Grid Resiliency

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.

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By Franklin Energy

The devastating wildfire in Lahaina, Maui. The floods in California. The historic heat wave in the southern U.S. Multiple tornados and hailstorms in the Midwest.

All of these weather and climate disasters occurred in 2023, and they took a toll on the nation’s electric grids. Excess heat and cold spiked customer demand. Floods damaged underground transformers. Hurricanes and blizzards pummeled utility poles and power lines.

Even the strongest grid would have trouble withstanding this meteorological onslaught, and the U.S. electric grid is far from strong. It’s patchwork and aging—in fact, according to the Department of Energy (DOE), 70% of transmission lines and power transformers are at least 25 years old.

Nevertheless, our beleaguered grids held up last year. Vox reports that on July 27, 2023, during the hottest month on the planet since at least 1880, electric grids continued to function despite energy demand across the continental U.S. being the highest ever recorded—reaching an hourly peak of 741,815 MWh.

U.S. grids were able to handle this unprecedented demand because of two main factors:

• Weather watchers predicted the scorching summer in advance, giving utilities time to forecast their energy use and alert customers.
• Grids were fortified due to increased reliance on renewable energy, especially solar and wind power.

Utilities’ role in grid reliability

That’s the good news. The bad news is these climate catastrophes are expected to continue.

“2023 is the fourth consecutive year in which 18 or more separate billion-dollar disaster events have impacted the U.S., marking a consistent pattern that is becoming the new normal,” reports the National Oceanic and Atmospheric Administration’s National Centers for Environmental Information.

And that means electric grid reliability is going to become even more important in the future.

Fortunately, electric utilities can help. Here are three key ways utilities can contribute to more resilient grids and play a pivotal role in the nation’s transition to a sustainable and electrified future.

Increasing reliance on DER

Distributed energy resources (DER), particularly distributed generation, battery storage, smart meters, smart charging, and advanced metering infrastructure, are already a reality for many utilities.

But University of Minnesota Research Fellow Matt Grimley, who is an expert in DER, said utilities have to address multiple concerns before their DER programs can make a significant impact on grid reliability.

A presentation at a June 2023 meeting of the DOE’s Electricity Advisory Committee (EAC) noted that in order for a utility to become DER-centric, it must address generation, planning, operations, and customer programs in new ways.

For instance, a traditional approach to generation would include integrated resource plans (IRP) with some demand-side management (DSM), along with a generation mix based solely on economics. A DER-centric approach includes making DER support of carbon goals part of the IRP and a generation mix that leverages DERs in the most cost-effective ways.

Meeting load-management standards

Different states have different utility load-management standards. Not surprisingly, California, which pledged that two-thirds of its electricity would be generated by renewable energy by 2023, has some of the most stringent standards.

California’s load-management requirements for large utilities and community-choice aggregators include:

• Detailing rates in the publicly available and machine-readable Market Informed Demand Automation Server (MIDAS) database
• Developing a standard rate­-information access tool for third-party services
• Developing locational rates that change at least hourly to reflect marginal wholesale costs
• Including information about new time-varying rates and automation technologies in customer education and marketing materials.

Franklin Energy is a leader in helping utilities adjust to new load-management standards. Here’s how we helped a large California utility leverage residential measured pay-for-performance to deliver grid reliability.

Leveraging demand response

Demand response programs can not only help lead the shift to sustainable energy, but they can also improve grid reliability in two important ways:

• Empowering customers to manage their power consumption during peak-demand periods
• Integrating renewable energy into the grid by aligning customer demand with resource availability

As the energy landscape continues to evolve, demand response will play an even more significant role in grid management. The integration of advanced technologies such as smart grids, IoT devices, and machine-learning algorithms will further optimize demand response programs, enabling more accurate forecasting and real-time adjustments.

While getting demand response programs right may appear complicated on the outset, it doesn’t need to be. Here’s an example of how Franklin Energy helped a large Missouri utility implement Peak Time Savings, a demand response program that adjusts customers’ smart thermostat settings during weather events. 

The bottom line

U.S. electric grids face more pressure than ever before. But utilities don’t have to be the victim of grid unreliability. Contact Franklin Energy to learn how our programs can help you navigate our evolving environment and manage the grid of the future.

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.

The U.S. Department of Energy on Oct. 18 announced nearly $3.5 billion in awards under its Grid Resilience and Innovation Partnerships program, known as GRIP, to support 58 projects in 44 states. When matched with private and local investment, officials said the awards will support a total of $8 billion to expand and strengthen the nation’s electric system.

It is “the largest ever investment in America's grid,” said Energy Secretary Jennifer Granholm. Billions more in future GRIP funding is planned.

The smallest of yesterday’s awards include smart grid grants of around $1 million to individual cities, and the largest is $464 million to support the construction of five transmission projects across seven Midwest states. 

More than half of U.S. transmission lines and power transformers were installed before 1970 and the outdated grid is vulnerable to the increasing impacts of the climate crisis, said DOE officials.

The bipartisan infrastructure law made $10.5 billion available to DOE’s Grid Deployment Office for GRIP. The program aims to help mitigate wildfire and other climate change risks, unlock stranded renewables projects, and boost the flexibility, efficiency and reliability of the nation’s aging electric power system.

“This round alone is the largest ever investment in America's grid,” Granholm said. “It's going to enable more than 35 GW of renewable energy on the grid and it will also boost the current renewable capacity as well by more than 10% within this decade.”

The program represents a new approach to grid upgrades, a senior DOE official told reporters.  All of the awards have stipulations in place between community groups and developers, known as Community Benefit Agreements, agreeing to local benefits in exchange for project support. 

“Historically, grid upgrades have not necessarily involved a ton of community engagement and we're trying to change that paradigm through this process,” the official said. “By asking people to engage from the Justice40 perspective, and engage with disadvantaged communities, [projects] are much more likely to be built.”

President Biden’s Justice40 initiative calls for 40% of the benefits of certain federal investments to flow to disadvantaged communities that are marginalized, underserved and overburdened by pollution.

While energy siting reform remains a work in progress, “the funding itself makes these projects almost irresistible,” Granholm said. “We've gotten huge support from states, from localities where the proposed projects will be.”

DOE received 700 initial concept papers for GRIP projects, and then encouraged 300 different organizations to make full applications. The awards announced Oct. 18 are not final and still require applicants to undergo a negotiation process with the agency.

The largest award will support the Joint Targeted Interconnection Queue portfolio, known as JTIQ, involving construction of five transmission projects across seven Midwest states. The projects are in Iowa, Kansas, North Dakota, Nebraska, Minnesota, Missouri and South Dakota, and will support resource adequacy in the Southwest Power Pool and Midcontinent Independent System Operator territories.

“The costs and uncertainty of the system upgrades have become one of the biggest bottlenecks for developing new renewable energy projects in the upper Midwest,” DOE said in a description of the project. “The JTIQ Portfolio project overcomes many of these challenges and provides numerous interregional benefits, including scalable transmission solutions, new renewable generation, lower energy costs, enhanced community engagement, and workforce development.”

Xcel Energy is developing two of the JTIQ projects and said the GRIP award would help advance that work.

“Unprecedented growth of utility-scale wind and solar projects in the central U.S. has created a bottleneck in the process of interconnecting new generation,” the utility said in a statement. “Right now, the transmission system along the locations where MISO and SPP meet is at capacity, and upgrades are too costly for individual energy developers.”

The GRIP award “is a critical step” in DOE’s efforts to expand the nation’s transmission capacity, increase connectivity between regions and add more clean energy, John Moore, director of the Sustainable FERC Project at the Natural Resources Defense Council, said in a statement.

“A larger grid is a resilient grid, and the funding for planning and coordination from today's grants will go a long way toward accelerating these efforts,” Moore said.

Entergy New Orleans celebrated its award of $55 million to fund the utility's Line Hardening and Battery Microgrid project, which it said will enhance the local grid’s resilience against storms.

“This is a huge win for our customers, for our community, and for the City of New Orleans,” Deanna Rodriguez, president and CEO of Entergy New Orleans, said in a statement. “Federal grant funds at this scale will enable us to make our grid stronger ... These funds will help offset the cost burden on our customers.”

The National Rural Electric Cooperative Association and a consortium of 39 cooperatives were tapped to receive nearly $100 million for wildfire mitigation.

“This infrastructure funding is an important step as electric co-ops work to harden systems against wildfires and enhance the reliability of the grid. These projects hold tremendous potential for local communities,” said NRECA CEO Jim Matheson. 

As an increasing supply of renewable energy resources requires greater reliability and resiliency for the power grid, virtual power plants are emerging as one way to ensure the supply of electricity always meets the demand.

“In the future, grids are going to need to be much more flexible,” said Severin Borenstein, faculty director of the Energy Institute at the Haas School of Business at the University of California, Berkeley, and a board member for the California Independent System Operator. “They’re going to use a lot of intermittent renewable energy, and they’re looking for ways to allow the system to easily and smoothly adapt to those fluctuations.”

VPPs are one way to address intermittency, an issue with wind and solar energy, by storing excess energy that’s sent back to the grid when solar panels and wind turbines aren’t generating electricity.  

“If prices start to spike [or energy supplies are constrained] we can look and say ‘hey, we have a resource within this region’ and we can press a button and call on that resource,” said Reg Rudolph, chief energy innovations officer for the Tri-State Generation Association.

However, even as VPPs proliferate, pinning down the meaning behind the term “virtual power plant” is difficult. Not everyone agrees precisely on a definition of “virtual power plant,” experts and industry insiders say.

“There is a lot of ambiguity in the market as to how they are defined by different vendors,” said Alex Pratt, vice president of business development for the California-based software company AutoGrid.

Pratt provided one such definition.

“A virtual power plant is an aggregation of distributed energy resources that is utilizing software to manage and orchestrate the resources to provide, as much as possible, the same grid services that a centralized power plant would,” he said.

A VPP can be as simple as a group of households with smart thermostats that a utility can adjust when demand strains the power grid. But VPPs generally involve several storage batteries connected to solar arrays or wind turbines that can work together to send energy back to the power grid.

“The idea of a virtual power plant is that in the heat of the summer, when you’re running your generation at full bore, you can hit a button and send a signal to larger loads and create 200, 300, 500 MW of virtual capacity,” said Rudy Garza, president and CEO of CPS Energy in San Antonio, Texas.

The concept has been discussed for decades, but utilities are looking more to VPPs as the use of battery storage increases.

“Once [a household or business] has a battery in place, the grid operator is saying ‘wait a second, we could benefit if we could use that battery on the worst day of the year,’” Borenstein said. “We could know that we could dispatch that battery right when we need it.’”

Several utilities are finding ways to encourage VPPs. The Sacramento Municipal Utility District, for example, provides a subsidy for anyone with battery storage who wants to join a virtual power plant, Borenstein said.

Virtual power plants are similar to microgrids because both can generate their own power. But microgrids are designed to run separately from the power grid, while virtual power plants are part of the grid.

Microgrids are intended to keep critical facilities such as hospitals online during blackouts.

The precise number of VPPs remains a matter of debate, but advancing technology and evolving regulations means the nation will almost certainly see more of them in the coming years, experts say.

How many are there?

The number of virtual power plants in the United States depends on how the term is defined, and with no precise meaning, regulators have yet to conduct their own count.

“Many companies include or remove criteria to enable them to be part of the picture,” said Ben Hertz-Shargel, global head of grid edge for energy research and consulting firm Wood MacKenzie.

But at least one independent assessment exists.

Wood MacKenzie calls a virtual power plant an aggregation of resources. Some or all are behind-the-meter and function together to provide some type of grid service.

“They need to be dispatchable,” Hertz-Shargel said. “They don't need to be able to hit a certain price point, they can be weather-dependent and can incorporate multiple technologies.” 

By that definition, the United States has more than 500 virtual power plants, with an outsized number, about 150, in California.

“There’s a lot of stuff that’s unique to California that would necessitate this,” said Ahmed Mousa, the utility of the future manager for Public Service Electric & Gas Co. in New Jersey.

For example, the unusually high price of energy in California requires novel ways to generate and deliver inexpensive power, and frequent wildfires mean that utilities need power sources to draw from when fires cause blackouts, he said.

What does it take to make more of them?

By all accounts, VPPs will proliferate as efforts to add renewable energy to the grid take on a greater sense of urgency.

But the logistics of virtual power plants are the most daunting barrier. VPPs require power generation and storage in multiple locations and software programs capable of connecting them to the power grid.

“There's a project development phase, akin to putting steel in the ground, that’s the biggest barrier,” Pratt said. “You need assets, and you need things that can be controlled.”

What are the benefits?

When asked about the benefits of a virtual power plant, experts and industry insiders have a common refrain: A lower carbon footprint.

A power grid relying on renewable energy needs a reliable source of power when the weather doesn’t cooperate, and virtual power plants are one way to achieve that reliability.

Virtual power plants or microgrids have numerous objectives, said Santiago Grijalva, the Georgia Power Distinguished Professor for the School of Electrical and Computer Engineering at the Georgia Institute of Technology. 

“One is resilience. If power goes out, or there’s a disruption in the grid,” a VPP can provide power to a small number of customers.

By storing energy during excess generation, VPPs reduce the risk of power outages. Having more points of generation makes VPPs more reliable, Mousa said.

“You have to have some contingency,” he said. “You can’t rely on three customers, because what if they are not available?”

Another objective, Grijalva said, is sustainability. Packaging solar panels with storage batteries — as many VPPs do — makes solar more valuable, encouraging more utilities to use them and providing more power with fewer emissions of planet-warming gases.

The benefits to customers depend on where they live. Net metering rules that pay rooftop solar users for excess power change from state to state, but households who install solar panels almost always stand to benefit when those panels produce more power than they need.

“Our customers sign contracts through our demand response program,” Garza said. “We pay them what the market price is for power like we would when we go out and buy power in the market.”

How FERC order 2222 will help

Regulations are changing at the state and federal levels to clear the way for more virtual power plants

For example, in 2020, the Federal Energy Regulatory Commission ordered regional transmission organizations and independent system operators to let distributed energy resources participate directly in wholesale markets by 2026.

“And they allowed aggregation,” Mousa said. “All of us can work together to make up the virtual power plant.”

Once fully implemented, the order will be a boon for virtual power plants, which fall under the definition of distributed energy resources, experts say.

“It’s going to be a gamechanger,” Mousa said.     

Visuals Editor Shaun Lucas contributed to this story. 

Utilities are preparing for unprecedented demand growth from electric vehicles but say it is a “misconception” that the power grid will be overloaded and become unstable. New system planning and load management tools must be developed, but EVs are a flexible load that experts say can improve grid resilience.

A policy brief published July 24 by the Zero Emission Transportation Association examines key energy considerations associated with the rise of electric transportation, and provides case studies of how major utilities are approaching the EV transition.

In California, Pacific Gas & Electric has almost 500,000 electric vehicles in its territory and anticipates 3 million by 2030. They are a “critical piece” of PG&E’s strategy going forward, Nick Morelli, a strategic analyst of decarbonization strategies at the utility, said July 24 in a discussion hosted by ZETA.

PG&E expects system demand to increase up to 70% over the next two decades as more EVs are added. To meet that demand efficiently, the utility developed a forecasting tool and integrated it into its distribution planning processes.

“A common misconception that we hear a lot is that the grid is not ready, or that increased loading from electric vehicles will overload the system,” Morelli said. “It's definitely true that electric vehicles will represent unprecedented load growth,” but the flexibility of EV charging “actually provides a great opportunity to improve resilience.”

EVs in the United States consumed 6.1 TWh of electricity in 2021, according to ZETA, a group advocating for full EV adoption by 2030. An additional 15-27 TWh of annual new power generation will be needed between now and 2050 to meet growing demand from electric transportation.

“History has proven increases of this magnitude to be accomplishable,” according to the group’s policy brief. New renewable and zero-emitting generation resources will be needed, along with strategies to manage load and the streamlining of regulatory processes to interconnect resources.

PG&E initially relied on customer applications to understand where additional capacity was needed, but has since developed more proactive tools, said Morelli.

“The reactive approach worked relatively well for utilities in the past as you avoid stranded assets,” Morelli said. “But just due to the speed that loads materialize ... instead of taking that peanut butter approach of just spreading and disaggregating load across our system, we individually analyzed the most common segments of electric vehicle charging and we developed an adaptable forecasting tool.”

Of the 3 million EVs expected on its system, PG&E says 2 million will be integrated with the grid: participating in time-of-use rates, managed charging or vehicle-to-grid bidirectional charging programs.

South of PG&E’s territory, Southern California Edison officials also say EVs represent an opportunity. The utility has more than 430,000 EVs in its service area.

“One of the big misconceptions I hear ... is that EVs will negatively impact grid resilience,” said Chanel Parson, director of SCE’s building and transportation electrification programs. But a typical passenger vehicle is only operating a fraction of the day, leaving up to 23 hours when it could be charging or discharging back to the grid, she said.

“Flexible load can help utilities balance the natural daily peaks on the grid, and make the grid more resilient by exporting load to the grid or removing home and building load,” Parson said. Today, SCE utilizes vehicle-to-grid applications in emergencies but is “setting the groundwork” to make it a common strategy, she said.

The utility also offers infrastructure programs to fund and install utility and customer-side infrastructure, vehicle rebate programs and customer advisory services, she said.

But to continue advancing the transition, utilities say they need greater certainty around the state and federal government’s commitment to EVs in order to advance grid upgrades and build out capacity. And persistent supply chain issues must be addressed.

“We are seeing long lead times and exponentially higher costs for critical equipment that support grid stability and EV infrastructure,” Parson said.

Regulatory frameworks that allow utilities to invest “proactively” are important, said Cliff Baratta, Consolidated Edison’s electric vehicle strategy and markers section manager. The utility serves New York City and is preparing for 230,000 EVs in its territory by 2025. Since 2017 it has been working to encourage grid-beneficial charging through its SmartCharge program, which offers incentives for drivers to avoid charging during peak times.

“Here in New York, we're meeting all electric service requests for EV chargers and the impact on the grid has been limited so far,” Baratta said. “When we look out several years, it's going to become a challenge. We anticipate extremely large loads coming.”

Despite previous warnings, U.S. power plants remain vulnerable to not working during bitter cold, according to an initial assessment of Winter Storm Elliott prepared by the Federal Energy Regulatory Commission and the North American Electric Reliability Corp.

About 70,000 MW was unable to run in frigid weather in late December across the Midwest and Eastern United States, leading to rolling power outages of more than 5,000 MW in the Southeast, according to a presentation at FERC’s monthly meeting June 15.

The majority of power plant outages during the cold snap were caused by problems with freezing, fuel supply, and mechanical and electrical issues, FERC staff said, noting those problems occurred in the last five major extreme cold spells that have happened in the U.S. since 2011.

Like in Winter Storm Elliott, there was a sharp drop in natural gas production and electric use was higher than forecast in some areas during some of those cold events, according to the presentation.

The need to weatherize power plants and other recommendations issued after previous cold weather events remain valid and if they had been fully implemented would have eased the problems during Winter Storm Elliott, FERC staff said.

"We're seeing the same three causes, so therefore we think that it makes all the sense in the world to continue full steam ahead on implementing prior recommendations," Heather Polzin, reliability coordinator for FERC’s enforcement office, said about power plant outages.

Anticipating grid vulnerabilities is becoming harder in the face of extreme weather, according to FERC Commissioner Allison Clements.

“It shows that reserve margins are an increasingly inadequate tool to predict winter sufficiency,” she said. “Two of the regions that suffered rolling outages during Winter Storm Elliott — TVA and Duke [Energy] — were not even identified in NERC’s 2022-23 winter assessment as anything more than a low risk of load shed.”

FERC Commissioner Mark Christie said weatherizing power plants raises market issues.

"It's fine to mandate weatherization, but you can't separate that issue from the issue of market design, and how do you pay for it?" Christie said. "Weatherization requires capital expenditures. Energy markets don't compensate for capital expenditures. That's what the capacity market was set up to do."

NERC oversees grid reliability, but no entity is responsible for making sure the gas system is reliable, FERC acting Chairman Willie Phillips said.

"I believe this is a reliability gap," Phillips said during a media briefing. "I, once again, call for some entity to have responsibility for the gas system's reliability. It doesn't have to be FERC, but someone needs to have responsibility for that."

With support from FERC and NERC, the North American Energy Standards Board is considering options for better harmonizing the electric and natural gas systems.

In the first of three planned meetings, the NAESB Gas-Electric Harmonization Forum meets June 16 to discuss 19 proposed recommendations for better meshing the gas and power sectors. The recommendations call for increased information sharing between power plant operators and pipeline companies. They also call for a study to determine if the natural gas system can meet future power plant needs.

Separately, FERC approved two rules June 15 that aim to improve grid reliability during extreme weather.

One rule directs NERC to require transmission system planning for extreme heat and cold weather over wide geographical areas, including studying what would happen if power plants and transmission equipment go offline at the same time. Grid planners would have to take actions to address any issues found in their studies. 

In the other rule, the agency ordered regional transmission organizations and other transmission providers to submit one-time reports describing their current or planned policies and processes for conducting extreme weather vulnerability assessments and reducing those risks.