Grid Resiliency

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.

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By Ameresco

As triple-digit temperatures arrived ahead of the official start of summer once again this year, the U.S. is bracing for what has become an all-too-common pattern; a season punctuated by relentless heatwaves.  The extreme heat is not just a matter of comfort, it is downright dangerous – a public health threat. While air conditioning helps to beat the heat and stay safe, its widespread use often burdens the power grid. 

During significant heat events, spikes in energy demand from high air conditioning use are coupled with the fact that power generation and transmission become less efficient at these high temperatures. The weather patterns, energy loads, and infrastructure strain create a perfect storm. The need for a more sustainable solution could not be greater.

Integrating battery energy storage with renewables

According to the National Oceanic Atmospheric Administration (NOAA), April 2024 was the world’s warmest April since NOAA started keeping records 175 years ago, and 2023 was the planet’s warmest year on record by more than two degrees Fahrenheit. Despite being the hottest summer on record in the United States, the summer of 2023 was largely without power sector incidents. The grid held, and that reliability is in part thanks to an increase in renewable energy and grid resiliency resources – such as solar and battery energy storage systems (BESS).

Front-of-the-meter BESS are grid-scale energy storage technology that can be used in conjunction with intermittent renewable power sources like wind and solar. BESS firms those renewable resources to be used regardless of weather and time of day, extending their dependence on Mother Nature and supporting the integration of renewables into the larger grid.

What’s more, fossil fuel peaking plants that utilities often need to put online during periods of peak demand can be replaced with battery energy storage systems. This alternative can further reduce grid emissions by tapping into renewable generation instead of fossil fuel power in the energy supply chain.

An added benefit of transitioning to a BESS from a fossil fuel generator is the rapid response capability of the BESS – these systems can go from zero to full power within milliseconds.

Reducing transmission constraints

In May 2024, the Federal Energy Regulatory Commission (FERC) issued two orders to address transmission development slowdowns and ensure the grid capacity meets the needs of the clean energy transition. One of those, order 1920, requires transmission providers to plan ahead at least 20 years. In those plans, they must consider including several grid-enhancing technologies, including dynamic line rating, advanced power flow, and advanced conductors.

While commendable and impactful, FERC’s actions do not completely solve the complex problem of speeding up transmission buildout and improving grid reliability and flexibility. In many cases, a battery energy storage system requires no new buildout nor permitting of new transmission lines. 

As people arrive home later in the day and turn on appliances such as air conditioning, demand spikes. In the case of solar power, this often coincides with the time when generation is waning for the day based on the sun’s position. However, a BESS paired with solar power can shift energy usage to after sunset or during rainy or cloudy days, allowing energy to be stored and used later rather than being generated and consumed at the same time. The pairing can also address transmission voltage constraints with solar energy previously harnessed.

Enhancing grid reliability with BESS

Utilities across the U.S. are embracing energy storage technologies to bolster their grid’s resilience. One marquee example is United Power, an electric cooperative serving Colorado’s northern Front Range. By strategically locating battery arrays throughout its service territory, new energy storage technology will empower the cooperative to balance its load effectively while seamlessly integrating local renewable resources into their operations.

United Power is partnering with Ameresco to install battery arrays across eight different substation sites, cumulatively totaling approximately 78 MW / 323 MWh. The BESS will allow the cooperative to store and dispatch power efficiently during periods of high consumption. The best practices in energy storage are being put into action by United Power, enabling the cooperative to optimize its energy resources, enhance grid resilience, and ensure a reliable electricity supply for its members. The project is expected to be placed in service this year.

As renewable energy resources continue to multiply, so too will the importance of grid-scale storage technology such as battery energy storage systems. Energy storage supports the rapid acceleration of the clean energy transition whether its primary goal is to firm renewable resources, help ease transmission constraint, or boost the reliability of the grid.

National Grid on May 23 announced plans to invest $35 billion in New York and Massachusetts over the next five years to harden the region’s electric grid against extreme weather, reduce emissions and help the states meet their clean energy goals.

The investment represents an increase of more than 60% over National Grid’s previous five-year spending in the region and “follows positive engagement with our regulators in these states,” CEO John Pettigrew said in a statement.

The portfolio of projects includes more than 70 previously-announced transmission system upgrades in upstate New York, smart meters and grid hardening investments in Massachusetts, and an effort to accelerate gas pipeline replacements around New York City.

National Grid said its Northeast system buildout aligns with the U.S. Department of Energy’s transmission needs study, which concluded the region needs a 255% increase in transmission development to support clean energy plans in New York and Massachusetts.

The utility “is committed to playing our part in achieving the ambitious decarbonization targets that New York and Massachusetts governments have set,” Pettigrew said. “The increased investment we’re announcing today follows positive engagement with our regulators in these states, reflecting a willingness to upgrade electricity networks to provide long term affordable energy to all, and reduce emissions across our gas networks.” 

In New York, National Grid said it plans to spend about $21 billion between now and 2029 to improve reliability and resilience and expand deliverability of renewable energy across the state. The “Upstate Upgrade” effort includes new substations and rebuilding more than 1,000 miles of transmission lines connecting towns near Buffalo, Rochester and Syracuse.

“This landmark investment will transform the energy grid to meet growing energy needs and is a much-needed piece of the puzzle to support the clean energy transition,” said National Grid New York President Rudy Wynter.

National Grid is planning to spend about $14 billion in New England, including on its Massachusetts Electric Sector Modernization Plan to upgrade and expand the state’s grid, accelerate renewables interconnection and roll out new customer programs to encourage energy efficiency.

“National Grid is making it clear that we are a committed partner to help Massachusetts meet its climate and clean energy goals,” said National Grid New England President Lisa Wieland. “The investment is essential to transform the energy ecosystem, build new and expanded infrastructure, and deliver an electric network that is fundamentally smarter, stronger, cleaner and more equitable than today.”

Along with the electric system upgrades, National Grid on May 23 also said it has proposed a three-year investment plan in New York “to modernize the Downstate gas businesses, reducing emissions, and making them more resilient and reliable.”

The utility is targeting 45 miles/year of replacements in New York City and 119 miles/year on Long Island, with a focus on disadvantaged communities.

Extreme weather events, the changing resource mix, rising customer demands and geopolitical conflicts are increasingly straining the U.S. electric grid and exerting profound and unpredictable effects on the cost of and demand for energy.  

Overall electricity consumption is increasing at a furious pace; a report from Grid Strategies says it’s expected to grow 4.7% over the next five years, nearly double what utilities and grid operators expected. New electricity demands from cars, buildings, the onshoring of manufacturing and increased use of cloud computing, are driving this rise in demand. Data centers are being built across the country at such a pace that their energy consumption is expected to double by 2035.

Economy-wide electrification efforts, spurred by the Inflation Reduction Act, will also create new demands on the grid. According to a Princeton study, electricity transmission systems will need to expand an estimated 60% by 2030 and triple in size by 2050.

Meanwhile, our country’s vast network of transmission lines has, in many cases, reached or exceeded its intended lifespan. Our electric sector is at a crossroads as utilities and grid operators work overtime to decarbonize the grid and serve new loads to achieve greater security, reliability and affordability of electric power in the U.S.

Our current approach to grid management and buildout is not up to the task of dealing with such complexity. Developers and policymakers have rightly been considering a number of ways to better manage the grid, including technology to augment existing transmission lines, better known as Grid Enhancing Technologies, or GETs, and new kinds of conducting materials that make lines more efficient. In addition to these technologies, transmission planners, regulators, industry and policymakers must consider new solutions such as exploring how emerging technologies like quantum computing and artificial intelligence can help expand, modernize and upgrade the aging grid.

Quantum and AI can work together to address complex grid problems

The U.S. needs an expanded transmission system, with new well-planned regional and interregional transmission lines. Emerging technologies, including quantum and AI, can help ensure that an improved system is able to meet our evolving energy needs.

Solving transmission problems must be a multi-pronged approach. Together, quantum and AI could expeditiously and efficiently meet new challenges facing the grid, such as updating obsolete electricity infrastructure, efficiently integrating variable clean energy resources and deploying the lowest-cost energy source.

Meeting these new demands will require every tool and technology available — and quantum computing is an important part of the solution.

Optimizing the electric grid and infrastructure projects

Quantum computing in particular is uniquely capable of solving optimization problems. A federally established consortium of quantum industry stakeholders, the Quantum Economic Development Consortium, has examined the role of quantum computing for the grid. Their report identifies cases in the electric sector where quantum applications could have the highest impact.

1. Fault prediction – Quantum annealing, quantum neural networks and quantum generative adversarial networks can help utilities better predict energy grid failures, which allows them to fix problems before they occur. 
2. Energy market optimization – Quantum computers can determine when to switch on power generators and when to leave them idle. This would help minimize costs while meeting customer demand.
3. Integrated planning for a reliable and resilient grid – Quantum computers can balance distributed generation, future energy sources and placement of equipment, which will increase grid resilience.

These challenges are not unique to the U.S. Utilities and regulators around the world are exploring how quantum computing can help solve challenges facing the utility industry. For example, E.ON, one of Europe’s largest electric utility service providers, built quantum annealing applications targeted at managing the electricity contributions of prosumers within a grid. While the classical computing approach grappled unsuccessfully with the problem, quantum computing efficiently provided a robust grid-partitioning solution.

Quantum computing could also improve sites for new transmission infrastructure projects. In Japan, the government supported building a quantum-powered application that optimized a construction project by 10%, saving time and money.

Additionally, a recent study by Quantum Quants and the Netherlands Organization for Applied Scientific Research demonstrated that a combination of quantum and classical computing methods provided a robust and scalable solution for the efficient design and management of energy infrastructure.

Legislation must focus on near-term emerging technology solutions   

Any policy related to upgrading the grid must include a focus on deploying new technologies to make the most of these significant investments, including near-term quantum computing applications and AI tools that can help tackle electric grid challenges.

There are a number of bills before Congress that could improve development of transmission, move forward the use of technologies that could enhance transmission capacity, and increase grid security, resilience and reliability. In particular, the National Quantum Initiative Act, which expired in September 2023, must be reauthorized and expanded to include near-term quantum application development so the U.S. government can begin using quantum to address today’s complex scenarios, including those facing the electric grid.

Transmission issues will not be solved using yesterday’s way of thinking. A key component of any new policy should be developing and deploying cutting-edge technologies that utilities can begin using in the near term. Emerging technologies like quantum computing and AI are ready today and can be part of the solution to developing an affordable, secure and reliable grid.

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.

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.

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.