Climate/Weather Risk Mitigation

The Securities and Exchange Commission’s climate risk disclosure rule has gone through quite the journey over the past two years. The rule was first proposed in 2022, mandating that companies describe their levels of greenhouse gas emissions and strategy toward reducing climate risk on their Form 10-K — an announcement that was met with pushback from both companies and politicians, particularly state and federal Republicans.

After pushing out its initial release and reviewing over 24,000 comments, the SEC passed the highly anticipated rule with a 3-2 vote earlier in March. The final rule scrapped scope 3 emissions disclosures entirely and scaled back scope 1 and scope 2 reporting requirements.

Despite the final rule being a pared-down version of the original, the regulation faced legal action almost immediately, both from critics who said the SEC had gone too far and from supporters who said the SEC hadn’t gone far enough. Consequently, the agency announced its decision to stay the rule in April as it works through these legal challenges.

Though the rule’s implementation has been halted as of now, it is just one of a plethora of climate regulations American corporations must potentially comply with going forward. This includes disclosure requirements both on home territory with California’s two climate bills — Senate Bills 253 and 261 — and abroad with frameworks like the European Union’s Corporate Sustainability Reporting Directive.

On July 11, ESG Dive — in collaboration with its sister publication, CFO Dive — hosted a virtual event focusing on how industry leaders and C-suite executives could set their respective companies on a smart path to compliance against the backdrop of the SEC’s climate rule and other disclosure regulations. Experts from Ceres, Morningstar and Morgan, Lewis & Bockius shed light on what the recent coalescence of global reporting frameworks, the Supreme Court’s Chevron ruling and the plethora of legal challenges being faced by the SEC rule entail for climate disclosure requirements going forward.

Here are our top takeaways from the “Risk & Reward: Complying with the SEC’s Climate Rule” event.

Lagging enthusiasm for climate disclosures from regulators

After the SEC backed away from an initial rule that would have required all public companies to disclose their full scoped emissions, Lindsey Stewart, director of stewardship research and policy at Morningstar Sustainalytics, said the final rule showed a growing gap between disclosures investors want and the regulations being promulgated.

“We've really ended up with a very different rule from what was proposed in 2022,” Stewart said. “I think a lot of the high ambition that we saw around COP26 … where investors and companies were expected to lead the drive towards net-zero and towards climate, for reporting and disclosure of climate risk, a lot of that initial enthusiasm appears to have subsided in the time that has elapsed since.”

Stewart said the comment letters received by the SEC showed that, in addition to a baseline expectation of disclosure of greenhouse gas emissions and material climate risks and opportunities, investors are looking for company boards to have an “appropriate level of climate competence” across management.

How companies can best prepare for disclosure requirements

“You need to start preparing now,” said Erin Martin, a partner at Morgan Lewis who counsels public companies and their boards on securities regulation, capital markets transactions and corporate governance matters. Martin noted, however, that such preparations would also be affected by the “ton of uncertainty” surrounding disclosure requirements.

“That's going to be challenging for any public company … to address the changing and evolving landscape of regulation,” she said.

Martin said companies will have to consider things like where they should focus their time and resources and what counts as “financially material” to adhere to the growing disclosures. 

She said that though determining what counts as financially material, and what isn’t, for a company might be time-intensive work, she has counseled her clients to “not sit and wait for the courts to decide,” alluding to the multiple legal challenges being faced by the SEC rule. 

Martin noted that although the SEC’s legal battle might take upwards of 18 months to work through, eventually, some pieces of its disclosure rule — if not all of it — “will be required.”

“In order to ensure that you can provide accurate information responsive to the SEC requests and rules … you need to have processes in place today to anticipate those rules so you can ensure that you have accurate disclosure that you're providing, under the federal securities laws to your various stakeholders,” Martin said. “We can't just sit and wait.”

SEC rule vs. other climate disclosure regulations

Much has been said about how the SEC’s final rule compares to other disclosure requirements, such as California’s climate bills and Europe’s CSRD — which still require scope 3 emission disclosures. Jake Rascoff, director of climate financial regulation at sustainability nonprofit Ceres, said the importance of having a federal regulation that mandates climate disclosures on a financial report is irreplaceable.

“To those who say, why do we need the SEC rule when we have California and Europe and ISSB? I think there is no real replacement for having this information in an SEC filing,” Rascoff said during the panel.

He said investors defer to a company’s 10-K or S-1 filing — which provides information on a company’s activities and financial performance — when evaluating its due diligence or investment stewardship efforts. Rascoff said such SEC-mandated filings were “critically important for improving the consistency and comparability” of climate-risk disclosures.

Rascoff said an SEC filing is subject to “a level of rigor and scrutiny that doesn't necessarily exist for voluntary disclosures or even other …  jurisdictions’ requirements.”

“The whole point of disclosure is to provide investors with the necessary information to make an informed investment decision, and then empower investors through that disclosure to make those determinations,” Martin noted when speaking about the SEC’s authority to mandate climate disclosures.

Challenges to compliance

Experts speaking on the July 11 panel said challenges to comply with the rule will vary depending on how an individual or group interacts with it. For investors, Stewart said, among the “challenges galore” will be navigating the various frameworks that already exist, including those in California and the EU. Companies navigating the fragmented environment will also have a more difficult time succinctly telling the story of how their sustainability mission coincides with their finance story.

“It certainly isn't going to be easy for companies to effectively communicate [their sustainability and finance story] across a fragmenting environment,” Stewart said. “So let's hope that this level of fragmentation doesn't last forever. I guess each jurisdiction had to start somewhere. We are where we are, and let's move forward from here.”

Martin, who spent more than 13 years in the SEC’s Division of Corporation Finance, said the rule will also place increased pressure on the agency’s regulators to determine compliance. She said the agency will need to ensure there is appropriate training and the right staff makeup to ensure they can determine if a company’s filing is materially compliant.

What the Chevron ruling means for ESG

The U.S. Supreme Court’s ruling in Loper Bright Enterprises v. Raimondo, which overturned the Chevron doctrine, has threatened to upend administrative law procedures to a varying extent. The fate of regulations in a post-deference era may come down to a more case-by-case analysis. The doctrine was used to dismiss a challenge to a Department of Labor rule allowing pension fund managers to consider ESG factors, and that case is currently under consideration by an appeals court.

Rascoff said the challenges to the SEC’s rule in the U.S. Eighth Circuit Court of Appeals were made more challenging by the Loper Bright ruling. He said the agency is facing an “uphill battle” to protect its rule.

“Consensus opinion is [that] this rule is unlikely to survive litigation completely intact,” Rascoff said. “I would hope elements of it do survive.”

Martin said that while Chevron gave agencies leeway to interpret ambiguous statutes, the SEC has been given broad discretion to implement disclosures “it views to be necessary for investors” by the Securities Act of 1933. Because of this, she does not expect the Loper Bright decision to lead to any rules being immediately tossed. However, the ruling will give opponents an additional method by which to challenge the agency’s rulemaking process. 

When it comes to the SEC’s current litigation, Martin said the lack of Chevron deference may add more support for arguments that the climate-risk disclosure rule is “arbitrary and capricious,” but does not mean the rule will be completely tossed.

“It's not, we have to start over. That's not what's at play here,” Martin said. “To be clear, [the Loper Bright ruling] does have a big impact. Just maybe not in this very small technical space right here.”

The California Public Utilities Commission on March 7 approved a long-term power line undergrounding program allowing major utilities to propose 10-year plans designed to harden the state’s electric grid against wildfire risks while driving down costs through economies of scale.

Moving power lines underground can reduce the risk of wildfire ignition by 98%, according to Pacific Gas & Electric, but critics of the practice argue there are cheaper methods such as reconductoring lines in at-risk areas. California utilities say burying their lines can cost from $1.85 million to $6.1 million per mile, depending on the location.

Under the new program, utilities with at least 250,000 customers can submit undergrounding plans to the state’s Office of Energy Infrastructure Safety, which must approve or deny the plan within nine months. The CPUC will then have nine months to approve the costs.

Regulators stood up the new undergrounding program just four months after PG&E’s last general rate case was approved, which included authorization to bury more than 1,200 miles of power lines.

In that decision “we found that increased investments in hardening the grid would provide great value to Californians,” CPUC Commissioner John Reynolds said in a statement. “The rules adopted today build on those investments, ensuring that long-term undergrounding promotes a safer grid in the most cost-effective way.”

The new undergrounding program was authorized by legislators in 2022, in Senate Bill 884. It requires utilities to apply for available federal, state and other funding to help pay for the projects, and it calls for periodic audits led by an independent monitor selected by the Office of Energy Infrastructure Safety.

The CPUC said any approval of undergrounding costs must include certain conditions including annual cost caps, unit cost caps, a cost-benefit threshold and requirements for third-party funding to be applied to reduce the annual cost cap.

“This program creates a process for expedited undergrounding ... while also incorporating oversight and ratepayer protection measures,” said Commissioner Darcie Houck.

PG&E in 2021 set a goal to move 10,000 miles of power lines underground and in December said it had completed about 600 miles of that work while also reducing costs from $4 million per mile to below $3 million per mile.

PG&E filed for bankruptcy in 2019 after fires caused by its power lines burned hundreds of thousands of acres in Northern California and led to more than 100 deaths. It paid out $25.5 billion to resolve its fire-related liabilities.

The utility said it plans to file its 10-year undergrounding plan by the middle of this year. Critics say customers can not afford more rate increases, however.

PG&E’s general rate case approved by the CPUC in November added about $34 per month to average bills, according to local news sources. And regulators gave interim approval to a smaller increase on March 7, which also included more than $500 million for upgrades including undergrounding.

“This situation is untenable for many of PG&E's residential customers, who have seen rates balloon by over 80% over the last three years, making PG&E the most expensive power provider in the state,” Assemblymember Dawn Addis, D, and other lawmakers said in a letter to the CPUC last week.

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For a risk manager at an electric utility, it’s crucial to recognize that the threat of catastrophic wildfires is pervasive and exists almost everywhere. Electric utilities are increasingly faced with the challenge of assessing their wildfire risk and applying mitigation strategies to reduce potential impacts. This task demands more than a simple designation of risk levels; it requires a comprehensive, nuanced approach that recognizes the complexities of fuels, climate, and people.  As climate conditions evolve, areas once considered low risk are now facing heightened dangers, increasing the likelihood of unexpected and extreme wildfire events. These singular events can prove catastrophic for utilities highlighting the urgent need for comprehensive risk assessment.

These events are often termed “unprecedented” due to their extreme magnitude or unexpected locations. But we have seen numerous “unprecedented” wildfire events in the past five years stemming from asset-caused ignitions. A good example of an “unprecedented” event is the 2020 Labor Day Megafires along the West Coast, where a massive drought and one of the strongest east-wind events on record destroyed thousands of homes, burned over 1 million acres, and took 11 lives. Another unprecedented weather event was the 2021 heat dome in the Pacific Northwest, when during its peak, at 121°F, was hotter than Death Valley, CA. According to a recently published paper in Nature, that singular event accounted for 21–34% of the total area burned in 2021.

For electric utilities, these events demonstrate why combining climatological analysis with operational risk modeling is essential. Climatological analysis helps understand what is normal and the operational forecast shows what is coming over the near term. This integration not only offers a comprehensive understanding of wildfire risk but also equips utilities with the ability to forecast unprecedented events, thereby enhancing preparedness and minimizing risk.

To develop such modeling, risk managers need to know their vegetation (and its dryness), topography, and upcoming forecasted weather. Yet, this data collection just highlights risk on the landscape. What managers need in addition is advanced fire spread modeling that can tell where a fire will go and what impacts on structures, acres, and people can occur, so the consequence of that risk can be determined for better decision-making. This advantage is becoming extremely important as more and more severe weather events impact the United States.  These “unprecedented” events make it hard to calculate their recurrence intervals and are often explained as “1-in-100” or “1-in-100,000” year events. How can we identify where these extreme events are most likely to occur and are we able to forecast these events in real time?

To do this, risk managers need to leverage climatological analysis based on historical weather data sets, running backward in time 20 to 30 years over a specific territory. The goal is to capture the complete historical variability of fire weather conditions, from typical low-risk days to the most extreme scenarios. Establishing this weather baseline helps in monitoring trends, setting norms, and calculating recurrence intervals.

Additionally, by combining climatological data with the utility’s outage records and asset information, probability of outage/ignition modeling can be conducted. This approach allows for quantifying and rating the likelihood of asset outages and the probability that a specific asset will ignite a wildfire under various weather conditions.

Combining climatological data with operational forecasts can help utility managers understand the severity of any upcoming weather event in their territory. When this data is processed through a fire spread model, it provides insights into where the greatest impacts on the landscape, people, and structures would occur if a fire were to start. Finally, by leveraging the probability of outage and ignition modeling they can see where these impacts are most likely to materialize.

Implementing such a comprehensive modeling framework empowers utilities to proactively manage and respond to severe weather events, even those as unprecedented as the Labor Day 2020 Megafires or the 2021 heat dome. This advanced approach provides utilities with the tools needed to manage severe weather events effectively, ensuring safety and reliability in an era of increasing climate volatility. Ultimately, they can confidently forecast the unprecedented. Learn more about the modeling science behind this work and how that science is put into practice.

As another unusually hot summer has demonstrated, heat waves, floods and other extreme weather events are already testing grid resilience in every region of North America. To meet these challenges, electric systems must be well-planned and climate-aware. This is an increasingly urgent task that utilities, system operators (RTOs/ISOs) and other planning entities are beginning to execute. However, there is a key aspect of the transition to a more resilient grid that requires more attention: how the impacts of future climate change intersect with the transformations required to decarbonize the energy system.

Building an energy system that is both clean and resilient is possible with the right planning tools. Our analysis of the impacts of climate change in New York State finds that investments in building decarbonization, including measures such as energy efficiency and heat pumps, can have additional climate resilience benefits that are often overlooked.

As part of the New York State Climate Impacts Assessment: Understanding and Preparing for Our Changing Climate, the New York State Energy Research and Development Authority commissioned Energy and Environmental Economics to perform a detailed examination of the impacts of rising temperatures on the New York State energy system. In collaboration with Industrial Economics and Michael Craig of the University of Michigan, E3 incorporated hourly temperature projections into the same energy system modeling framework we used to support the New York State Climate Action Council Scoping Plan.

The analytical framework coupled (1) temperature projections under three climate change scenarios, and (2) the impacts of changes in temperature on key components of energy supply and demand to examine two infrastructure scenarios: a reference case reflecting less decarbonization investment and a Climate Act-compliant decarbonization scenario.

The analysis examined three warming scenarios, selected as illustrative bookends from a broader climate modeling exercise performed by Columbia University using general circulation models, including a “mild” scenario with no change in winter temperatures relative to today; a “severe” bookend scenario with very high levels of warming in both the summer and winter; and a “moderate” scenario with comparable levels of summer warming through 2050 but less pronounced impacts on winter temperatures (Figure 1).

Figure 1: Projected impacts of climate change on temperature in New York state

The impacts of warming on the ‘peak heat’ challenge

Under deep decarbonization scenarios, the electric system must grow significantly to meet newly electrified heating end-uses in cold climates. To meet its Climate Act goals, winter peaks in New York are expected to grow substantially under today’s climate conditions, approximately doubling to reach nearly 50 GW between 2022 and 2050.

Increased warming can partially reduce the electric infrastructure investments required by electrification-driven load growth. Our analysis finds that warming temperatures could lead to reductions in the decarbonization scenario winter peak of between 4 GW and 7 GW across moderate and severe levels of warming in 2050 (Figure 2).

Figure 2: Impacts of warming temperature on NYISO seasonal peak demand

However, meeting system peak needs in the winter remains a critically important challenge to solve under decarbonized futures, especially given the limited availability of certain resources. For example, times of high demand during the winter often coincide with reduced solar output as well as outage risks at thermal power plants due to freezing of plant equipment or fuel infrastructure.

It is also important to note there is still uncertainty associated with how climate change may impact extreme cold weather events, which may limit the extent to which electricity system planning is impacted by expectations of warmer winter extremes, especially given the importance of maintaining reliability during extreme cold as more customers rely on the electric system as their primary heating source.

Building decarbonization investments can offset the impacts of temperature rise on summer peaks

In a “reference” scenario, summer air conditioning needs drive peak electricity demand, and reliance on existing, relatively inefficient cooling equipment makes the New York grid very susceptible to warming temperatures. Our analysis finds that the summer peak in a reference scenario increases by between 3 GW and 12 GW (7%-28%) by late century under moderate and severe levels of warming relative to the mild warming scenario (Figure 2).

New York’s investments in decarbonization of the buildings sector, including investments in efficient building shells, would also have the added benefit of mitigating electricity system peak impacts in both seasons. Investments in building insulation and heat pumps — which are significantly more efficient than conventional air conditioning units — help to mitigate the impacts of rising temperatures on summer peak demand, adding value on top of the improved air quality and carbon benefits (Figure 3). Conversely, without investments in improved building shells and more efficient equipment like heat pumps, increasing summer temperatures lead to significantly higher cooling demand.

Figure 3: Combined impacts of warming temperatures and decarbonization investments on NYISO summer peak, 2050

In the decarbonization scenario the capacity added to meet electrification-driven winter peak demand is required to meet summer peaks as well; as a result, the resource portfolio is developed to meet system reliability needs across both the summer and winter seasons. By 2050, under severe levels of warming, the reference scenario requires nearly the same amount of capacity to maintain reliability in the summer despite having significantly lower levels of building and transportation electrification than the decarbonization scenario.

Rising summer temperatures will also impact electric infrastructure

The challenge associated with maintaining system reliability during summer peak demand periods is compounded by the impacts of rising temperatures on electric infrastructure. For example, higher temperatures lead to lower transfer capacity across the transmission system and reduced output from solar panels due to a fundamental reduction in efficiency. Warming also has a two-fold impact on thermal generators, increasing ambient temperature derates for combustion-based power plants and at the same time worsening their risk of unforced outages.

Many ISOs and utilities are already moving towards an effective load-carrying capability framework to capture the reliability contributions of intermittent and limited-duration resources such as wind, solar and battery storage. The same framework can and should be applied to thermal generators, which can experience correlated increases in outage risks during periods of high demand (during both extreme cold and extreme heat events). By accounting for the coincidence of thermal generator performance with reliability events, this framework would enhance system reliability under today’s climate conditions, provide a stronger incentive for weatherization of infrastructure, and be more adaptable to changing climate conditions in the future.

As the impacts of climate change intensify, it will become increasingly important for energy system planners to directly account for the effects that warming temperatures will have across every segment of the industry. Scenario design and sensitivity testing can be used to characterize critical sources of uncertainty, and ultimately planning frameworks will need to be highly adaptable in the face of ongoing uncertainty around how climate change and warming temperatures will impact energy supplies and demands.

By continuing to invest in climate modeling efforts and incorporating climate uncertainty into decarbonization planning, the industry will ensure that the significant investments made over the coming decades are robust to a broad range of plausible futures.

The Nuclear Regulatory Commision does not fully account for future climate risks in its reactor licensing and oversight processes, the U.S. Government Accountability Office said in a report released April 2.

NRC officials interviewed by the GAO said they believe current NRC risk assessment processes adequately consider climate risk, but the commission has not made a formal assessment on the question, the report said.

“Our position is that as we go forward, [the NRC] should take the best available information on what to expect from climate change and use that to supplement their risk assessments,” GAO Natural Resources and Environment Director Frank Rusco told Utility Dive in an interview. 

The NRC considers a broad range of safety threats in its licensing and operational oversight processes, including wildfires, high winds, extreme heat and cold, flooding, hurricanes and drought.

The commission closely examined flooding risk after the 2011 disaster at the Fukushima Daiichi nuclear plant in Japan, which partially melted down and released radioactive water after it lost backup power in an earthquake-induced tsunami. It published a final rule in 2019 that would require operating commercial reactors and new reactor license applicants to ensure uninterrupted reactor cooling following the loss of normal backup power.

Despite criticism from the Union of Concerned Scientists and others that the rule was not stringent enough, it did address a notable weakness in nuclear safety protocols, Rusco said.

“The NRC is a bit ahead of the game on flooding because of Fukushima,” he said.

However, the NRC currently uses historical climate data to assess other safety risks that could worsen due to climate change, the GAO found. Ahead of an anticipated flurry of new license applications for reactors “that could be around for another 80 years,” the NRC should be “looking ahead” as climate models improve and incorporate new data, Rusco said.

The GAO report made three recommendations to the NRC:

• The commission ought to assess whether its current licensing and oversight processes adequately account for increased risks due to climate change;
• Should that assessment find any gaps in existing processes that could threaten nuclear safety, the commission ought to devise and implement a plan to address them; and
• Moving forward, the commission should determine which climate projections to use in licensing and operational oversight processes and establish guidelines for how and when to incorporate those data.

In written comments included in the GAO report, the NRC noted that “the three recommendations are consistent with actions that are either underway or under development.” But Rusco reiterated that the NRC does not currently incorporate climate projections into its licensing and oversight processes.

”It could well be that if they looked at all the [climate change] projections now, even worst-case scenario projections, they’d compare those against their [safety protocols] and say, ‘We’re still good,’” Rusco said. “But they don’t know that unless they look.” 

The GAO report did not suggest that the U.S. commercial nuclear fleet faces acute climate-related safety threats today, and any future threats would be site-specific, Rusco said. It’s likely that extreme weather events would first impact reactor performance rather than safety, such as an extended heatwave that affected a reactor’s supply of cooling water, he added. 

“We don’t want to give the impression that all these plants are unsafe because of climate change,” Rusco said. But it’s better for nuclear plant operators, utilities, ratepayers and the NRC itself that the commission builds forward-looking climate data into its processes, he added.

“In the end, that’s going to save money for operators and ratepayers,” he said. “You don’t want to have to make costly upgrades as the climate changes.”

2023 marked yet another year of costly wildfires in various parts of the United States. In June, an investigation into the causes of the 2021 Marshall Fire — deemed the most destructive wildfire in Colorado history — had hundreds of litigants lining up to sue Xcel Energy for a dislodged power line that may have ignited part of the fire. Xcel executives disclosed that the company’s potential liability for the fire could exceed the limits of its insurance policies in a July earnings conference call.

Two months later, Hawaiian Electric indicated in an SEC filing that it was “seeking advice from various experts” as part of “prudent scenario planning” to contend with litigation associated with the wildfires that devastated the island of Maui in August. The company has not declared bankruptcy, though it has spoken with restructuring advisors, hired a new CFO with experience in utility bankruptcies, and contributed $75 million to a fund for victims of the fire who are willing to forgo litigation.

It's not unheard of for a utility to declare bankruptcy in the wake of wildfire-related litigation — Pacific Gas & Electric being a prime example. But bankruptcy is not the only consequence of the rising tide of wildfire litigation. Insurance companies, PG&E spokesman Paul Doherty said, are also reconsidering how — and in some cases whether — they will extend liability coverage to utilities in wildfire-prone areas.

“At PG&E, we've experienced a varied response by insurance companies in the commercial markets,” Doherty said in an email. “From some carriers opting to no longer offer wildfire liability policies, to sub-limits of insurance for wildfire-related losses, to higher deductibles and increasing premium costs for policies covering wildfire risk.”

Insurance analysts say the growing risk of severe wildfires due to climate change, and a shifting legal landscape that increasingly holds utilities accountable for the damages caused by these conflagrations, has indeed changed the calculus that goes into a utility's liability insurance policy. But they're split on what that means for the long-term. Some analysts believe that the growing need for wildfire-related liability insurance will spark ingenuity, bringing new insurance products to market.

Others, however, believe the government may need to intervene in order to quite literally keep the lights on in some parts of the U.S.

“I can't say whether there will or won't be insurance, or whether utilities will have problems with coverage,” Finity Consulting Principal Rade Musulin said. “But what I will say is many of the prerequisites for an insurance market that can deliver stable and affordable prices are not met in this space.”

Climate risk, or climate uncertainty?

For insurance to work, Musulin said, actuaries need to be able to do two things. They need to be able to calculate the losses associated with a potential incident, and then they need to calculate the likelihood that the incident will occur. This allows them to estimate what it will cost an insurance company to insure its clients against a given risk — and to estimate a premium that would cover those potential costs.

Most of the time, actuaries incorporate historical data in their estimates of potential risk and losses, Musulin said. And this is the problem insurance companies have with covering modern threats like terrorism, cyberattacks and climate change — historical data isn't representative of today's risk environment.

When it comes to wildfire and climate change, Musulin said the insurance industry is relatively comfortable with its grasp of the scientific issues. They have most of what they need to know about changing incidence of drought and severe winds, and how these issues could contribute to more frequent and more severe wildfires in the future. What isn't known — and what's currently creating the greatest angst for insurers — is how infrastructure designed for the climate conditions of yesteryear will perform under future unprecedented conditions.

“The scientific [evidence] is in reasonably good shape. The question is, what happens when that climate hits something. How likely is it that thing will become damaged?” Musulin said.

And you can't just assume, Musulin said, that if you increase the speed of the wind during a severe storm by 10%, that the damage caused by the storm will increase by a corresponding 10%. Most structures are designed to withstand extreme conditions up to a certain point — and after that point, they fail, he said.

“There might be very little damage up to winds of 100 miles per hour,” he said, “but at 110 the building will fall over.”

Wildfire risk is also impacted by a shifting legal landscape, Musulin said. It's not just that our social expectations surrounding climate, and the responsibility of industry for climate-related disasters like wildfire have shifted, he said. In the past, it was relatively difficult to determine who or what was responsible for starting a wildfire. But it's much easier if there's a camera pointed at a power line. And today, cameras are everywhere.

Add inflation and rising property values into the mix, Musulin said, and you're starting to raise some real questions about whether insurance — or anyone — can absorb the cost of losses that could be associated with wildfires in the years to come.

Insurance innovations

Alp Can, an actuary for USI Insurance Services and chair of the Climate Index Task Force that produces the Actuary's Climate Index, takes a more optimistic view of the future of commercial insurance for utilities. It's not that he intends to downplay the significance of the liability risk posed to utilities by wildfires — it's difficult to understate the potential magnitude of liabilities in the tens of billions of dollars — but Can believes the problem can be managed. What's more, he and other industry observers believe wildfire risk could spur innovation in commercial insurance that could ultimately prove beneficial to utility companies.

Historically, utility insurance policies have focused more on the risks associated with power generation, and less with transmission.

“That will need to change,” Can said, “because the risk of wildfire isn't simply a function of climate change. It's also a function of how utilities have managed their transmission lines.”

This has led actuaries to work with other industry experts to develop models capable of assigning insurance premiums based on factors such as whether a utility has buried its power lines or has programs to keep vegetation from coming into contact with above-ground lines.

“These are going to be taken into consideration, and insurers are going to make use of improvements in catastrophe modeling and location tools such as satellite space monitoring to pinpoint the level of risk involved with individual assets and locations,” Can said.

Insurers are also looking at contractual innovations such as parametric insurance, Can said. Parametric insurance is conditional coverage based on a specific parameter, such as, in the case of a wildfire, the total acreage burned by a single event. With this kind of insurance, the policy would kick in and cover a utility's liabilities in the event that a wildfire reached a certain catastrophic size. Wildfire lends itself well to this kind of coverage because of its binary nature, Can said. An insured property will either remain out of the path of the event, or it will be caught in the wildfire’s sprawl, in which case it will usually burn to the ground, presenting a total loss.

“With these kinds of tools and approaches available, I would say we are equipped to handle this particular risk,” Can said. “Insurers are going to start becoming much more discerning about the potential for billions of dollars of losses, but with all the mitigation efforts taken into consideration, I believe coverage will be viable.”

This all strikes Mike Doyle, a senior equity analyst for Edward Jones who covers Xcel Energy, as rather good news. Insurance costs are going up, and insurance isn't something you love to see a company spending too much money on, Doyle said. But it also creates a financial need for transmission upgrades and grid hardening, and that's going to trigger a need for capital that will open opportunities for investors.

“It's a common theme for utilities that when a problem is identified, they find a solution. And usually that solution is going to cost money,” Doyle said. “And if regulators think it is important to fix that problem, they invest money and earn a return.”

By raising the costs incurred by utilities due to poor grid maintenance, insurers could also help utilities convince regulators — and investors — of the need to perform grid hardening, Musulin said. In the long-term, he believes this will prompt the industry to invest in future-proofing the grid, which will drive down the risk and cost of catastrophic wildfires. Electrification and the growth of renewable energy will require major grid investment in the coming years, providing an opportunity to address wildfire mitigation at the same time, he said.

But that's the long-term view, Musulin said. It will take years to rebuild the grid, and in the meantime, he said, the government may need to step in to literally keep the lights on in some wildfire-prone areas. Because if utilities face massive liabilities in the event of a wildfire and rising insurance premiums, they may decide the most financially prudent solution is to simply shut down the grid when the risk of fire is greatest — a phenomenon that is already sufficiently common that claims against Hawaiian Electric have argued its failure to de-energize the grid makes it responsible for the damages on Maui.

PG&E, similarly, states on its website that it may implement a Public Safety Power Shutoff during conditions such as low humidity, high winds or dry vegetation near power lines.

But this isn’t the only strategy PG&E has adopted to address the rising cost of insurance and the diminished availability of suitable insurance policies. Doherty said PG&E has opted in late 2023 to move to a 100% self-insurance model in pursuit of a more cost-effective solution to wildfire risk — meaning that the company has discontinued third-party insurance and plans to use its own funds to cover future wildfire liabilities. 

PG&E also has access to the California Wildfire Fund, which reimburses participating utilities for legal claims that result from a wildfire. The program is funded via an electric bill surcharge and administered by the California Earthquake Authority, a publicly-managed, privately funded insurance company created by the state legislature. PG&E expects that these programs will save customers up to $1.8 billion over the next four years, according to Doherty.

The public-private approach, Doherty said, “has been an innovative solution to protecting utilities and supporting the continued investment in safe, clean, and reliable power for California at a reasonable cost to customers.”

Adverse wildfire-prone conditions might become more frequent due to climate change, potentially increasing the incidence of extreme fire events. But this can be prevented by properly optimizing investments and operational decisions for power grids while explicitly considering the relationship between power lines and wildfire ignition under a methodology being developed by researchers at the Lawrence Berkeley National Laboratory with support from the Department of Energy’s Office of Electricity Advanced Grid Modeling program and in partnership with professors from the University of Michigan and the University of Washington.

The proposed methodology is capable of balancing the costs and benefits of different wildfire mitigation approaches and indicating the optimal portfolio of investments to protect power grids.

In this century, wildfires quickly became one of the most feared extreme weather events and a major challenge to safely operating power grids in different locations within the U.S. and abroad. Wildfire-related damages to transmission and distribution assets exceeded $700 million between 2000 and 2016 in California, which is also where the frequency of small wildfires and the total area burned by large ones have significantly increased over the last two decades.

During windy weather periods with low humidity and high temperatures, power lines passing through areas surrounded by vegetation cause some of the most severe wildfires. In fact, if these areas are large enough, multiple ignitions might occur. Some examples of wildfires triggered by power lines include:

• The “Black Saturday fire,” which destroyed more than 400,000 hectares and caused 173 human deaths in Victoria, Australia, in 2009;
• The “Bastrop fire,” which resulted in the death of two people and the loss of hundreds of homes, in Texas in 2011;
• The “Camp Fire,” which led to the death of 85 people in 2018 and is the deadliest wildfire in the history of California; and
• The “Dixie fire,” which burned an area larger than 300,000 hectares in California in 2021.

Indeed, in California, out of the 20 most destructive wildfires observed in the past two decades, at least nine were caused by the interaction between electrical infrastructure and the environment.

Wildfires induced by power systems can be started mostly either when external objects, such as tree branches, come in contact with a power line or when the line itself comes in contact with nearby vegetation, equipment or other lines as depicted in Fig. 1. In either case, usually a line fault is followed by the ignition of nearby vegetation. The ignition process occurs when the power flowing in the conductor finds an alternative path to the ground, closing a circuit. This action can directly start a fire when close to vegetation by creating an arc, or indirectly through molten metal particles, burning embers or burning fluids.

In this context, the higher the power flow, the higher the thermal stress of the lines, and the higher the chance of electric arcs to occur. The duration and intensity of these arcs are directly related to ignition probability.

The missing puzzle piece to deal with this critical problem is determining how the benefits of different investment options should be balanced to mitigate wildfires and find the most cost-effective portfolio of actions.

Concerned about the numerous adverse fire incidents over the past two decades, electric utilities in California and elsewhere have started specific programs to tackle this issue. San Diego Gas & Electric has created numerous initiatives, including enhanced situational awareness, forecasting and wildfire risk modeling programs. Furthermore, infrastructure improvements have also been implemented, encompassing conductor covering, equipment modernization, protection enhancement and microgrid development.

Southern California Edison also developed special operational protocols and implemented vegetation clearance and conductor hardening. In addition, artificial intelligence and machine learning algorithms have helped the company to identify equipment defects via aerial inspections. Similar actions have been taken by Pacific Gas and Electric. The company is one of the utilities in California that use the Public Safety Power Shutoff program, where under specific weather conditions, power lines are actively de-energized in high-threat areas to prevent wildfire disruption. As a consequence, this program can cause power outages for customers during long periods.

A more recent initiative from PG&E, the so-called Enhanced Powerline Safety Settings, or EPSS, program, is helping to reduce the frequency of PSPS events by deploying protection devices that can rapidly de-energize power lines once in contact with external objects, therefore decreasing the amount of energy released by a potential arc and thus reducing potential sources of wildfire ignition. However, EPSS might increase the frequency of service interruptions compared to usual protection mechanisms as it makes protection equipment much more sensitive and potentially disconnects power lines even when it is not needed. In any case, there is no single silver bullet for the wildfires problem and a combination of different measures is needed to address this issue.

The methodology being developed by LBNL, in partnership with the University of Michigan and the University of Washington, can help system planners and operators to explicitly consider how power flow levels through power lines can increase ignition probability within high-threat areas. Essentially, the developed methodology considers different investment alternatives — for example, line coating, line undergrounding, installation of line segments through alternative paths paired with strategic placement of switching devices, etc. — and provides the portfolio of actions that will increase the flexibility of the system to deal with wildfire-prone weather conditions and minimize service disruptions.

By properly considering how the magnitude of power flows through lines can increase fire ignition probability, the methodology is able to identify tactical investments that can decrease frequency and duration of interruptions and would not be properly valued otherwise. This is one of the main advantages of the LBNL-UM-UW methodology compared with current mitigation efforts together with the capability of considering multiple intervention options.

The methodology is under active development and has been presented to SDG&E, whose territory is partially affected by wildfires. Improvements to enhance its computational efficiency of the developed approach are currently the main focus of the project.

The U.S. Department of Energy on Jan. 16 announced $34 million in funding to support a dozen projects focused on improving the nation’s power resilience by moving some grid infrastructure underground.

The projects span 11 states, and are being developed by small and large businesses, national labs, and universities. They are being funded through the Grid Overhaul with Proactive, High-speed Undergrounding for Reliability, Resilience, and Security program — aptly known as GOPHURRS — and managed by DOE’s Advanced Research Projects Agency-Energy.

Projects include multiple worm-inspired digging approaches, an artificial intelligence and aerial drone solution, ground penetrating radar and advances in cable deployment and splicing.   

The U.S. electric system spans more than 5.5 million line-miles and contains over 180 million power poles, “all of which are susceptible to damage by weather and its effects, and account for a majority of power outages in the country each year,” DOE said. “Undergrounding power lines is a proven way of improving the system reliability for both transmission and distribution grids.”

Moving power lines underground can keep them functioning through storms and reduce the risk of sparking wildfires, but it is typically an expensive proposition. The California Public Utilities Commission surveyed investor-owned utilities and found the cost of undergrounding existing lines ranges from $1.85 million per mile to more than $6 million per mile in 2019 dollars.

DOE said the projects announced Jan. 16 will help to reduce the cost of moving lines underground, as well as increase the speed and safety of that work. Projects include:

• $3.7 million to GE Vernova Advanced Research for development of a “robotic worm tunneling construction tool” that can dig and install conduit and cables in a single step. The tool — called SPEEDWORM — could be deployed from a standard pickup truck, according to a DOE list of projects tapped to receive funding;
• $4 million to RTX Technology Research Center for development of a mobile sensing platform using radar approaches based on quantum radio frequency sensing, together with artificial intelligence, to locate existing utility lines;
• $4.5 million to Prysmian Cables & Systems USA for a hands-free power cable splicing machine that could fit into a utility access hole and use laser cutting and a vision system augmented with machine learning; and
• $3.75 million to the Pacific Northwest National Laboratory for development of an artificial intelligence system for processing geophysical survey data into digital twin and augmented reality to identify existing utilities and other subsurface obstacles before installing underground power distribution lines.

“DOE is supporting teams across the country as they develop innovative approaches to burying power infrastructure underground — increasing our resilience and bringing our aging grid into the 21st Century,” Secretary of Energy Jennifer Granholm said in a statement.

The Advanced Research Projects Agency-Energy focuses on high-impact energy technologies that are too early for private-sector investment. On Jan. 11, it announced up to $30 million in funding is available to improve the sustainability and commercial viability of fusion energy. And in December, it made $38 million available to enable transportation and storage of renewable energy through carbon-containing liquids.

Investor-owned utilities facing increased physical risks from climate change should adopt a three-pronged strategy that includes “reducing damages from physical events, minimizing litigation risk, and expanding capabilities for cost recovery,” S&P Global Ratings said in a November report.

Utility credit downgrades “directly related to physical risks have significantly increased” in the past six years, S&P said. And “the credit quality of utilities with physical risk exposure could come under even more pressure if comprehensive risk-reduction strategies are not effectively implemented.”

From 2005 to 2017, S&P downgraded two North American IOUs due to physical risks from climate change. From 2018 to 2023, it downgraded 19, including utilities impacted by the 2018 Camp Fire wildfire in California, 2021 Winter Storm Uri, 2021 Hurricane Ida, and the 2023 wildfires in Maui.

Utilities hit with downgrades this year include PacifiCorp and Hawaii Electric Light Co., while S&P also revised the rating outlooks to negative for Berkshire Hathaway Energy, Fortis Inc. and Xcel Energy subsidiary Public Service Co. of Colorado.

A major risk to utilities’ credit worthiness is “regulatory lag,” S&P said — the gap between when a utility incurs a cost and when it is recovered from ratepayers. 

“We believe it's important for the IOU industry to significantly increase and broaden recovery capabilities,” S&P said, including through the use of storm reserves, increased commercial insurance levels, self-insurance, development of special wildfire funds, and securitization. 

“We expect that the industry will continue to effectively manage regulatory risk with a focus on reducing regulatory lag,” Gabe Grosberg, managing director of North America Regulated Utilities for S&P Global Ratings, said in an email.

Most IOUs have already implemented some combination of decoupling, formula rate plans, forward test years, multiyear rate cases and regulatory riders over the past decade, Grosberg said. “We expect that the industry will remain proactive.”

Securitization — where utilities issue debt to cover costs, and that debt is secured by a non-bypassable charge on customer bills — is another way utilities can ensure cost recovery. “Because the debt is secured by the high likelihood of customers paying their bills, the associated interest costs are typically lower,” Grosberg said.

But while developing new avenues to recover costs will support a utility’s credit quality, S&P said “this alone without reducing damages from physical events or minimizing litigation risk, would likely not be sufficient to reduce credit risks.”

There are nine civil lawsuits pending against nine utilities because of wildfires, according to S&P’s report.

“While there are differences between states' standards of negligence, we consider litigation a material credit risk that affects the entire industry,” S&P said.