Grid Resiliency

The U.S. Department of Energy selected 38 projects for nearly $2 billion in funding from its Grid Resilience and Innovation Program, DOE said Oct. 18.

“With these projects, we're investing in resilience, which means we're supporting communities before, during and after wildfires and storms and heat waves and other extreme weather across the country by hardening the grid by, for example, undergrounding power lines or adding technology that reroutes power during storms,” DOE Secretary Jennifer Granholm said Oct. 17 during a press briefing.

The projects will boost transmission capacity by more than 7.5 GW, speed up interconnection for clean energy and spark over $4.2 billion in public and private investment, DOE said in a press release.

Under the Biden administration, DOE has sparked $36.9 billion in public-private spending on grid projects, according to Granholm.

In its initial funding rounds, including yesterday’s announcement, the $10.5 billion GRIP project has committed to $7.6 billion in funding while receiving applications for projects totaling about $50 billion, Granholm said. DOE plans to launch a third funding round next year.

Selected projects include:

• $160 million for Georgia Power to install grid-enhancing technologies, including dynamic line rating technology and reconductoring.
• $100 million for Exelon’s Renewable-Aware project that will deploy a distributed energy resources management system and Unbalanced Load Flow technology to optimize distributed energy resources across its service territory, with an initial focus on disadvantaged communities.
• $117 million for Hoosier Energy Rural Electric Cooperative and Southern Illinois Power Cooperative to build 69-kV or 138-kV transmission feeds to loop transmission to substations in seven counties in Illinois and Indiana that face increasing outages from extreme weather events and tornadoes.
• $50 million for GridUnity, which will use cloud computing and other advanced processes to speed up the grid interconnection process around the United States. DOE expects the project will cut interconnection times by more than a year on average.

In October 2023, DOE announced $3.5 billion in GRIP funding for 58 projects in 44 states. In August, the department announced an additional $2.2 billion for eight more selections.

The Southwest Power Pool board of directors on Oct. 29 approved a slate of 89 transmission projects with an estimated cost of $7.7 billion, aimed at addressing “reliability, economic, policy and operational needs” across its 14-state operating footprint

The 2024 Integrated Transmission Plan is the “single largest portfolio, in terms of size and value,” that SPP has proposed in its 20-year history, the grid manager said in a statement. The plan includes 2,333 miles of new transmission and 495 miles of transmission rebuilds.

SPP’s footprint “is facing a generational challenge as the need arises to balance new sources of demand, like data centers, crypto mining, mining, and oil and gas production, with the retirement of conventional resources that use coal and natural [gas] as fuel sources,” according to the plan.

The plan addresses “uniquely sharp load increases in New Mexico” by recommending a 765-kV line be developed from the panhandle of Texas to southeastern New Mexico, “delivering much needed energy to a remote area of the region.” Rapid load growth in North Dakota and South Dakota will be addressed through a network of new and upgraded lines across both states, it said.

SPP said its winter storm resiliency analysis also identified transmission projects that “improve system voltages throughout the approved target areas,” including transmission necessary for generation from outside of this area to reliably reach the loads.

“Increasing imports is especially important when the limited natural gas supply restricts local generation or transmission congestion prevents local generation from coming online,” the report said. “SPP also identified projects that increased the transmission system’s ability to transfer power from north to south within the SPP footprint by approximately 1.5 GW. This further increases resiliency against extreme winter storms by enabling SPP’s northern generation facilities which are hardened to withstand extreme temperatures to deliver power to the southern portion of SPP’s footprint.”

Ahead of the board’s decision, SPP said its Markets and Operations Policy Committee voted in support of the plan with 95% approval.

“The high degree of consensus among our stakeholders in support of such a significant infrastructure investment demonstrates the quality of this remarkable planning effort which is expected to provide significant value for years to come,” SPP Executive Vice President and Chief Operating Officer Lanny Nickell said in a statement.

The projects “are expected to quickly pay for themselves and provide benefits exceeding costs by a rate of at least 8-to-1 while improving grid resilience in the face of extreme weather events,” SPP said. By reducing costs, the projects will create savings of $10.55 to $11.47 on the average retail residential monthly bill, according to the plan. The projects are expected to be “cost beneficial within the first year of being placed in-service” and to pay back the total investment “within the first three years.” 

“The magnitude of the 2024 ITP is larger than we’ve seen before, but the time is right,” said SPP Vice President of Engineering Casey Cathey.

“We’re seeing a large increase in demand for power throughout the nation and our region. Events like Winter Storms Uri and Elliott have highlighted the need for increased transmission capacity to ensure that all customers continue to receive reliable electricity service in the most challenging times,” Cathey said.

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By Burns & McDonnell

Hurricanes, and other impactful events that cause utility outages, can wreak havoc on critical infrastructure. Extreme weather events have proven time and time again to be major threats to critical infrastructure service reliability. Electric vehicle (EV) charging infrastructure is no exception. Maintaining EV charging infrastructure operations is crucial to prevent fleets from becoming stranded and keep EV drivers on the roads.

As EV adoption accelerates rapidly, driven by environmental concerns, regulatory pressures and advances in vehicle technology, so too does the need to maintain reliable charging operations. Creating resilient EV infrastructure involves maintaining a commitment to designing robust systems that can withstand and adapt to unforeseen challenges.

A disruption in charging capability, no matter how short the duration, can lead to major operational delays, significant costs to restore infrastructure and missed opportunities to create additional revenue. From manufacturers struggling to deliver products to emergency services left stranded, the effects of EV charger outages can be widespread for those that depend on EVs operating.

It’s crucial to incorporate resilient planning early in the installation of EV chargers. Infrastructure design should not rely on a single point of failure, which could lead to widespread system outages. Maintaining consistent network connectivity is essential as disruptions in communication can limit operations even if power is still available.

The integration of backup power systems, such as battery energy storage systems (BESS) and renewable energy sources, combined with robust redundant design strategies, is essential to keep EV infrastructure operational. In the event that the electric grid is compromised, having a diverse portfolio of energy sources powering EV chargers can keep systems functional. This increases the overall efficiency and reliability of EV operations.

Those who prioritize resilience in EV infrastructure will benefit from a reduced risk of service disruptions and a stronger return on investment. EVs will be able to remain operational, especially in regions prone to natural disasters or power outages. Bringing in an experienced, integrated firm can be the next step to identifying and implementing a resilient EV infrastructure charging solution.

CenterPoint Energy has acquired generators sized between 230 kW and 5 MW to help restore power during future grid outages, the utility said Oct. 25. Larger generators were of little use following Hurricane Beryl in July, which led to widespread criticism of its storm preparations.

PA Consulting Group published a third-party assessment of CenterPoint’s Beryl preparation and recovery efforts last week. Its 77 recommendations included for the utility to acquire smaller emergency generation units. CenterPoint says it has completed or is in the process of implementing 51 of the recommendations and is assessing the remaining 26.

Following the storm, CenterPoint launched a $5 billion Greater Houston Resiliency Initiative to improve the local distribution system. “We heard loud and clear the calls for change and are acting with urgency,” utility President and CEO Jason Wells said in a statement.

Despite making dozens of recommendations for CenterPoint to improve its storm posture, PA Consulting’s analysis found the utility’s handling of Beryl to be on par with its peers.

CenterPoint’s preparation and response to Hurricane Beryl “were found to be generally consistent with industry standards, and its overall restoration time was comparable to its neighboring utilities,” the report concluded. It pointed to examples where the utility’s preparations, such as its acquisition of mutual assistance resources and the rapid deployment of staging sites and associated logistics, minimized recovery times.

Beryl “caused extensive damage” to CenterPoint’s electric infrastructure, primarily impacting the utility’s distribution system, according to the after-action report. The transmission system “proved resilient.”

The storm’s impact intensified as it hit Houston’s most densely populated service areas, and resulted in a high number of tree falls, many from outside utility easements, the report said. More than three-quarters of CenterPoint’s overhead distribution circuits experienced lockouts, and about 2.1 million customers were left without power.

Storm restoration took 11 days, which PA Consulting noted “was significantly shorter than the 17 days required for the company to restore power after Hurricane Ike [in 2008] and on par with peers during Hurricane Beryl.” About 78,000 CenterPoint customers were still without power after eight days after Beryl, the report noted.

Customer sentiment “declined from before the storm to after its impact,” PA Consulting added. “This negative feedback primarily arose from the communication challenges CenterPoint encountered throughout the storm.”

PA Consulting’s review “is invaluable,” said Wells. “Their recommendations will help us make the changes necessary to achieve our goal to build the most resilient coastal grid in the nation.”

CenterPoint said it has already completed 18 of the consulting firm’s recommendations. The utility has replaced its public-facing outage map with an improved tracker; revised communication strategies to focus on delivering essential information to customers; and acquired “additional smaller generators, between 230 kW and 5 MW in size, to enable greater use of temporary generators during future events,” it said.

Criticism of CenterPoint’s storm response included its emergency generation resources, most notably the decision to lease 32-MW generators that were not deployed post-Beryl due to their size. The large units “are used for transmission events such as load shed or loss of substation events,” PA Consulting noted. “These larger generators were not compatible with the types of sites that were requesting temporary generation; none of these were deployed during Hurricane Beryl.”

CenterPoint said it also is “in the process of” implementing 33 other recommendations from the report, including expanding the use of automatic reclosers across its distribution system to help automate restoration and increasing the use of composite poles capable of withstanding stronger hurricane-force winds. The utility said it is also revising its tree-trimming cycle “to be more proactive and responsive to higher-risk vegetation.”

CenterPoint said it is evaluating 26 additional recommendations from PA Consulting Group, “to assess what additional actions can be taken over the coming months ... or as part of our long-term resiliency efforts that will be announced in January of 2025.”

Recommendations under consideration include enhancing CenterPoint’s tree replacement program, assessing the feasibility of a customer communication solution that can both push alerts and receive reports from customers across multiple channels, and implementing a system to gather feedback regarding the effectiveness of the utility’s communication.

Electric utilities are developing a new understanding of how to plan for the increasing and worsening severe weather events like Hurricanes Milton and Helene.

The U.S. has experienced 24 events so far in 2024 “with losses exceeding $1 billion each,” and billion-dollar events have impacted all 50 states in the last decade, the National Oceanic and Atmospheric Administration reported. There were 20.4 events per year from 2019 to 2023, but that jumped to 28 events in 2023 that cost $95.1 billion, NOAA added.

And, as Houston, Texas, customers of CenterPoint Energy learned earlier this year, many utilities have only begun resilience planning and preparation.

Hurricane Beryl’s “over a million customer outages” showed “there is plenty of need for the resiliency hardening investments that utilities such as CenterPoint have proposed,” Wei Du, a PA Consulting energy and utilities expert and former senior analyst and engineer for New York City’s Con Edison, told the New York Times after the event.

A well-planned, resilient system can better withstand severe weather, said Andrea Staid, principal technical leader, electric sector climate resilience, for research consultant Electric Power Research Institute. New climate modeling and asset performance metrics “can show which utility investments would make previously disruptive events go unnoticed,” she added.

EPRI, utilities and analysts remain uncertain, however, about which climate and asset performance metrics and methodologies are needed to most precisely identify power system vulnerabilities.

What’s a resilience plan?

New frameworks are emerging to guide utility resilience planning.

“The utility industry is shifting from responding to an individual event to mapping vulnerability to financial risk and quantifying benefits of potential investments on four pillars,” said Aditya Ranade, Guidehouse director of energy, sustainability, infrastructure.

“The first of the four pillars is hazard mapping,” which identifies types of threats, from flooding to wildfires, Ranade added. And “a multi-hazard benefit cost analysis approach is the next level of planning sophistication,” he said. The second pillar is a vulnerability assessment quantifying utility assets’ vulnerability to climate hazards, Ranade said.

“The third pillar is financial risk, which is the sum total of values derived in hazard mapping and vulnerability assessment,” Ranade said. And “the fourth pillar is decisions on adaptation measures, like replacing wood poles with composite poles, elevating substations against floods, or dynamic line ratings, and that is done by comparing benefits,” he added.

These pillars can help utilities optimize their investments, but the final decision on what spending to approve “is up to state policymakers or regulators,” Ranade said. “The compromise between resilience and keeping rates low is determined jurisdiction by jurisdiction, by state regulators and policymakers,” he added.

Though no two utilities face identical risks, assessment frameworks help utilities understand “the specific sets of risks they must mitigate,” said PA Consulting’s Wei Du. “Data analytics of the risks of different events, like storms and wildfires, and how to mitigate them, follow the same frameworks,” he added.

Specific planning mitigations include system hardening and technologies to bring situational awareness closer to real time, Wei said. Planning can also include proactively obtaining more and more granular local meteorology data to know what impacts might occur where and strengthening engineering standards and building codes to harden infrastructure, he added.

Utilities need to improve “restoration performance as demonstrated in the storm restoration curve,” Wei continued. The steeper the slope of the curve, the more people are restored in less time, and the more effective the utility’s restoration preparations were, he said.

“Best practices are emerging with four dimensions of response,” said Judsen Bruzgul, vice president, climate resilience and Climate Center senior fellow at global consulting and technology services provider ICF. “Some things can be hardened to withstand events, like undergrounding and strengthening poles,” and “some impacts can be absorbed,” he added.

But the only answer to some events is “limiting the impacts with faster responses because hardening would be too expensive,” Bruzgul continued. “The fourth dimension is investing in resources like microgrids that can sustain communities and customers,” and are adaptable enough “to continue meeting new challenges over time,” he said.

“Proactively investing in resilience is often more cost-effective than rebuilding after an event," Bruzgul added.

There are similar resilience planning frameworks with similar prioritized preparatory mitigations in new papers from the Edison Electric Institute and the Pacific Northwest National Laboratory. But EPRI’s still incomplete Climate Resilience and Adaptation Initiative, or Climate READi, may be the most anticipated assessment, several utilities agreed.

A framework to ensure “science-informed modeling” in climate resilience planning and decision making as the climate changes is not available, said EPRI’s Staid. But in 2025, Climate READi will provide “a comprehensive set of climate informed models to evaluate adaptation investments,” she added.

Climate READi will include definitive climate data and metrics, guidance on asset vulnerability, and power system planning for resilience, Staid said. Data-based comparisons of options like asset hardening, installing new assets, or operating the system differently allows prioritizing and justifying the best resilience investments, she added.

“READi will not add new metrics to traditional planning,” Staid said. But it will show where there is “resilience planning data on the increasing frequency and severity of extreme events that wouldn't typically show up in a resource planning model,” and allow “planning for combinations of climate hazards” that can enable handling “a diversity of region-specific or even system-specific conditions,” she added.

Some utilities will await EPRI’s 2025 framework. Others, already facing climate impacts, cannot. 

Are utilities planning?

Regulators in 14 states, including California, Texas, Florida and New York, have resilience plan requirements for regulated utilities, according to a July study from Lawrence Berkeley National Laboratory. Through June, at least 30 utilities had filed resilience plans.

Best practices are emerging, and “just because there isn't a resilience plan requirement doesn't mean utilities aren't doing resilience planning,” said Lisa Schwartz, senior energy policy researcher and strategic advisor for LBNL’s Energy Markets and Policy Department and report co-author. But current utility resilience planning is limited, the research found. 

There is not a clear connection between the identified hazards and the planning horizons of many resilience plans and how those lead to the plans’ vulnerability assessment, said Josh Schellenberg, the principal and chief operating officer of H&S Insights and an affiliate in LBNL’s Energy Markets and Policy department, and report co-author. “That makes it difficult to know how the proposed mitigations will impact the risks,” he added.

Feedback from five utilities showed the different attitudes on resilience planning. Some are waiting for EPRI’s Climate READi, some are moving ahead with their own planning tools and data, some are using tools and data from other researchers.

The Duke Energy utilities in Florida and the Carolinas are using advanced technologies, modeling and self-healing systems as part of “a multi-year grid improvement strategy,” according to Duke spokesperson Jeff Brooks. It is also developing “self-healing technology to isolate problems when they occur and restore power,” he said.

Across its territories, Duke spent over $4 billion in 2023 on hardening and modernizing its system and will spend “around $75 billion over the next 10 years,” Brooks continued. Recent rates “do reflect those improvements,” but the utility has worked to keep increases “predictable and gradual over time,” he added.

Central Hudson Gas and Electric followed requirements of New York law to develop its vulnerability study and a resilience plan which is now under regulatory review, according to Jennifer Paull, Central Hudson senior engineer, electric distribution, reliability, and resilience.

The resilience plan outlines improvements “to address current climate projections, the state of our system, and resilience services from 2025 through 2044,” Paull said. The funding request for 2025 to 2029 is about $28 million total, which represents an average annual rate increase of only 0.06% for customers, she added.

Future investments may be larger because storms are clearly increasing in frequency and magnitude, Paull continued. “There is not a widely accepted methodology for comparing resilience investments to avoided costs” on which to base spending proposals, though “industry initiatives, like EPRI’s Climate READi, may change that,” she said.

PacifiCorp utilities operate in states like Utah with resilience requirements and states like Washington without them. It plans to spend over $10 billion on reliability and resilience programs over the next 10 years, Josh Jones, PacifiCorp vice president of asset management and wildfire strategy, said. “We don’t take rate increases lightly,” but “we cannot ignore” the risks and impacts of climate events, he added.

Arizona has no state resiliency requirements, but Arizona Public Service incorporates resilience into its planning, Yessica Del Rincon, its spokesperson, said. The utility has been investing $2 billion annually on “understanding and mitigating risks,” to minimize or avoid service interruptions, she added.

Though Washington state does not have resiliency planning requirements for utilities, Puget Sound Energy is a participant in the three-year EPRI Climate READi initiative, said PSE’s Director, System Planning - Clean Energy Strategy & Planning David Landers. The utility remains focused on near term planning and awaits EPRI’s 2025 guidance because science-informed long-term climate impact forecasting “isn't there yet,” he added.

Three elusive factors

Better resilience metrics, estimates of resilience benefits, and benefit-cost analyses of resilience investments require further research, utilities, analysts and the LBNL researchers agree.

“There is no perfect way to optimize across all factors, but traditional benefit-cost analysis is one way to prioritize investments,” LBNL’s Schellenberg said. “Impacts from factors that can be quantified can help determine the resilience investments of best value,” he added.

“It can be difficult to quantify the benefits of resilience investments or justify the increase in rates that they may lead to” because the costs of not doing them is an unknown, Schellenberg continued. But further analyses “of the full range of benefits for multiple events over longer planning horizons may show benefits many times greater than the costs,” by “preventing catastrophic impacts,” he said.

“Rates are already getting higher,” LBNL’s Schwartz acknowledged. “But stakeholder engagement upfront can communicate the fact that it’s not just the dollars upfront, it’s the reduced storm impacts that matter, too,” she said.

Resilience plans may be part of integrated distribution system planning, and show “a holistic assessment of all investments that contribute to customer rates,” Schwartz continued. But “climate risks need to be assessed frequently, so commissions need to move forward on standalone plans, too,” she said. Central Hudson’s Paull agreed.

EPRI’s Climate READi calls for including climate metrics in all resilience planning decisions, “whether in standalone plans or as part of integrated system plans,” EPRI’s Staid said. Either way, “it will result in more science-informed results that can improve resilience decisions and performance,” she added.

A heat dome such as the one that engulfed the San Francisco Bay Area in early October with temperatures soaring to over 100 degrees might well have put California’s power grid on the brink in the recent past. In fact, that’s exactly what happened in August 2020 when rolling blackouts led to unfortunate politicizing of renewable energy and misleading charges of unreliability in the run-up to that year’s presidential election. But you aren’t hearing the same claims from the anti-renewable energy peanut gallery today.

Time and again, it is not the underlying source of generation, but rather the surrounding infrastructure, which has often proven to be the key vulnerability. Be it the Marshall fire in Colorado, Hurricanes Helene and Milton in the Southeast, or the Lahaina fire in Maui — all regions where fossil fuel power plants are prevalent — it is the legacy grid and not clean power generation which has failed local communities.

It is time for the public to recognize this fact.

It’s true that more than 9,400 PG&E customers were left without power for part of one day during the most recent Bay Area heat dome due to PG&E’s Public Safety Power Shutoff program in select areas. But it would have been considerably worse were it not for California’s growing fleet of clean energy resources buttressing the region’s power supply.

Amid intense scrutiny and political pressure following the August 2020 brownouts, it would have been easy for California to renege on its clean energy ambitions. Instead, Gov. Gavin Newsom and state legislators doubled down, prioritizing “firmer” sources of cleaner power, such as battery storage and geothermal. A combination of improving market economics and targeted centralized procurement directives resulted in California adding nearly 9 GW of incremental clean energy — solar and wind in particular — and growing its fleet of battery storage by a whopping 22 times in the past four years.

The California Independent System Operator reported that solar and wind resources were responsible for meeting up to 40% of demand from Sept. 30 to Oct. 3 during the recent heat wave. The output from battery storage resources also peaked at 7 GW at 6 p.m. on Oct. 2, aligning perfectly with the height of electricity demand that Wednesday.

Customer consumption levels and patterns have also contributed to ensuring that the power grid remains an afterthought.

“Time-of-use” utility rate structures implemented by PG&E and others have successfully employed a carrot and stick approach to nudge customer power usage. Indeed, the power load during the worst of this last heat dome peaked at 40 GW, compared to the 47 GW peak in 2020, despite sizable growth in power demand from electric vehicle charging, data centers and heat pumps since August 2020. Smarter grid planning — particularly around coordinating imports, primarily hydropower — has rounded out a seemingly effective strategy.

All this has been achieved while keeping wholesale power prices relatively low. Based on CAISO data, prices averaged $55/MWh in Northern California from Sept. 30 to Oct. 3, well below the $80/MWh price during the Aug. 13 to Aug. 15, 2020, heat dome.

In fact, during some daytime hours over the course of the recent heat dome, prices at certain locations within California continued to be negative, a trend that has grown significantly this year. Northern California is on track to experience negative wholesale power prices in approximately 7% of all hours this year — primarily driven by increasing volumes of low-cost renewables — compared to just 2% across all of 2020.

That said, this latest bout of extreme heat is proving that we can increasingly and reasonably rely on renewable energy and storage to save us from catastrophic power outages even as the planet warms.

California has demonstrated that a key concern of the clean energy transition has to do less with the proliferation of clean energy, and more with the need to harden physical grid infrastructure. The California Public Utilities Commission released an independent report in 2023 showing roughly 60% of underground lines in PG&E’s territory exceeded useful life, with 20% of the structures suffering from unreported damage. Also, PG&E was only installing about 40 miles of new lines on average for the past seven years, well behind the report’s recommendation to install 800 miles of new lines each year. 

Fortunately, state regulators recognize this issue and have granted PG&E the approvals necessary to “future-proof” more than 2,000 miles of electric lines and spend more than $1 billion on vegetation management through 2026. Similarly, a public-private coalition that includes the California Energy Commission, CPUC, CAISO, PG&E and Southern California Edison received a $600 million federal grant for modernizing 100 miles of transmission infrastructure.

The hope now is for a broader, nationwide paradigm shift, which moves the focus away from the purported risks of clean energy and toward the need to strengthen the resilience of physical infrastructure.

The Midcontinent Independent System Operator and the Tennessee Valley Authority will be able to sell “emergency energy” to each other under a first-ever agreement filed Oct. 24 at the Federal Energy Regulatory Commission.

The TVA is not able to supply emergency energy directly to MISO due to restrictions in the TVA Act that limit exports only to neighboring electric systems that the federal agency had exchange power arrangements with as of July 1957, according to MISO’s filing. 

As a result, under the agreement, Ameren and Entergy — MISO members that meet the requirements of the TVA Act — will be able to buy electricity from the TVA during energy emergencies on behalf of MISO.

“Due to the changing configuration of the grid and recent emergency events, like Winter Storm Elliott, MISO and TVA have become increasingly focused on the need for additional coordination and planning to better ensure reliability in an emergency,” MISO said. “To that end, each has identified the need to purchase Emergency Energy from the other to maintain the reliability of each individual transmission system and, more generally, the integrity of the Eastern Interconnection.”

During Winter Storm Elliott in December 2022, about 7,000 MW flowed from MISO into the TVA’s region, according to a presentation by FERC and the North American Electric Reliability Corp. The TVA instituted nearly eight hours of rolling blackouts totaling 3,000 MW at their peak during the winter storm.

Under the agreement, emergency energy can only be requested when an Energy Emergency Alert Level 2 or higher has been declared, MISO said. The proposed agreement is similar to ones MISO has with other balancing authorities, the grid operator said.

“Emergency Energy is typically only called on in the most extreme cases when reliability is threatened and there are few options remaining,” MISO said. “Both MISO and TVA anticipate that there may be situations in the future that will meet this criteria and having the ability to purchase Emergency Energy from each other may be the key to enhanced grid stability and avoiding load shed.”

MISO asked FERC to allow the agreement to take effect on Dec. 24.

Increased wildfire risk has contributed to nearly 100 utility company credit downgrades since 2020, according to a report by global consulting firm Charles River Associates.

Lower credit ratings have made it more difficult for utilities to borrow money while insurance and wildfire mitigation costs have increased, the report states. These costs have largely been passed on to consumers in the form of rate increases, according to Andrew Dressel, vice president of energy at Charles River Associates.

However, wildfire mitigation practices seem to be effective in reducing utilities' legal risks. Credit downgrades have become less common in states that took early action to address wildfire litigation, Dressel said.

The increased risk of wildfire — and wildfire-related litigation — could significantly erode the financial stability of utilities in fire-prone areas, according to Charles River Associates. But emerging evidence suggests that public policy and utility-led wildfire mitigation efforts are effective in reducing these risks, Dressel said.

Credit rating agencies like Moody's, Fitch and S&P Global have recently downgraded a raft of utility credit ratings, often citing wildfire risk as a key factor in these decisions. Initially, the downgrades applied only to Southern California utilities, like Pacific Gas & Electric, that had been directly impacted by catastrophic wildfires, Dressel said. But the Labor Day fires in Oregon and the Marshall Fire in Colorado triggered another wave of downgrades throughout the West. Further downgrades are now expanding to the Southern Plains and the Southeast following the Smokehouse Fire in Texas, he said.

All in all, Charles River Associates tallied 99 utility downgrades by S&P since 2020, compared with 72 downgrades from 2016 to 2017 and just 34 from 2012 to 2015.

“Even Warren Buffet was saying utilities may no longer be a profitable business. Obviously, Berkshire Hathaway has made quite an investment over the years, so the alarm bells were ringing,” Dressel said. Berkshire Hatahway owns both NV Energy and PacifiCorp.

Unlike other natural disasters, like tornadoes or hurricanes, wildfires pose a particular risk to utilities because utility companies have been found liable for billions in damages when their equipment is found to have ignited the blaze, Dressel said. Wildfire frequency and severity is believed to be increasing as a result of a warming global climate and historic forest management policies that tried to suppress wildfire throughout the West and contributed to a buildup of dry, high-risk fuels.

But there is also reason to believe that actions to reduce wildfire risk in states such as California have had a measurable impact on utilities' bottom line. California has created a public wildfire insurance pool for utilities, for example, as has Utah, Dressel said. Utilities can buy into these pools to gain access to wildfire insurance in situations where commercial insurance may not be available, or could prove too costly to the utility.

These and other states have also required utilities to implement wildfire mitigation plans, and these plans seem to reduce the frequency with which utilities are found liable for igniting large wildfires, Dressel added. Although California has seen more wildfire ignitions this summer and fall due to hot, windy weather, the state so far has not seen any catastrophic fires triggered by utility infrastructure, Dressel said.

Those actions have contributed to a leveling-out of the wildfire cost increases, Dressel said. PG&E and Southern California Edison have seen credit upgrades in more recent years, while San Diego Gas & Electric has held steady, and this trend could spread as other states and utilities begin to take more proactive action on wildfire risk, Dressel said.

“One of the key takeaways is that this can be managed. It doesn't have to be the sword of Damocles over our heads,” he said. “We can take practical measures to reduce this threat. There are people working across industries and across government working to resolve this issue, and I think we are making progress.”

Resilience is the new buzzword in the energy sector. Amidst mounting threats of cyberattacks, terrorism and natural disasters, executives and security leaders recognize it is impossible to prevent every disruptive incident. Instead, energy companies must develop resiliency: the ability to adapt in a changing environment to survive and prosper.

But while many energy companies maintain business continuity plans, true resilience requires moving beyond this standard approach to become more innovative and adaptive in this heightened threat environment. As continued attacks put our national security at risk, achieving resilience for the energy sector is of dire importance.

How can the energy sector achieve resilience?

Resilience is still an emerging discipline. In 2017, the International Organization for Standardization identified several key attributes of a resilient organization: sharing information and knowledge; understanding and influencing business, political and social environments; and anticipating change. In essence, resilience begins with situational awareness. For energy companies, this requires a focus on three key types of information: threats, assets and national policy in Washington.

Solid insight into these three areas is a critical enabler to other activities an organization undertakes to improve resilience, such as business continuity, disaster recovery, emergency and crisis management, IT redundancy and more. Without this solid knowledge base, resilience planning will be ineffective.

Threats

Energy companies face growing threats from foreign adversaries like China and Russia, far-right terrorists, left-wing extremists and cybercriminals. These threat actors vary greatly in their motives — from sparking a race war to defeating the West — but have a shared understanding that attacking the energy system can advance their political objectives. As a result, energy is at the top of their target lists.

These bad actors employ a diverse set of attack methodologies, from small arms and explosives to cyber breaches and espionage. They are constantly identifying novel avenues of approach to put our energy system at risk. Take, for example, the risk that China could exploit its position as the largest manufacturer of solar panels to create back-doors in the U.S. energy system, expanding ongoing sabotage efforts across a growing renewables attack surface.

In this threat environment, intelligence is no longer optional. Energy companies need in-house intelligence capabilities to help them understand how these threats could impact the company’s assets and operations. This requires financial investment to hire the right personnel and onboard a mix of technology and consulting vendors that give perspective and insight. That said, energy companies should also take advantage of the many free and low-cost intelligence resources available. The Electricity Information Sharing and Analysis Center (E-ISAC), for example, has been so effective in generating intelligence sharing across the energy sector that it now serves as a model for ISACs in other industries.

Assets

In April 2024, the White House published a new National Security Memorandum on Critical Infrastructure Security and Resilience (NSM-22), which emphasizes the need to assess dependencies within and across critical infrastructure sectors. It also mandates that the government develop a list of Systemically Important Entities, companies with infrastructure whose disruption would have significant cascading impacts to national security.

This heightened focus on interdependencies and cascading effects serves as a needed reminder to energy companies to routinely update and maintain detailed maps of the assets they own, those upon which they rely, and those that depend on them. This begins with a thorough knowledge and risk-based prioritization of all the power plants, transmission lines, solar farms, storage facilities, etc. that the company owns or operates.

But mapping assets should also extend beyond the company itself. Energy companies rely on IT, telecommunications, water and other critical services provided by other sectors. What if one of those goes down? What will the impact be? Likewise, energy companies support other critical sectors — military bases, emergency services and more. What threats do those organizations face, and might their energy provider be targeted by someone looking to take them down?

Policy

We would argue that no private sector industry is of more concern to national security policymakers than the energy industry. Energy sector executives understand this and recognize the expectation from their customers to take any means necessary for the power to remain on. As a result, they are highly engaged with national security agencies like CISA, DOE, TSA and FBI — both to support resilience planning and so they know who to call when incidents occur.

The most resilient enterprises go even further, building internal teams dedicated to understanding national security policy at a deep level. This enables organizations to build more sophisticated resilience programs that focus on the future, not just the present. These national security teams work with policymakers (NSC, DHS, State, DOD), legislators (Congress), regulators (FERC, NERC), and industry associations (EEI, INGAA) in Washington to gain deeper insight into the government’s priorities and shape national security policy and new security requirements.

There is nothing untoward about this. Federal agencies have been encouraging active cooperation. Companies with strong leadership who value the private-public partnership have had success informing a more favorable regulatory environment and anticipating threats. These organizations provide a high standard of excellence the entire sector should strive towards.

Toward resilience

Adam Lee, vice president and chief security officer at Dominion Energy and a former FBI special agent executive, understands the value of situational awareness in building a resilient energy enterprise. Dominion Energy is the power company serving the Pentagon, Navy Yard, the Norfolk Naval Shipyard, the Loudoun Country data centers and other sensitive national security sites. “We’re the upstream target for all of that,” Lee notes, “and so we have to partner with those customers to understand their greatest risks and then we distill that information down to what it means for our resilience planning.”

Energy companies intent on building a more resilient enterprise should start, like Dominion, with enhancing their situational awareness capabilities. All the plans and playbooks make little difference if they fail to account for evolving threats, inter-dependent assets and dynamic government policy. Attaining this “information advantage” requires companies to make investments, especially in the areas of intelligence, asset monitoring, supply chain risk management and national security analysis.

But the responsibility for a resilient grid cannot rest on the private sector alone. Energy companies have made vast investments to provide a critical service to Americans. Government policymakers and legislators need to help because this existential fight is an American problem, not just an industry one. Government must expand efforts to provide timely and relevant information to the private sector and should address the financial burden borne by private sector companies to protect assets from national security threats. The battlefield is not level. The adversaries only need to be right one time, but the energy sector must maintain vigilance and resilience 100% of the time to keep the power on.

Lawrence Berkeley National Laboratory has released a new interactive decision framework to improve local and system-level grid planning amid anticipated load growth, adoption of distributed energy resources and state requirements that utilities file distribution plans, the lab said July 1. 

The framework builds on the Department of Energy Office of Electricity Delivery and Energy Reliability’s Modern Distribution Grid Project and aims to create a “shared understanding” among utilities, states and other stakeholders around longer-term distribution grid investments to ensure reliable, resilient and affordable electric service, Berkeley Lab said.

“We need really sophisticated planning tools to be able to address all of these factors,” said Joe Paladino, senior advisor in the DOE’s Office of Electricity, which sponsored Berkeley Lab’s work on the tool.

Distribution grid planning is more complicated than it was a decade ago, when utility regulators in California, New York, Hawaii and a few other states began thinking about how to manage growing DER capacity, Paladino said. With DERs far more widespread today, “almost everybody has to figure out how they’ll integrate and utilize them [to] provide grid services,” he added. 

Those efforts coincide with other emergent considerations like maintaining grid reliability amid a changing generation mix, hardening transmission and distribution assets against increasingly extreme weather, and managing “incredible load growth” from data centers, electric vehicles and building electrification, Paladino said. 

Additionally, sophisticated distribution planning is crucial in jurisdictions that require utilities to file some form of distribution plan with regulators, said Lisa Schwartz, the Berkeley Lab senior energy policy researcher and strategic advisor who led the interactive decision framework’s development.

Nineteen states plus the District of Columbia have such requirements, according to Berkeley Lab. 

“Now, regulators and other stakeholders are seeing plans for capital investments in advance, rather than just on the back end in rate cases,” Schwartz said.

Against this backdrop, bulk transmission planning alone may not lead to “least-cost, least-risk solutions” for energy system investments, especially given the potential for increasing DER capacity to reduce the need for additional transmission, Schwartz said.

The Berkeley Lab framework supports integrated distribution system planning, which the lab calls “a systematic approach to satisfy customer service expectations and state and utility objectives for grid planning and design.” 

Integrated distribution system planning “is a stakeholder-informed decision-making process,” with states and utilities setting objectives upfront, stakeholders like consumer advocates and community organizations engaging with the planning process, and all parties then working toward the “best solution set” that meets their shared objectives, Schwartz said.

The framework includes modules relevant to system-level planning, such as “system forecast and scenarios” and “resource and transmission planning,” alongside distribution-related modules like “Granular Locational Forecasts and Scenario Analysis” and “Current Distribution Assessment.”

“The framework ties together what typically are disparate [planning] processes for bulk and distribution grid planning,” Schwartz said.

The Berkeley Lab framework is structured as an interactive flow chart with modules and sub-modules detailing aspects of energy system planning. Each module and sub-module features plain-language explanations of their place in the planning process, and most also include definitions of key terms and frequently asked questions. Some have additional sections with explanations of stakeholder roles and responsibilities at each step, relevant state and utility practices, process-specific flow charts and links to relevant non-DOE tools and resources.

DOE hopes the framework helps state regulators and utilities with less integrated distribution system planning experience ascend the learning curve “rather than try to reinvent the wheel,” Paladino said.

“What Lisa has developed here will be a powerful, powerful tool for decision-makers,” he said. “[DOE] can’t tell people what to do, but we can provide them with best practices.”

Xcel Energy on June 27 filed a $1.9 billion wildfire mitigation plan with the Colorado Public Utilities Commission that includes adding hundreds of weather stations near power lines, updating pole and equipment inspection schedules in high-risk areas, and expanding its vegetation management program.

If the plan is approved, incremental bi-annual changes would increase a typical residential bill approximately 9.56%, or almost $9 per month, by 2028.

Xcel has been named in almost 300 lawsuits in Colorado alleging its power lines helped spark the Marshall fire which started in 2021 and caused more than $2 billion in damages. Xcel’s Southwestern Public Service also faces lawsuits in connection with the Smokehouse Creek Fire in the Texas Panhandle this year.

Wildfire risk has increased since Xcel filed its first wildfire mitigation plan in 2020, the utility told Colorado regulators.

“Doing more to mitigate wildfire risk requires substantial investment,” the utility said in its application. “Three of the five largest fires in Colorado history occurred in just the last five years, and Colorado endured two of the most destructive fires in that same time period.”

Based on the utility’s updated risk mapping, “the geographic areas of moderate to high risk in the Company’s service and facilities footprint have nearly doubled since the 2020 WMP.”

Wildfires are a growing risk for utilities, particularly as extreme heat and drought increase, and are making it more difficult for them to procure liability insurance. In 2019, Pacific Gas & Electric filed for Chapter 11 bankruptcy after fires caused by its powerlines burned hundreds of thousands of acres in Northern California and led to more than 100 deaths.

Xcel said its Colorado wildfire plan includes “a variety of new, expanded, and more targeted programs,” including a public safety power shutoff program to deactivate lines in times of high risk, and an enhanced powerline safety settings program that operates and re-energizes power lines in ways that reduce wildfire risks.

The plan includes using inspections to create 3D maps of equipment and terrain in high-threat areas and a multi-year program to identify and replace or upgrade equipment, underground some power lines, replace and repair poles, and rebuild transmission lines in high-risk areas.

“Our goal is to ensure that no catastrophic wildfire is started by Xcel Energy assets. And, while we’ve made significant wildfire safety progress in Colorado and achieved key goals, there is still work to be done to meet the evolving threat,” Bob Frenzel, president and CEO of Xcel, said in a statement.

The use of enhanced powerline safety settings will increase the number of feeders Xcel can set to “safety settings” remotely, sectionalizing lines in order to impact fewer customers when power is shut off, and adding equipment in high-risk areas and new technology to improve the program.

In its application, Xcel said its plan is similar to many of the measures being implemented in other utility wildfire mitigation programs in the Western U.S.

The proposed investments and approaches “create a comprehensive multilayered approach to wildfire risk reduction through increased awareness, system investments, operational activities, and customer engagement and resiliency measures designed to both prevent wildfire ignitions from utility infrastructure and limit the spread of fires regardless of their cause,” Xcel said.