1 billion of claims by themselves, before they can seek reimbursement from the fund. Property owners must first seek reimbursement from their own insurance coverage, and utilities are expected to try to reach settlements with insurance companies that file wildfire claims.

California's AB 1054, the law that created the fund, dictates that the fund will only reimburse claims settlements deemed reasonable by the fund administrator. Settlements with insurance companies are considered reasonable if the claim is settled for 40% or less of what the insurance company paid. But those that exceed 40% are subject to additional scrutiny under the law, according to the fund spokesperson.

Even if private insurance picks up, say, half the bill, a $10 billion to $15 billion loss on the Eaton Fire would eat a sizable chunk of the fund's available assets and leave it with limited resources to cover the next large California Wildfire, Wara said. Thus the concern by investors: not whether the fund will cover SCE's Eaton-related liabilities, but whether there will be enough left in the bank for the next utility hit by wildfire lawsuits.

The fund's relatively slow rate of replenishment relative to what it may need to pay out represents the other part of investors’ concerns. According to the wildfire fund's 2024 annual report, the fund has received $9 billion in annual contributions since 2019 from the three participating utilities — SCE, PG&E, and San Diego Gas & Electric. One-time initial contributions paid to join the fund represent $7.5 billion of this total.

Utilities’ annual contributions to the fund have brought in $1.5 billion, and proceeds from surcharges on ratepayers’ electric bills have generated about $3.3 billion, according to the annual report. Figures from 2023, the last full year of contributions detailed in the report, suggest the fund has a little under $1.2 billion coming in annually.

“That is the real source of uncertainty for utilities right now,” Wara said. “It's what we call ... the ‘go forward’ problem.”

Insurance Costs

For utilities, the immediate impact is not such much the threat of another bankruptcy on the near horizon, but the question of whether shareholders will be willing to accept current rates of returns in exchange for what appears to be much greater financial risk. And utilities have already begun to see some investors' answers. PG&E stock dropped 19% following the outbreak of the L.A. fires, while stock in Sempra, SDG&E's parent company, fell 9%. Edison International, SCE's parent company, dropped 26% following the fires — even before speculation about the cause began. Edison's stock price is now down by nearly 30%.

Declining stock prices, coupled with other increases in borrowing costs, impact utilities' ability to raise and deploy capital — hindering their ability to invest in wildfire mitigation and in new generation to meet growing demand, Emily Fisher, chief strategy officer for the Smart Electric Power Alliance, said during a February 19 webinar discussion on wildfires.

Utilities in California and throughout the west have also seen their credit scores downgraded as a result of growing wildfire risk, Fisher said, and PG&E CEO Patti Poppe said during the company's fourth quarter earnings call on Feb. 13 that it was unlikely the company would see substantial improvements in its credit score this year as a result of the fires.

Utility companies have also seen dramatic increases in their insurance premiums in recent years — assuming such insurance is even available, according to Alp Can, an actuary for USI Insurance Services and chair of the Actuaries Climate Index. Many utility companies have dropped their wildfire insurance policies and moved toward a self-insurance model, either to cut costs or because they cannot find a suitable policy, Can said.

“There are positives and negatives involved in that. Obviously you have to have the wherewithal, you have to reserve the funds in anticipation of catastrophic events,” Can said, adding that decreased costs typically come with a higher risk of insolvency.

Joe Wilson, a regional vice president for PG&E, noted during the Feb. 19 webinar that moving to a self-insurance model will save the company's customers $1.8 billion over the next four years — though, as a participant in the California Wildfire Fund, this move is potentially less risky for PG&E than for utilities in other states. Poppe told investors during the company's earnings call that PG&E was working with lawmakers to find ways to shore up the wildfire fund — as did leaders at Edison International and Sempra during their own earnings calls

This is the real challenge the wildfire fund seeks to address, Wara said: utility shareholders typically accept lower returns in exchange for reliable financial performance. Investors willing to accept the scale of risk associated with catastrophic wildfire do exist, but they generally expect much greater returns when their investments pan out.

“We can't afford to buy utility infrastructure from investors who expect a 20% return on their money,” he said. “It doesn't work.”

Reducing the consequences

Climate experts, including Wara, have historically called for a federal solution similar to the California Wildfire Fund in order to address the growing threat of wildfire litigation against utilities. But given the current policy climate, that seems unlikely. Even within the state of California, finding the will to increase the wildfire fund surcharges on residents' electric bills could prove challenging given the current political and economic environment, Wara said.  And utilities oppose paying more into the fund without a commensurate increase in electric rates, as this would eat into shareholder's returns, he said.

As a result, Wara and other experts are contemplating solutions outside the insurance paradigm. Eric Gray, vice president for government relationship at the Edison Electric Institute, argued that simple reforms like expedited permitting could help utilities implement mitigation strategies like undergrounding and vegetation management in a more timely manner.

Another option, Gray said, is liability reform — eliminating the strict liability paradigm that has emerged to hold utilities responsible for all damages related to fires started by their equipment, regardless of whether their actions are deemed negligent or not. He noted that some states, such as Utah, have already taken measures to limit utility liability, and that conversations surrounding this option are taking place in other states including California.

But Wara believes there's another side of the risk equation that deserves more attention: the vulnerability of private properties to fire. For all the billions that utilities have spent trying to reduce the odds that they could start a wildfire, total state and federal spending on measures and upgrades that could stop homes from catching fire is limited to a few hundred million, he said.

“We need to be spending something like $3 billion a year as a state on this other stuff,” Wara said. “Not utility ignition avoidance, but reducing the consequence of the ignition. Because in a state with 40 million people, there are going to be ignitions. There is no way to avoid it.”

And the risks of wildfire and climate change are so great, Can agreed, that taking a broader societal approach to solving the problem is likely appropriate.

“The climate change risk is a global, multi-layered chaos,” he said. “There are different channels of attack, of taking it on. Insurance will have to do its own part, governments will have to do their part, and the public will have to do its part.”

Utilities and system operators are discovering new ways for artificial intelligence and machine learning to help meet reliability threats in the face of growing loads, utilities and analysts say.

There has been an “explosion into public consciousness of generative AI models,” according to a 2024 Electric Power Research Institute, or EPRI, paper. The explosion has resulted in huge 2025 AI financial commitments like the $500 billion U.S. Stargate Project and the $206 billion European Union fund. And utilities are beginning to realize the new possibilities.

“Utility executives who were skeptical of AI even five years ago are now using cloud computing, drones, and AI in innovative projects,” said Electric Power Research Institute Executive Director, AI and Quantum, Jeremy Renshaw. “Utilities rapid adoption may make what is impossible today standard operating practice in a few years.”

Concerns remain that artificial intelligence and machine learning, or AI/ML, algorithms, could bypass human decision-making and cause the reliability failures they are intended to avoid.

“But any company that has not taken its internal knowledge base into a generative AI model that can be queried as needed is not leveraging the data it has long paid to store,” said NVIDIA Senior Managing Director Marc Spieler. For now, humans will remain in the loop and AI/ML algorithms will allow better decision-making by making more, and more relevant, data available faster, he added.

In real world demonstrations, utilities and software providers are using AI/ML algorithms to improve tasks as varied as nuclear power plant design and electric vehicle, or EV, charging. But utilities and regulators must face the conundrum of making proprietary data more accessible for the new digital intelligence to increase reliability and reduce customer costs while also protecting it.   

The old renewed

The power system has already put AI/ML algorithms to work in cybersecurity applications with cutting-edge learning capabilities to better recognize attackers.

Checkpoint Software, the global AI chip maker NVIDIA’s security provider, is working with standards certifier Underwriters Laboratories on new levels of security for consumer devices, said Peter Nicoletti, Checkpoint’s global chief information security officer. Smart devices “will be required to meet a security standard protecting against hackers during software updates,” he said.

Another proven power system application for advanced computing is market price forecasting based on weather, load and available generation.

Amperon has done weather, demand and market price forecasting with AI/ML algorithms since 2018, said Sean Kelly, its co-founder and CEO. But Amperon’s short-term modeling now “runs every hour and continuously retrains smarter and faster using less energy, combining the strengths from each iteration in a way that humans could never touch,” he added.

Hitachi Energy’s Nostradomus AI forecasting tool, with the newest AI/ML capabilities, “has improved price forecasting accuracy 20% over human market price forecasting” since November, said Jason Durst, Hitachi Energy general manager, asset and work management, enterprise software solutions.

AI/ML-assisted technology has also emerged “as a critical pillar of wildfire mitigation strategy,” said Rob Brook senior vice president and managing director, Americas, for predictive software provider Neara. It helps utilities identify wildfire risks “across their networks by proactively assessing more variables than a human can assimilate,” he added.

AI/ML algorithms have, in the last year, accelerated the use of robotics for solar construction, said Deise Yumi Asami, developer of the Maximo robot for power provider AES. The six months once needed to retrain Maximo have been eliminated because its AI/ML algorithms autonomously learn the unique characteristics of each solar project before it begins work, she added.

The new and more autonomous AI/ML capabilities will offer “increased stability, predictability, and reliability at scale,” said Nate Melby, vice president and chief information officer of Midwestern generation and transmission cooperative Dairyland Power Cooperative. Management of system complexity “is where AI could shine,” he added.

Utilities are increasingly using new AI/ML capabilities to meet the accelerating complexities of variable loads, proliferating distributed energy resources, or DER, and other power system challenges.

New needs, new capabilities

A power system without adequate flexibility “can lead to decreased reliability and safety, increased operational costs, and capacity costs,” Pacific Gas and Electric, or PG&E, concluded in its 2024 R&D Strategy Report. “AI/ML and other novel technologies can not only bolster our immediate response capabilities but also inform long-term planning and policymaking,” it added.

PG&E’s total electricity consumption will double in the next five to 10 years, but it can limit peak load growth to 10% with AI/ML-based grid optimization of DER on the existing infrastructure, PG&E CEO Patti Poppe said at the utility’s November Innovation Summit.

Access to AI/ML algorithms is now commercially viable, and their capabilities can optimize multiple large scenarios in parallel to support decision-making for the power system’s millions of variables, NVIDIA’s Spieler said. The algorithms can also write software code to allow utilities to use “the petabytes of stored system data they have but have not used to optimize more operations,” he added.

Utilities can upload and query their internal knowledge bases of research papers, rate cases and analyses of wildfire and safety issues into a generative AI model, Spieler said. The query responses can then explain system anomalies based on performance and maintenance histories or deliver needed data and precedents for writing general rate case and other regulatory proceeding filings, he added.

Utility demonstrations are verifying the new AI/ML capabilities.

From DER to nuclear plants

Several demonstrations have focused on how AI/ML algorithms can optimize distribution system resources.

Utilidata’s Karman software platform and an NVIDIA GPU-empowered chip are embedded in Aclara smart meters and will soon be in other distribution system hardware, said Utilidata VP, Product, Yingchen Zhang. Karman reads high resolution distribution system raw data 32,000 times per second and identifies individual customer electricity usages in real time, he added.

A real world demonstration, with Karman reading and reacting to granular real-time data, found utilities can quickly stabilize EV charging-induced voltage fluctuations, a University of Michigan-Utilidata study noted.

Within one year of implementing software from data disaggregation specialist Bidgely, Avista Utilities reduced service calls in response to high bill complaints by 27%, reported Avista Corp. Products and Services Manager Andrew Barrington. Instead of a service call to check the customer’s meter, Bidgely’s software analysis identified the customer usage causing the bill spike, he added.

A Bidgely disaggregation analysis evaluated EV charging for 10,000 Ameren Missouri customers, reported Caroline Cochran, its VP, Delivery, in a Stanford-EPRI conference presentation. The analysis identified the 73 customers that could utilize better management to avoid or defer costly infrastructure expenditures that otherwise would have been needed to manage EV charging loads, she added.

Bidgely’s similar 2023 disaggregation analysis of 100,000 NV Energy EV charger owners identified “hot spots where infrastructure investment will likely be needed first,” which limited larger distribution system capital investment, reported the Smart Electric Power Alliance’s January AI for Transportation Electrification Insight Brief.

AI/ML algorithms are also finding efficiencies that reduce nuclear power plant costs and safety challenges.

PG&E is using Atomic Canyon’s Generative AI software, trained to Nuclear Regulatory Commission standards, at its Diablo Canyon Nuclear Power Plant, said Nuclear Innovation Alliance Research Director Patrick White. And innovative AI/ML-based plant designs, operations and predictive preventive maintenance are limiting costs and increasing plant safety, he added.

There are, however, things utilities must do to more fully take advantage of the accelerating AI/ML capabilities, utilities and providers recognize.

The work ahead for utilities           

Effectively capturing the benefits of AI/ML algorithms begins with recognizing the potential and acquiring and using the right hardware and software, utilities and third parties say.

Avista’s successful adoption of third-party AI/ML “began with a mindset,” said Barrington. The key questions were “how to enhance customer engagement, how to integrate customer data with system operations, and how to enhance system visibility and enable proactive strategies,” he added.

AI/ML algorithms are now extracting real-time data and making actionable suggestions, Utilidata’s Zhang said. But “utilities cannot take advantage of the suggestions because they do not have the technology and communications ecosystems in place,” he added.

Utilities need communications technologies, advanced metering and edge computing infrastructure, and data processing and storage technologies, EPRI’s Renshaw said. And, at the distribution system level, utilities should also have software that can be securely updated for new technologies as customers adopt them, Utilidata’s Zhang added.

Balancing the protection of security and customer privacy with the need to provide data to train AI/ML algorithms continues to be a significant challenge.

Protecting utility data requires “strong cybersecurity practices,” said Dairyland Power’s Melby. But utilities need to access and manage data in a way “AI platforms can leverage,” he added.

Recently, “utilities have begun doing penetration testing to prove their data is as secure in our system as in theirs,” said Bidgely’s Cochran. They also “have developed AI committees to do extra thorough reviews of the users of their data,” she added.

“There is good reason for utilities to be conservative about data privacy, but AI/ML power system applications are not yet any threat,” Utilidata’s Zhang said. Federated learning or foundation models are ways to both protect privacy and provide data for algorithm training, he added.

Federated learning allows utilities to protect proprietary data by building synthetic models of their data about specific challenges that can be shared at a secure location for further training, Zhang said.

But some think federated learning may be too limited for power system complexities. Foundation models would use orders of magnitude more data that has been anonymized and pre-trained with as much power system information as possible, EPRI’s Renshaw and others said.

Utilities may be able to create a foundation model to enable shared learning and protect their data, said PG&E Senior Director of Grid Research, Innovation and Development Quinn Nakayama.

“The bottom line is — gather more high-quality data, use, store and protect it properly, and feed it into models that are trained and updated for the right tasks,” Renshaw concluded.