Grid Resiliency

Oncor Electric Delivery on May 6 filed a System Resiliency Plan with Texas regulators, proposing $2.9 billion in capital expenditures and $520 million in operations and maintenance expenses to harden and modernize its grid, including addressing wildfire and cybersecurity risks.

If approved by the Public Utility Commission of Texas, Oncor said it plans to make the investments over a three-year period beginning in 2025.

The utility announced its first-quarter 2024 earnings May 7, reporting $225 million in net income compared with $103 million in the same period last year. The increase reflected new rates, increases in transmission revenues, customer growth and higher electricity consumption partially related to weather, the utility said.

Oncor is seeing significant growth in its territory, contributing to the company’s bottom line along with the need for system expansion and modernization, officials said May 7.

“This plan is not just an investment in infrastructure; it's an investment in creating a more secure and more intelligent grid that is better able to withstand and more quickly recover from the wide range of threats impacting our customers,” Oncor CEO Allen Nye said in a statement.

Oncor’s strategic plan includes more than $1.8 billion to harden and automate its legacy overhead and underground systems; approximately $510 million to optimize, expand and automate its distribution system; and $285 million to expand vegetation management efforts.

Another $525 million will go to cybersecurity, including to “enhance and secure Oncor’s digital backbone infrastructure and other measures,” the utility said. And $80 million is proposed for improvements to physical security, “including video and event correlation systems and asset protection.”

Approximately $900 million of the total system resiliency plan plan will enhance Oncor’s wildfire mitigation efforts, including $182 million in specific mitigation measures.

The strategic plan will allow Oncor “to advance and accelerate its wildfire mitigation strategies through additional investments in fire safe device deployment, advanced wildfire risk modeling, and strengthening, modernization and protection of assets in wildfire mitigation zones,” the utility said.

The plan “reflects our commitment to fortifying our infrastructure for the future,” Nye said. “This plan is not just an investment in infrastructure; it's an investment in creating a more secure and more intelligent grid that is better able to withstand and more quickly recover from the wide range of threats impacting our customers.”

Population and business growth in the state, and within Oncor’s service territory, “continues to be a driver of operational activity,” the utility said.

The Electric Reliability Council of Texas is anticipating about 152 GW of new load by 2030, driven by data centers, industrial electrification, electric vehicles and other sources, the grid operator said last month. Oncor said it anticipates approximately 40% of that new load to be located in its service territory.

In the first quarter, the utility said it added 18,000 locations served, compared with 17,000 in the same period last year. Oncor serves more than 4 million residences and businesses.

The utility also placed approximately $161 million of transmission projects into service in the first quarter of this year, compared with approximately $94 million in the same period a year ago.

“The continued growth across Oncor’s service territory resulted in the construction or upgrading of approximately 24 circuit miles of transmission lines and included 9 major substation projects and 3 major switching station projects, all being placed into service in the first quarter of 2024,” the utility said.

Oncor is majority-owned by Sempra Energy, which also reported first-quarter earnings May 7. Sempra, which also owns Southern California Gas and San Diego Gas & Electric, reported first quarter 2024 earnings of $801 million compared with $969 million in the same period last year.

Schneider Electric has announced a battery energy storage system that it says will act as the cornerstone for its fully integrated microgrid solution. 

The BESS, offered as part of Schneider Electric’s EcoStruxure Microgrid Flex system, incorporates pre-integrated components like batteries, inverters, a battery management system, a power conversion system and a controller, the company said in an April 25 news release. The BESS accumulates energy from different sources and stores it in rechargeable batteries for later use, with an ability to discharge that stored energy to supply power to industrial and commercial facilities as well as electric vehicles or the grid, per the release. 

The BESS can boost operational efficiency, facilitate demand change management and reduce overall energy costs, as it allows for storing energy during off-peak hours when electricity rates are lower and using it during peak demand periods, Jana Gerber, Schneider Electric's president of North America Microgrids, told Facilities Dive. The system can also reduce business disruption by providing backup power during outages, she added.

Building-level renewable energy and microgrid technologies are gaining steam amid a growing demand for uninterrupted and clean power supplies. Given a shift toward electrification, microgrid systems hold the potential for boosting energy efficiency and mitigating the effects of climate risk, which can help building owners and operators meet growing electricity demands, according to a December 2023 report from JLL.

Additionally, more organizations are looking to reduce their reliance on the grid, especially in the event of power outages and storms. Microgrids can provide efficient energy backup for reasonably long periods of time, with solar arrays capable of cutting buildings’ carbon footprints and boosting resiliency, according to Rohan Kelkar, executive vice president of global power products at Schneider Electric.

The BESS, embedded with a scalable configuration and advanced safety controls, provides bidirectional connectivity, giving operators the flexibility to operate either on or off the grid, Schneider Electric said. The company noted that the BESS can store energy for immediate access during outages and other power events, delivering between 60 kW and 2 MW of power in two-hour and four-hour configurations. 

The system’s features facilitate streamlined site engineering, construction and installation processes while minimizing labor and material expenses, the company said. 

“Historically, the industry has experienced significant difficulty in integrating battery products into microgrid systems,” Gerber said, noting that the BESS is incorporating a process to “test, validate and document the architecture of Schneider Electric’s system.” This has involved investing in a testing lab to vet the use cases that will be deployed in the field and linking the microgrid controls with battery use cases and physical hardware to ensure more structured commissioning of systems to reduce costs, enhance quality and “improve performance in a way the industry has not yet experienced,” she explained. 

Graybar, which is strengthening its focus on renewable energy, is the inaugural channel partner for the new BESS, Schneider Electric said. Graybar, a distributor of electrical, communications and data networking products, also specializes in related supply chain management and logistics services, with a network of over 300 distribution facilities across North America. 

The BESS is compliant with UL9540 certification and has a fire safety system designed to align with the latest standards outlined in NFPA 855, the National Fire Protection Association’s standard for the installation of stationary energy storage systems, Schneider Electric said.

The ready-to-deploy system consists of a documented architecture and enables an installation process that exceeds the efficiency of traditional custom-engineered designs, Schneider Electric said. The company noted that the solution’s integration with its energy management systems significantly reduces integration time and minimizes field errors.  

Effectively maintaining such a system involves “utilizing built-in solutions programs and features to help mitigate maintenance and support systems, as well as optimize operations through the solution’s monitoring system performance and battery health management,” Gerber said. “Additionally, the solution’s data analytics and performance management tools can be used for proactive maintenance,” she noted.

Two connection-ready BESS options are available — a small, hybrid seven-feet NEMA 3R Enclosure that can connect to both alternating current and direct current power sources, and a medium 20-feet NEMA 3R Enclosure that can connect to AC power sources, the company said.

Sponsored content

By Osmose Utilities Services

Situation

While inspecting a utility’s transmission network in 2017, an Osmose assessment crew encountered a lattice tower with significant corrosion at its base. Osmose engineers determined that the structure was at risk of failure and informed the utility. Before the utility could replace the tower, however, a tornado touched down nearby and the tower collapsed, leaving thousands of households in the dark and shutting down an important traffic artery. One of the impediments to a quick fix for the downed tower was the lack of construction drawings for the structure. Once a transmission tower is erected, years pass and metal components begin to rust, concrete foundations deteriorate, and hardware breaks and becomes loose. Additionally, record keeping is often lacking. Having on hand the original approved fabrication and erection drawings can be the difference between extending the structure’s lifespan through relatively inexpensive restorations versus an expensive replacement.

Solution

Although the downed tower could no longer be salvaged, Osmose recognized the structure’s failure as a call to action to offer a different option. By deploying a team to a similar lattice tower nearby, Osmose was able to collect ground-based LiDAR scans and 360 degree imagery. Using the data from the scans, Osmose engineers were able to create a three-dimensional digital model of the tower. The model mapped the entire structure and included such detailed information as steel member sizes and thicknesses within 1/16th of an inch. In fact, the model was so accurate that it included current damage due to corrosion including missing bolts and components. By importing the digital model into Osmose’s proprietary analysis software, the team was able to consider current load cases and custom (utility specific) loadings to the structure including wind load from 360 degrees.

Moving Forward

The digital model that Osmose engineers created can serve as a stand-in for the missing structural drawings and presents a new path for the utility toward structural resiliency.  With the digital model in hand, a utility is no longer forced to replace an aging tower simply because they are unsure of restoration options. When restoring a structure is an option, it is almost always more cost effective than replacement. Osmose’s advanced processes and analysis tools offer clarity on the magnitude of any structural concerns and a roadmap to restoring resilience without the expense of replacing a structure.

Osmose engineers were able to create a three-dimensional digital model of the tower. The model mapped the entire structure and included such detailed information as steel member sizes and thicknesses. In fact, the model was so accurate that it included current damage due to corrosion including missing bolts and components.

Artificial intelligence can help manage the U.S. electric grid, including reducing emissions and lowering costs — but the nascent technology poses significant risks if deployed “naïvely,” the Department of Energy said in a pair of reports published April 29.

Priority use cases for managing the U.S. electrical system include grid planning, permitting and siting, operations and reliability, and resilience, according to the “AI for Energy: Opportunities for a Modern Grid and Clean Energy Economy” report.

Similarly, four broad categories of grid risk have emerged, DOE said in a report titled “Potential Benefits and Risks of Artificial Intelligence for Critical Energy Infrastructure.” Those risks include adversarial attacks against AI systems, unintentional failures of AI models, the use of AI to execute cyber or physical grid attacks, and supply chain compromises.

“Artificial intelligence holds both incredible promise and potential challenges for the U.S. energy sector,” Puesh Kumar, director of DOE’s Office of Cybersecurity, Energy Security, and Emergency Response, said in a statement.

The assessments published April 29 were directed by an executive order President Biden signed in October identifying the administration’s core principles regarding the development of AI. The order also directed DOE and the Department of Homeland Security to assess AI systems’ threats to critical infrastructure.

Potential risks associated with AI include “poisoning attacks,” where an attacker could “add, modify, or alter the data used to train an artificial intelligence model, in order to force the model to learn the wrong behavior. This can include modifying data on energy system operations,” according to the CESER report.

A poisoning attack could result in an AI model misunderstanding what normal energy systems operations look like, the report said. More sophisticated attacks could alter training data “so that a model meant to detect physical wear in oil and gas equipment never declares an equipment to need maintenance.”

AI could also allow less-sophisticated adversaries to carry out cyber or physical attacks on energy infrastructure, CESER warned. 

The new technology could enable “autonomous control of devices for physical attacks,” the report said. “Adversaries could combine AI-enhanced capabilities with other technologies, such as unmanned drone systems, in order to execute remote physical attacks on energy infrastructure.”

There are also risks associated with the development of AI tools, the report found. Machine learning models created with “a mismatch between training data and real-world use” can skew outcomes in energy systems, CESER said. And the use of AI to make predictions about unexpected events, such as extreme weather, “can lead to unpredictable or inaccurate behavior.”

Ultimately, CESER concluded most of the risks “can be mitigated through best practices, putting appropriate protections around important data and models, and in some cases, funding further research on mitigation techniques.”

Beyond the risks, DOE officials say AI has the potential to help address climate change and improve grid resiliency.

“Artificial intelligence can help crack the code on our toughest challenges,” Secretary of Energy Jennifer Granholm said. The agency “is accelerating its AI work on multiple fronts to not only keep the U.S. globally competitive, but also to manage AI’s increasing energy demand.”

President Biden has set a goal for the U.S. electric system to be carbon-free by 2035. Achieving that, including managing large amounts of renewable and distributed generation, creates challenges that AI can help address, DOE concluded.

“AI offers significant opportunity to better maintain existing generation assets, forecast non-dispatchable generation and adjust flexible loads, and better inform operational safety,” the report said. Areas for use include matching load and supply; predictive, risk-based maintenance; and improvements to grid resilience.

“By predicting the impact of outages and optimizing the dispatch of repair crews, AI can help utilities restore power more efficiently,” the report said. It can also help with anomaly detection and equipment assessment.

“AI algorithms, particularly those based on machine learning, can infer the state of a system from limited measurements by leveraging historical data and probabilistic models, providing valuable insights where human analysis may be insufficient,” according to the report.

DOE also announced several AI-related initiatives alongside the release of the reports. The agency is: investing $13 million to build AI-powered tools to improve siting and permitting of clean energy infrastructure; establishing a new working group on powering AI and data center infrastructure; and over the next several months plans to convene utilities, clean energy developers, data center operators and regulators to discuss the impacts of load growth.

Experts say the power demands of artificial intelligence are growing rapidly.

Global power demand created by AI, excluding China, is estimated to reach 13.5 GW to 20 GW by 2028, Sreedhar Sistu, vice president of artificial intelligence offers for Schneider Electric, told a House subcommittee in October.  Of that demand, 30-45% is estimated to be in the United States.

Administration officials say the power demands can be managed, while the technology transforms the grid.

DOE wants to utilize AI to “address pressing needs such as enhancing the cybersecurity of the power grid, engineering new materials for batteries, and building the next-generation of grid-scale storage solutions,” Helena Fu, DOE’s chief artificial intelligence officer and director of the Office of Critical and Emerging Technologies, said in a statement.

A coalition of New England states announced April 17 it has submitted a pair of applications seeking federal funding for projects to support offshore wind, battery storage and expanded interregional transfer capacity.

Massachusetts, Connecticut, Maine, Vermont, New Hampshire and Rhode Island submitted an application to the U.S. Department of Energy’s Grid Innovation Program to support the Power Up New England project. And in conjunction with New York, those states submitted another application for the Clean Resilience Link project.

Power Up New England will utilize new and upgraded transmission points of interconnection in Massachusetts and Connecticut to access 4.8 GW of offshore wind and battery energy storage systems in Connecticut and Maine. The Clean Resilience Link features an interregional transmission upgrade “that would enable operation of a New York-New England transmission line at 345 kilovolts, increasing transfer capacity between the two regions by up to 1,000 MW,” the states said.

The applications include “robust” community benefit plans that describe what actions project developers will take related to community engagement; workforce development; diversity, equity, inclusion; and accessibility, the states said.

“The Northeast region offers DOE two compelling applications, highlighting our strong regional ties,” Massachusetts Department of Energy Resources Commissioner Elizabeth Mahony said in a statement.

DOE is expected to announce the awards in the fall.  

The Grid Innovation Program is managed through DOE’s $10.5 billion Grid Resilience and Innovation Partnerships program. Awards are capped at $250 million unless projects have a significant transmission investment, in which case they can receive up to $1 billion. Both New England projects proposed this week contain significant transmission investments, the states said.

Up to $1.82 billion in funding is available through this round of Grid Innovation Program funding; applications were due April 17. In October, DOE announced nearly $3.5 billion in awards under its Grid Resilience and Innovation Partnerships program to support 58 projects in 44 states.

The two New England Grid Innovation Program applications submitted this week “are the result of a whole-of-government effort to compete for federal funding, and close partnerships with our counterparts in neighboring states," Massachusetts Director of Federal Funds and Infrastructure Quentin Palfrey said in a statement. "The funding would be transformational for the development of renewable energy and grid resiliency across the entire Northeast region.”

National Grid, which serves Massachusetts and New York State, said March 20 it is investing $4 billion to upgrade upstate New York’s power grid.

That money will go toward 70 projects, which will include building substations and rebuilding more than 1,000 miles of transmission lines connecting towns near Buffalo, Rochester and Syracuse. National Grid plans to roll out these projects over the course of six years.

The utility said in a news release that the upgrades will allow the company’s transmission lines to carry more electricity and better handle extreme weather.

National Grid’s $4 billion “Upstate Upgrade” campaign is intended to improve resiliency and deliver renewable power to towns in Central, Eastern and Western New York such as South Oswego, Lighthouse Hill and Black River, the company said.

Climate change has increased the likelihood of extreme weather, and National Grid says upgraded transmission lines are necessary to better protect the grid from powerful storms and intense heat.

And the state of New York, which already generates more power from renewable energy than any state east of the Mississippi River, according to the U.S. Energy Information Administration, plans to add even more clean power to its grid in the coming years. The state has a goal of receiving 70% of its power from renewable sources by 2030. As of August, roughly 29% of the state’s electricity came from renewable sources, according to the state comptroller’s office.

“There is no transition without transmission,” Julie Tighe, president of the New York League of Conservation Voters, said in a press release. “Decarbonizing the state’s grid will require more than just generating wind, solar, and hydro power. We also need the poles and wires to deliver all that electricity to our homes and businesses.”

The upgrades should result in fewer power outages and quicker restoration of service if the power does go out, National Grid said.

“This six-year portfolio of work will transform the grid, improve reliability and resilience and enable us to deliver renewable energy to homes and businesses across New York,” National Grid New York President Rudy Wynter said in the news release.

In April 2022, the Department of Energy determined that transmission lines in the United States will need to grow by 60% by 2030 to meet heightened demand brought on by population growth and renewable energy projects that must be connected to the power grid.

The Inflation Reduction Act included $2.9 billion to upgrade transmission lines in the United States.

National Grid has announced eight projects so far. The Black River Clay Project is one of them. The endeavor involves rebuilding 62.1 miles of 115 kv transmission lines in Jefferson, Oswego, and Onondaga Counties in Central New York. Onondaga County is home to Syracuse. The project also involves the construction of a new substation in the town of East Watertown.

Another project involves rebuilding 20 miles of transmission lines in Western New York’s Monroe County, which is home to Rochester, the state’s fourth most populous city.

The campaign’s cost will be passed on to ratepayers over time, National Grid spokesperson Jared Paventi said in an email.

“Ratepayers won’t see any charges until the projects are in service and the costs will be recovered over the course of decades,” he said. “We expect the average monthly bill impact for a residential customer to be about as much as a candy bar.”

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.

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.

The electric power and natural gas sectors should collaborate on a “blackstart system restoration plan” to bring the grid back online in the event of a widespread blackout, a joint report released Dec. 19 by the Federal Energy Regulatory Commission and North American Electric Reliability Corp. recommended.

Most large generators require electric power to begin operations, but blackstart resources are capable of starting up on their own and are critical to system recovery in the event of a grid collapse.

Most blackstart resources utilize natural gas but FERC Commissioner Allison Clements has indicated she wants to explore how inverter-based resources, or IBRs, such as wind, solar and batteries could help with grid recovery.

The joint report focuses on Texas, and arises from the 2021 Winter Storm Uri report, which identified instances where blackstart resources “were rendered unavailable during the storm,” said study authors. But the recommendations could apply to any area.

Winter Storm Uri resulted in widespread blackouts and almost 250 deaths in Texas, but not a total grid collapse. The aftermath led to efforts to redesign Texas’ energy markets and strengthen the electric grid.

The study represents an “important milestone in cooperation and collaboration among federal, regional and state groups,” FERC Chairman Willie Phillips said in a statement. “I urge all regions of the country to review it because they, too, can benefit from its recommendations and observations.”

The report’s recommendations are voluntary. Along with coordinated development of a blackstart recovery plan, it also recommended entities charged with developing the plan “examine the diversity of fuel, single points of failure, fuel arrangements, and other limitations of each blackstart resource.”

The gas and electric sectors should work collaboratively “to develop this plan and should prioritize the natural gas infrastructure required to supply natural gas to the blackstart, next-start, and other essential resources,” Mark Henry, chief engineer and director of reliability outreach for Texas RE, told FERC in a Dec. 19 presentation of the report. Texas RE is the NERC regional entity for the area served by the Electric Reliability Council of Texas.

The report also recommended recovery plans “evaluate and incorporate, where feasible, a wide variety of options” including inverter-based resources, high voltage direct current ties, variable frequency transformers and other resources.

None of the blackstart resources in Texas’ recovery plan were wind, solar or battery resources, the report noted.

“I am interested in how IBRs could be used for blackstart preparedness and in finding solutions to support all resources with the capabilities to bolster grid resiliency,” Clements wrote on X, formerly known as Twitter.

“We want to make sure this commission is thinking about how we allow for these resources ... to provide this critical grid service,” she said during the meeting.

Batteries could be used as backup power systems to energize critical equipment at power plants, the report said.

“The team believes that with ongoing improvements in battery technology, batteries could make valuable contributions in emergency operations by providing support early in the blackstart system restoration as a power source, as a controllable load, and as a tool to maintain frequency and voltage,” the report said.

It goes on to recommend state and other authorities “assess the impact of a blackout on the natural gas supply chain” and develop an electric grid restoration plan “that meets the needs of both the electric and natural gas industries.”

“The natural gas supply chain may be severely stressed or completely unavailable during a blackstart system restoration scenario,” the report warns. “Stored natural gas may increase the likelihood of blackstart and next-start resources being able to secure fuel more quickly and reliably in the event of a blackout, which may be necessary to start system restoration.”

“Effective blackstart system restoration requires the necessary electric and natural gas entities to work collaboratively across multiple jurisdictions and functional responsibilities to restore the system,” Robert Clark, FERC co-lead of the joint study team, told the commission on Dec. 19. The report’s recommendations “are tailored to apply to all entities that play a role in blackstart system restoration,” he said.

U.S. utilities are grappling with a pressing challenge: their electric assets are located in areas that are becoming increasingly vulnerable to wildfires.

This vulnerability is twofold. Utility infrastructure, particularly transmission and distribution lines, has caused wildfires. At the same time, wildfires can damage utility assets, leading to significant power outages for consumers. The situation is exacerbated by climate change, with rising temperatures and drier conditions amplifying wildfire risks.

In parts of the Western U.S., data suggests that a 1 degree Celsius increase in average annual temperature could result in up to a 600% rise in median burned areas in some forest types. Additionally, the growing population in wildland-urban interface areas further intensifies the wildfire threat to communities.

Managing wildfire risk is a challenge

Utilities confront multifaceted hurdles in wildfire risk management spanning customer concerns, asset vulnerabilities and technological limitations. Customers bear the brunt of Public Safety Power Shutoffs, or PSPS, done to reduce the risk of causing wildfires during inclement weather, with vulnerable communities feeling the most impact. Additionally, the intricate maze of right-of-way issues and customer agreements often hampers access to transmission lines, pivotal for vegetation management and risk mitigation.

Aging assets, compounded by climate change, elevate wildfire risks. Diverse power systems complicate risk identification. Varied ownerships and regulations across jurisdictions further challenge standardized risk management, with many standards bypassing explicit wildfire mitigation.

To address the increasing risk of wildfire, utilities must embrace short- and long-term strategies that emphasize asset protection, real-time risk assessment and infrastructure investments.

Short-term operational strategies

Utilities should assess wildfire ignition and spread likelihood in near real-time, factoring in grid conditions and forecasted weather. This risk is influenced by weather, vegetation and moisture levels.

Enhanced weather stations offer granular data, aiding precise PSPS decisions. Cameras and imagery from satellites, like that provided by NASA’s Fire Information for Resource Management System, can help provide early wildfire detection. Effective communication with municipalities further aids rapid wildfire identification. Community risk also hinges on population density, infrastructure types and road layouts affecting evacuation capabilities.

To reduce wildfire risk seasonally, utilities should adjust grid control settings, implement PSPS during high-risk weather, complete annual vegetation management and introduce worker protocols for dry conditions.

Changing grid control settings, such as disabling reclosing switches, can minimize wildfire ignition risks, with some utilities having remote capabilities while others needing manual intervention. Effective PSPS involves accurate weather prediction, municipal coordination, pre-PSPS customer communication and thorough infrastructure assessment before reenergization.

For most utilities, the interaction of vegetation and the grid is the primary cause of interruptions and a significant driver of wildfire risk, so annual vegetation trimming is vital. Proper training and tools for utility work can further diminish ignition risks from field operations.

Long-term planning strategies

Long-term wildfire risk identification hinges on understanding grid vulnerabilities. Comprehensive asset inspections, data analysis and wildfire spread modeling are essential.

Notably, risk isn't uniform across the grid; for instance, PG&E found 95% of their wildfire risk in just 22% of their distribution line miles. Enhancing data capture from asset inspections and failures, even those not causing interruptions, is vital. It’s also critical to understand the potential for wildfires to ignite and spread, and how that risk may increase due to climate change. Climate projections can be used to understand potential changes in factors such as precipitation, drought, fire weather conditions, and fuel moisture, to characterize future wildfire risk.

The ICF report, Resilient Power: How Utilities Can Prepare for Increasing Climate Risks, estimated an investment gap of approximately $100 billion to address wildfire risk to utility grids. Long-term mitigation involves grid hardening, minimizing PSPS impact and refining vegetation management.

Understanding risk locations is foundational; using sensors to monitor grid health aids in preemptive action. Grid hardening focuses on upgrading high-risk components, with higher-cost strategies like undergrounding used selectively. Investments can reduce PSPS frequency, scope and duration, with technologies like emergency generators and microgrids offering localized solutions. Enhanced vegetation management, using tools like LIDAR and machine learning, aligns efforts with risk profiles.

Lastly, a well-coordinated wildfire response process, involving trained teams, local collaborations and clear customer communication, is imperative for risk reduction.

Utilities must take action to proactively mitigate wildfire risk

Utilities have been thrust to the forefront of wildfire risk management due to the location of their assets. They must take proactive measures to mitigate this risk. Luckily, they don’t have to do it alone.

Federal programs such as the Infrastructure Investment and Jobs Act and the Grid Resilience Innovation Partnership, or GRIP, include funding for grid resilience. We’ve seen the National Rural Electric Cooperative Association and 39 other co-ops across the U.S. selected to negotiate contracts for nearly $100 million under GRIP. That funding can accelerate high-priority wildfire mitigation projects.

To prepare themselves for this kind of funding, utilities should first make a wildfire mitigation plan that assesses wildfire risks to inform their investments and collaborate with all community stakeholders who could potentially be impacted, especially vulnerable customers. Understandably, California is in the vanguard for developing wildfire mitigation plans, due not only to tragic experiences but to a regulatory requirement by the California Public Utilities Commission, to draft and update such plans annually. But some utilities, such as Seattle City Light, are ahead of the curve. As a municipal utility in Washington State, Seattle City Light currently has no requirement to develop and publish a wildfire mitigation plan but has been an active participant in the legislative discussions about wildfire mitigation requirements and has drafted and published its wildfire mitigation plan ahead of a state requirement to do so.

Of course, there is no one silver bullet approach to mitigating wildfire risk. A portfolio of actions will be needed. PSPS, even to large swaths of the grid, may not completely prevent wildfires, as shown on October 26, 2019, when PG&E implemented power shutoffs to as many as 3 million people, but the company’s power grid still caused up to five wildfires. A portfolio of actions that improve capabilities across the dimensions of risk assessment and situational awareness, grid hardening, operational response and community engagement will be necessary to most effectively reduce wildfire risk.

This portfolio of actions should include deploying tech solutions. These solutions can make a big difference with a relatively modest investment. Utilities in California are using Protective Equipment and Device Settings, also known as “fast trip” settings, which are advanced safety settings implemented by electric utilities on powerlines to reduce wildfire risk. Southern California Edison began its fast trip program in 2018 and saw a 54% reduction in ignitions between circuits with fast trip enabled versus circuits without it.

Managing wildfire risk for utilities involves an effective balance of short- and long-term strategic approaches. It also requires vigilance and adaptability in the face of evolving environmental conditions and regulatory requirements. Ultimately, utilities that proactively manage wildfire risks not only protect their assets but also safeguard the very communities they serve

Owners and operators of some inverter-based resources, or IBRs, like wind, solar and storage are not following voluntary operational guidelines, which increases reliability risks to the bulk power system, the North American Electric Reliability Corp. concluded in a Nov. 30 report.

About 5,200 MW of bulk electric system solar IBRs have voltage and frequency protection settings within NERC’s “no trip zones,” meaning they are at greater risk of going offline in the event of a grid disturbance, according to the report.

NERC recommended development of two reliability standard projects to improve IBR performance, as directed by the Federal Energy Regulatory Commission in October, and said it intends to issue an alert in early 2024 to gather additional modeling information from generators and transmission owners.

NERC is tracking a growing list of examples where IBRs have tripped offline or reduced output in response to grid disturbances, and in March it issued an alert and recommendations for solar resources connected to the bulk power system. But the report published Nov. 30 finds those recommendations “are not being implemented.”

The March alert required owners of bulk power system-connected solar facilities to provide site-specific information by June 30 via a data submission worksheet. Many generators “indicated that they did not have the requested facility data readily available,” NERC said. “The information requested in the worksheet is fundamental equipment information that NERC expects would be retained and easily accessible with some assistance from equipment manufacturers if necessary.”

Responses also showed more than 5 GW of solar IBRs on the bulk power system have voltage and frequency protection settings within the “no trip zone” NERC set in PRC-024, the protection and control standards for generators.

NERC recommends that all IBRs “have parameterized protection settings outside of the ‘no trip zones’ based on maximum equipment capabilities” in order to ensure the resources do not trip offline when when they are needed to preserve reliability, according to the report.

But about a quarter of reporting facilities use a protection system “that results in an increased likelihood of inadvertent tripping during normally cleared grid faults,” NERC said. And because of the way these protections are modeled, the “risks would not be captured in interconnection studies or during annual planning assessments.”

About a quarter of facilities “use a fault ride-through mode that does not adequately support BPS reliability,” NERC added. And about a third use power capability modeling that indicates the potential for “a significant amount of underused reactive power capability” which can negatively impact reliability services like voltage regulation.

“For many years, NERC has been working collaboratively with industry to produce world class recommended practices to help ensure reliability around this evolving technology,” Ryan Quint, NERC’s director of engineering and security integration, said in a statement. “The findings in this report demonstrate that potential reliability gaps exist when those recommended practices are not implemented.”

As a result, NERC said it will make development of two new reliability standards a “high priority.” One will modify PRC-024 and another will set performance standards for IBRs to address “systemic” performance issues.

“This report reiterates the criticality of implementing these standards in a timely manner to ensure adequate ride-through performance of IBRs as well as proactive risk mitigation,” NERC said. It also recommended examining how FERC interconnection agreements and procedures can further support the reliable integration of IBRs.

“Less than one-third of the inverter settings reported are set based on equipment capability, showing that there is significant underused ride-through capability” across the bulk power system, the report concluded.

A NERC subcommittee focused on IBR performance will develop a standard authorization request and should also consider proposing commissioning requirements for IBRs, the report said. The request “might mention that the standard could be applied at commercial operation to ensure adequate risk mitigation steps occurred during the commissioning process,” it added.