Grid Resiliency

President Donald Trump on August 26 signed an executive order preparing to block utilities from connecting some foreign-made equipment to the bulk power system, including transformers, batteries, inverters and associated software and digital products.

The order also contemplates the replacement of already-installed equipment, allowing the Secretary of Energy to “impose conditions on the continued use, operation, maintenance, servicing, or updating of foreign manufactured or operated bulk-power system electric equipment acquired or installed before the date of this order.”

The EO “focuses on transactions involving foreign nationals that pose an undue risk of sabotage, unauthorized access, or other disruption,” the White House said in a fact sheet, and is aimed non-distribution level equipment. It directs the Secretary of Energy to develop rules within 120 days to implement the order.

The U.S. faces an “extraordinary foreign threat ... involving bulk-power systems produced abroad that may present national security vulnerabilities,” the White House said. “The rapid growth of advanced manufacturing, data centers, artificial intelligence, and defense production has increased the Nation’s dependence on abundant, reliable electricity and magnified the consequences of a successful attack.”

Utilities are committed to working with DOE “on the implementation of [the] order to ensure that we can maintain the reliability and affordability of electricity across the country,” Edison Electric Institute spokesperson Dani Marx said to Utility Dive in an email.

The group represents investor-owned power companies and last year it estimated U.S. electric utilities would invest $1.1 trillion in the 2025-2029 period, a rapid increase in capital expenditures to meet rising demand. Capital expenditures from 2015 to 2024 totaled $1.3 trillion, the trade group noted.

According to the International Energy Agency, China accounts for 80% or more of the world’s production of certain grid equipment, including lithium-ion battery cells and some solar components.

Manufacturers of grid equipment say they are still digesting the order and will likely need clarification on several aspects.

“We've made a lot of progress on ensuring robust supply chains domestically and with our partners,” Bridget Bartol, the head of industry and regulatory affairs at the National Electric Manufacturers Association, told Utility Dive.

She said Trump’s Wednesday order builds off of 2020 Executive Order 13920, which focused on large power transformers from China, adding, “I see this as kind of an update and expansion.”

But Bartol warned there is the potential for confusion in the markets as a result of the order, “and we want to make sure that we continue to engage with the administration.”

Software, in particular, may “raise a lot of questions around what does it mean to be designed and developed by a covered foreign entity,” she said, noting that the order does not call out particular countries.

“There's a need for a lot more clarity” around the covered entity concerns, Bartol said. “I think there's going to be a lot of dialog between the industry and the administration.”

The United States Army announced August 26 that it has selected five companies to deploy 1-MW to 20-MW nuclear microreactors at military installations across the country to provide resilient power for critical infrastructure while remaining connected to the broader grid under normal conditions.

The Army’s Janus program will provide milestone-based federal funding for the companies to develop contractor‑owned and operated assets. Under the agreements, Antares Nuclear and Radiant Industries are slated to build three reactors at Fort Bragg, North Carolina, and Fort Benning, Georgia, respectively. The other three companies have contracts for one reactor each: BWX Technologies at Fort Campbell, Kentucky; General Atomics Electromagnetic Systems at Fort Hood, Texas; and Westinghouse Government Services at Fort Drum, New York. 

The investment model combines approximately $2.2 billion in federal funding from fiscal years 2027 through 2031, with private investment from each vendor expected to make up the majority of total project costs. “The goal is to have companies that can stand up on their own afterwards without government subsidies,” Jeff Waksman, principal deputy assistant secretary of the Army for installations, energy and environment, told reporters.

The Army's microreactor program could give a handful of advanced nuclear developers something the industry has struggled to secure: a major, committed early customer capable of helping absorb some of the financial and technical risks associated with first-of-a-kind deployments.

The Army is not simply buying reactors outright. The Defense Innovation Unit is using other transaction authority agreements with fixed-price, milestone-based payments modeled in part on NASA's partnership with SpaceX, Army officials said during a media roundtable Wednesday.

The agreements cover the engineering, qualification, regulatory work and construction needed to get the initial microreactors built, as well as their first year of operation. After that, the projects are expected to transition to Army power purchase agreements or other long-term offtake arrangements, Waksman told Utility Dive.

Government funding is intended to help companies overcome the additional costs and risks of developing and deploying early commercial units, but officials said the federal money is not structured as a conventional cost-sharing arrangement. 

Waksman said officials anticipate private capital to total “billions of dollars” and ultimately account for the majority of overall investment, but the Army did not provide a precise figure because companies are “still working to raise money off of this announcement.”

Army officials framed the program as more than a technology demonstration, saying the goal is to develop reactors capable of producing reliable electricity for years and ultimately support commercial sales.

"The Janus Program will be a complete success when and only when we have assisted multiple nuclear companies in developing truly reliable and affordable nuclear microreactors which they can sell to other buyers beyond just the military," Waksman said in the Army's announcement.

The Army said collaboration with utilities will be essential to its nuclear strategy and invited them to work with the government on future utility-scale, grid-facing generation located on Army installations. 

For initial projects, the reactors are designed primarily around installation resilience. Officials said the units will remain connected to the grid but could provide backup power if service is disrupted.

The generation IV microreactors selected for the program are designed as “inherently safe” systems that shut down on their own without relying on external power or diesel generators, using natural air circulation to remove heat in an emergency, officials said. 

The Army also emphasized that no long-term nuclear waste will remain on installations. All spent fuel and other radiological material must be removed from a site within two years of a reactor shutting down under a planned, Pentagon-wide waste agreement the Army is negotiating with the Department of Energy. 

While the units will operate under an Army regulatory process rather than the Nuclear Regulatory Commission, Waksman said the service is working closely with the DOE and the NRC to align standards so companies can more easily pursue licenses and broader commercial deployment after proving out their designs on Army bases.

Waksman said all five designs will use encapsulated nuclear fuel, with tristructural isotropic, or TRISO, fuel the likely choice because it is already qualified and in production. The reactors will need high‑assay low‑enriched uranium, or HALEU, which DOE is expected to supply initially by downblending existing stockpiles. But fueling more than 20 units could strain limited U.S. supplies, Waksman said, even as DOE has committed about $2.7 billion to expand enrichment capacity.

The Army, which launched Janus in October 2025, is targeting at least one operational reactor by Sept. 30, 2028. Three awardees — Antares, Radiant and Westinghouse — were also among the companies the Air Force and Defense Innovation Unit selected to develop microreactors at three Air Force bases.

Although individual company schedules vary, the program aims to eventually deliver more than 20 reactors across various sites within five years. Success in this domestic deployment is intended to pave the way for potential future use in remote or austere locations such as Alaska or U.S. Pacific island outposts, according to Waksman.

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By Pariveda

Resiliency has always been the core promise of a utility. When the grid is disrupted, contain the impact and restore power quickly. What is changing is the nature and consequences of those disruptions.

Much of the infrastructure is aging, while demand is expected to grow. The American Society of Civil Engineers graded the U.S. grid a D+ in 2025, and much of it is operating near or beyond its designed service life just as extreme weather and cyber threats test it in new ways. Summer peak demand is projected to grow by more than 224 GW over the next decade, leaving utilities with less room to absorb disruptions when they occur.

Resiliency under these conditions is about more than redundancy. It is about having multiple ways to respond when conditions change, whether that means rerouting power, drawing on storage, shifting load, dispatching distributed resources, or changing field priorities. The technology to create those options is becoming easier to acquire. The question is how utilities can exercise these options when needed.

The technology is no longer the constraint

A decade ago, deploying an AI use case required specialized teams, a clean labeled dataset and long development cycles. In contrast, today a working pilot can be stood up in days. For CIOs and Chief Data Officers asked to turn resiliency mandates into capability, the constraint has shifted from whether the technology can work to whether the organization can actually operationalize it.

Interestingly, most mature AI applications by utilities are often tied directly to grid reliability, such as predictive maintenance, proactive outage communications, identifying and localizing outage causes, improving ETOR estimates, prioritizing field work, detecting vegetation or asset risks. Utilities have made progress with applications like these. Yet scaling these into production and across the enterprise remain challenging for reasons that are rarely technical.

Why pilots stall short of production

Pilots often succeed by working around the enterprise. Someone extracts the data, cleans it and hands the team a CSV. That may be enough to prove the use case. However, production requires something different. It needs consistent, secure access to trusted operational data and the context needed to act on it.

Data access is only part of the story. A governance lens raises a broader set of questions:

• Who is accountable when an AI system gets it wrong?
• Which decisions require human review?
• What evidence is needed to validate the model and satisfy cybersecurity, safety and regulatory requirements?

When those answers are defined early, governance clears the path to production. When they are not, teams face uncertainty, delays and rework in order to move to production.

Governance extends beyond AI and internal processes. Resiliency depends not only on having options, but on having the authority to exercise them. A battery, flexible load, or automated control may create another way to respond when the grid is under stress. But contracts, operating procedures, or unclear decision rights can make that flexibility unusable.

Utilities are risk-driven organizations by design. They excel at stopping work that has not been shown to be safe, reliable, or compliant. What is often less clear is when enough risk has been addressed to proceed. Without a defined basis for saying yes, pilots tend to stall before production or struggle to scale.

Governance that fits the work already underway

When governance sits outside the normal workflow, it becomes a checkpoint. When built into the workflow, it helps teams navigate risk as part of the work.

For instance, AI-specific questions can be added to vendor procurement, risk and impact assessments incorporated into existing IT intake and the level of review matched to the risk. Low-risk use cases may clear a short questionnaire, while higher-risk ones follow a more structured review grounded in NIST's AI Risk Management Framework. That reduces the chance of governance becoming a late-stage hurdle.

It can also speed things up by addressing risk and compliance as the work progresses rather than after the fact.

"When we embed governance into existing processes, it speeds things up," says Lauren Malik of Pariveda. "It makes it consumable, and it doesn't feel like more work because it's already part of what they're used to doing."

What a solid foundation makes possible

The payoff shows up in what becomes possible afterward. A major electric delivery utility in high-growth Texas was running a transmission construction budget that doubled roughly every two years on a platform more than 25 years old. Rebuilding it around how work actually needed to flow through planning, scheduling, estimating and execution produced a system that now serves more than 2,500 users, supports over 50,000 construction projects and has enabled the utility to scale transmission construction activities by 250%.

What made that scale possible was not the technology alone. It was the foundation around it in the form of data people could rely on, workflows that connected and a system the organization trusted enough to use. The same holds for AI. The International Energy Agency has cautioned that without policies to support AI applications, energy-sector use is likely to stay limited to small-scale pilots.

Utilities that embed governance into the work from the start gain more than a faster approval cycle. They build the organizational capacity to say yes as the technology evolves. They turn technological optionality into operational resiliency, which means not just having more choices, but being able to act on them when the grid is under stress.

An affordable plug-in connector developed by Ford and Global Power Products will allow compatible Ford pickup truck owners to tap their vehicles for up to five days of home backup power without costly retrofits, the companies said July 22.

The Ford Vehicle Connector links Ford F-150 Lightning and PowerBoost Hybrid trucks’ 240-volt outlets with GPP’s GenerLink transfer switch. It can deliver power to home outlets and hardwired appliances like well and sump pumps, security systems, gas furnaces and lighting that can’t be powered with generator extension cords, Ford and GPP say.

Nic Saeger, CEO of Global Power Products, told Utility Dive that the product greatly simplifies and reduces the cost of home backup for rural utility customers, who typically face longer outages and have more critical hardwired appliances, like well and sump pumps. Rural customers in most of the U.S. experience longer and more frequent power outages, according to an analysis of Poweroutage.us data.

Ford says homeowners can expect to spend $1,350 to $1,550 on the new home backup solution, with some wiggle room to allow for variable installation costs. The hardware component — including the GenerLink transfer switch, 20-foot GenerLok extension cord and 12-inch Ford Vehicle Connector — costs about $1,100, while professional installation of the transfer switch typically costs $250 to $450, the automaker said in a Wednesday blog post.

More than 800 utilities have approved the GenerLink transfer switch for use on their meters, Saeger said. The list includes investor-owned utilities like Commonwealth Edison and Central Maine Power as well as larger municipal utilities like Austin Energy, which serves parts of Texas’s capital region, he said.

It also includes hundreds of smaller rural electric co-ops and other public power entities in far-flung territories where reliability is a perennial challenge and many customers lack municipal water service, Saeger said. Some of those utilities may offer free or discounted transfer switch installations, he added.

“If you’re on well water and you don’t have a device like this, you can’t plug in your well [pump],” he said. “You can’t flush your toilet if you don’t have power.”

Customers of utilities that haven’t yet approved the transfer switch can connect their trucks to a secondary meter box next to the main meter, Saeger said. But that’s a more expensive option, running about $1,000 more on average after installation, Ford estimates.

Both options are more affordable for Ford truck owners than the status quo, a cumbersome setup that David McCreadie, Ford’s director of EV grid energy services, told Utility Dive can cost upwards of $10,000 per installation. Standby generators, too, can cost anywhere from $7,000 to $15,000, depending on sizing, location and other factors, according to Poweroutage.us.

McCreadie said Ford’s partnership with GPP will benefit existing Ford truck owners and could boost uptake of its electrified vehicle models on the margins. 

“People who have never bought an electrified vehicle before may not realize that these products go beyond … just transportation [and] can add real value to the other areas of your life that an internal-combustion vehicle could never think of doing,” he said. “That is something we are trying to incorporate as part of our product messaging.”

McCreadie declined to say whether the smaller, more affordable all-electric pickup Ford plans to begin selling in 2027 will have the same vehicle-to-load capabilities as the F-150 Lightning and PowerBoost Hybrid trucks. 

Ford discontinued its all-electric full-size F-150 Lightning pickup in December after a string of disappointing sales years, choosing to shift some battery manufacturing capacity to stationary energy storage. The Lightning will reappear as an extended-range plug-in hybrid.

El Niño has developed in the Pacific Ocean, with warming water potentially upending U.S. weather patterns and complicating electric utility forecasting, say meteorologists at AccuWeather following NOAA’s June 11 declaration. 

The return of El Niño could offer some relief to utilities preparing for another active Atlantic hurricane season, but it may increase operational risks elsewhere on the grid, experts said. The previous El Niño episode persisted from 2023 into 2024.

The climate pattern is developing unusually early and is strengthening quickly, allowing it to exert greater influence on weather conditions across the United States. The outlook comes as utilities continue to invest in grid resilience and storm response capabilities.

A split summer scenario, where regions across the U.S. experience contrasting weather patterns, is expected to increase pressure on regional power systems, with AccuWeather forecasting heavier rainfall in parts of California and the Southwest alongside hotter, drier conditions across the Northwest, Northern Plains and Upper Midwest. 

In Florida, forecasters expect periodic stretches of above-normal temperatures and below-average rainfall that could add to load management challenges. Meteorologists said the shifting conditions may drive flooding and debris flows, along with drought and wildfire threats, with the potential for regional outages and broader grid disruptions through late fall.

AccuWeather is predicting 11 to 16 named storms in the Atlantic, which would be below recent La Niña-influenced seasons, but fewer storms do not mean lower reliability risk. AccuWeather Lead Hurricane Expert Alex DaSilva said storms forming close to the coastline during El Niño years can pose heightened risks due to shorter preparation time.

“It only takes one storm,” DaSilva said, noting that even a quieter season can still yield significant infrastructure damage. 

The Edison Electric Institute, which represents investor-owned utilities, is prompting its members to coordinate with industry and government partners on preparedness and mitigation efforts to maintain reliability and support rapid restoration. The El Niño pattern “can affect storm activity and add uncertainty to seasonal outlooks,” EEI Senior Vice President of Industry Operations Jennifer DeCesaro told Utility Dive in an email. 

The trade group highlighted mutual assistance efforts that allow companies to pre-position crews, equipment and supplies ahead of major storms, a key strategy given that severe weather accounted for roughly 80% of power outages between 2000 and 2023.

Looking beyond this year, AccuWeather sees elevated drought risk persisting across portions of the Plains from Texas to North Dakota even after El Niño peaks, raising longer-term concerns for resource adequacy and system planning. 

“El Niño patterns tend to be persistent, meaning places that end up drier than average can stay that way for an extended period of time, possibly for months or even years,” said AccuWeather Expert Meteorologist Paul Pastelok.

AccuWeather also estimates a 40% chance the climate pattern strengthens into a rare “Super El Niño,” which could extend weather impacts into 2027.

As weather risks grow more complex, utilities are expanding investments in distributed energy resources. An Electric Power Research Institute report identified microgrids, energy storage and automation tools as ways to support localized islanding for faster restoration, though the technologies also face weather-related limitations.

“Microgrids are not immune to extreme weather; therefore, climate-informed planning must account both for how microgrids enhance resilience and how extreme weather may degrade performance or alter generation and storage availability,” said Erik Smith, technical leader of climate data analysis at EPRI, in a written statement. 

Utilities are also allocating increasing funds for targeted prevention, including Florida Power & Light’s nearly $15.1 billion, 10‑year Storm Protection Plan. The shift is toward vegetation management, stronger poles and selective undergrounding as overhead lines and substations remain key failure points in severe weather, where localized damage can quickly cascade into broader outages.

“The goal is not to harden everything, but to invest where outage risk and community impacts are highest,” said Hayley Lai, grids and utilities analyst at BloombergNEF, in an interview.

Lai added that storm-related costs, often recovered over time through rates or surcharges, can result in customers paying for restoration long after an event. Public funding or regulatory action may offset some costs, but typically not fully, and underinvestment can result in repeated outages and more expensive recovery efforts.

Ryan Ward, a weather and commodities analyst at BloombergNEF, said recent storms underscore that variability. He pointed to a new study that found Hurricane Helene left nearly 6 million customers without power across 10 states, while Hurricane Zeta affected more than 3,700 miles of transmission lines — more than Hurricane Ian, which caused 2,455 miles of transmission impacts despite being a Category 4 storm.

“In short, a weak season overall does not imply no risk, especially if a storm landfalls in a vulnerable location,” Ward told Utility Dive in an email.

The El Niño outlook comes as policymakers and weather experts debate the future of federal forecasting capacity. The Trump administration has proposed reducing NOAA funding by roughly 26% in fiscal year 2027 while NOAA and the National Weather Service continue efforts to reorganize operations and address staffing gaps.

Critics argue the cuts could undermine weather forecasting at a time when utilities are facing growing exposure to hurricanes, floods, wildfires and extreme heat.

“These cuts diminished our ability to study, monitor, forecast, and warn for hurricanes and other hazards,” said John Morales, meteorologist and Climate Power co-chair, in a formal statement. “Weakening our ability to save lives and property in the face of increasingly severe and frequent extreme weather events is a dangerous mix.”

The PJM Interconnection can curtail data centers and other large loads that have backup generation under an emergency order issued Monday by the U.S. Department of Energy.

PJM on Sunday asked to be able to direct transmission owners and electric utilities in its Mid-Atlantic and Midwest footprint for permission to curtail those facilities if needed for three days starting May 18 because of hot weather combined with planned power plant maintenance outages.

PJM said it expected to have less than 5,800 MW of reserves during its May 18 peak, and that Maryland and Virginia could be especially stressed by the unseasonably hot weather.

Power plant and transmission owners often take their facilities offline in the spring for maintenance so they are prepared for the summer, PJM noted. The grid operator said it expected power plants totaling more than 40 GW would be offline for planned outages on May 18.

“The projected level of generation outages coupled with the forecasted demand raises a significant risk of emergency conditions that could jeopardize electric reliability and public safety,” PJM said.

The curtailments would be a last resort before ordering rolling blackouts, according to the DOE’s order, issued under the Federal Power Act’s section 202(c). Only large energy consumers with backup generation would be affected.

“The employment of this backup generation is expected to reduce stress on the grid,” the DOE said. “This will permit orderly, safe, and secure operations during PJM’s hot weather conditions.”

There are significant amounts of backup generation in the United States that have remained largely untapped during grid emergencies, according to the DOE.

“Deployment of backup generation resources (whether auxiliary, standby, directly-connected, battery storage or other, and whether synchronized or not to the bulk power system) at data centers (including, but not limited to, hyperscaler facilities), and at other large load industrial and commercial customer sites, can prevent avoidable blackouts, thereby saving lives and reducing costs to the American people,” the department said.

In January, the DOE issued similar emergency orders to PJM, Duke Energy Carolinas and Duke Energy Progress, and the Electric Reliability Council of Texas.

PJM said on Monday that it had issued “maximum generation” and “load management” alerts for May 19, with a “hot weather” alert in place for most of the PJM footprint.

Also, the grid operator activated demand response customers in parts of the Mid-Atlantic and Dominion regions. The grid operator said it called on pre-emergency demand response for the Baltimore Gas and Electric, Dominion and Potomac Electric Power Co. areas on Monday to address local transmission constraints and to preserve the run-time of generators that will be needed for the hot weather and higher electricity demand expected on Tuesday and Wednesday.

For three days starting on Tuesday, PJM expected its peak load to hit 134,027 MW, 135,961 MW and 119,103 MW.

The North American Electric Reliability Corp. on May 4 issued a rare Level 3 alert — the watchdog’s highest level — following instances of data centers unexpectedly dropping load or oscillating demand rapidly, creating reliability concerns. The alert includes seven actions grid entities “must implement to address immediate risks posed by computational loads,” NERC said.

Transmission planners and operators, system planners and balancing authorities are among the entities that must act. The required actions address the modeling, study, operation, protection and control of computational loads, including artificial intelligence training and cryptocurrency mining.

“The grid faces unprecedented challenges from a surge in large power consumers,” NERC said in a statement. Summer peak demand across the bulk power system is expected to rise 24% in the next 10 years, with data centers accounting for most of the increase, the organization said in its most recent Long Term Reliability Assessment, published in January.

In the face of rising data center loads — and instances where they unexpectedly disconnected from the grid — NERC issued a Level 2 warning last year that elicited alarming responses from grid stakeholders, the reliability watchdog said.

“Entities generally did not have sufficient processes, procedures, or methods to address emerging computational loads,” NERC said in its Monday warning. The essential actions NERC calls for include the following:

• Transmission planners and planning coordinators should develop a detailed list of modeling data, settings, and parameters needed from computational loads and distribute this to transmission operators in their footprint. Transmission operators should reflect this information in their facility interconnection requirements.
• Transmission planners and planning coordinators should collect data from computational loads such as the expected minimum and maximum consumption in megawatts and the percentage of IT load vs. non-IT load (cooling, for instance), at various load levels.
• Planning coordinators should revise definitions that trigger a review of local area protections, stability limits and other reliability studies to account for computational loads.
• Transmission operators should establish a “commissioning process” for computational loads.
• Where possible, the commissioning process transmission operators develop should include testing facilities at full load and at no load, and, if possible, with at least a 10% change from nominal voltage.
• Transmission operators should install and utilize dynamic fault recording devices to understand computational load facility electrical performance during system disturbances.

Registered NERC entities must acknowledge receipt by May 11 and must respond by Aug. 3.

Level 3 alerts, which are rare, call for grid operators to take specific steps in response to an immediate issue. NERC last issued a Level 3 alert a year ago regarding possible grid disruptions related to inverter-based resources. Solar, wind and battery resources have been known to trip offline during grid disturbances. 

Grid instability issues caused by data centers "could become quite severe — to the the point of creating widespread blackouts," Ben Inskeep, program director for the Citizens Action Coalition, told Utility Dive in an email.

"It is critical that we have standards in place to protect all ratepayers from negative impacts to grid stability, reliability, and resiliency that are caused by data centers, especially given the rapid proliferation of these mega users across the country," Inskeep said.

NERC’s efforts to better align utility and data center operations may take longer than anticipated, Digital Power Optimization CEO and founder Andrew Webber told Utility Dive. The company builds and manages data centers.

“It will take years of coordinated effort in the drafting of new regulations, understanding limitations and opportunities related to physical equipment, understanding limitations and opportunities related to software and control systems, re-prioritizing various loads all throughout society, etc.,” Webber said in an email.

He pointed to recent comments by Laura Swett, chair of the Federal Energy Regulatory Commission, about a lack of communication between data centers and energy regulators.

“Given the absolutely critical need [for data center developers] to source power for their developments, I found it quite interesting that FERC isn’t seeing more direct engagement from the data center industry,” Webber said. “I think it exemplifies the challenges NERC is also going to face in getting genuine buy-in and wholehearted acceptance by the data center industry as it pertains to grid reliability.”

“New evaluation paradigms will need to be created and worked through in partnership with the data center industry,” he said.

An additional 1 GW of interregional transmission capability could have saved U.S. consumers $183 million during Winter Storm Fern, Liza Reed, director of climate and energy policy at the Niskanen Center think tank, told the Senate Committee on Energy & Natural Resources Wednesday.

Some regions saw prices of hundreds of dollars per megawatt-hour during the multi-day storm from Jan. 23 to Feb. 3, while neighboring areas experienced negative power prices. “There was power not being used at all because the transmission was not available to move it to where it was needed,” said Reed.

Wednesday’s hearing to “examine the state of the bulk power system” focused on regulatory roadblocks to expanding the grid, including transmission, and the need for new technologies and market constructs. U.S. Sen. Alex Padilla, D-Calif., said he and other senators are developing legislation to help modernize transmission development and grow the use of grid enhancing technologies.

Electricity bills are up by as much as 13% since President Trump took office, Sen. Martin Heinrich, D-N.M., said in an opening statement, and the administration has threatened 116 GW of new clean energy capacity from coming online.

Transmission investment could address both rising demand and affordability, he said.

“We need to get more out of the grid that we have,” Heinrich said. “Grid enhancing technologies can unlock 20 to 100 GW of additional capacity when demand is highest. These solutions cost less than one quarter of the traditional upgrade costs and can be deployed in three to five years.”

Grid enhancing technology, such as dynamic line ratings and advanced power flow controls, “could reduce grid congestion by 40% or more, saving customers four to $8 billion a year,” he said.

Padilla said his draft legislation builds on the bipartisan Energy Permitting Reform Act of 2024, which passed out of committee but was never voted on by the full Senate.

The new bill will include additions to support implementation of advanced grid upgrades and high-voltage direct current lines, along with improving interconnection procedures and reauthorizing grid resilience grant programs, Padilla said.

“I believe our effort represents not just a common sense plan, but one that will build a cheaper, stronger, more reliable electrical grid that protects ratepayers,” he said.

Other lawmakers involved in drafting the legislation are Sens. John Hickenlooper, D-Colo., Catherine Cortez Masto, D-Nev., Ruben Gallego, D-Ariz., and Angus King, I-Maine.

Sen. Mike Lee, R-Utah, said permitting delays are “slowing projects across all forms of energy infrastructure” while market distortions “are affecting investment decisions, and the pace of innovation in the electricity sector is not where it needs to be.”

“If we modernize permitting, and if we ensure that markets are truly competitive, we can solve this challenge,” Lee said. But if a lack of supply additions hold back demand growth, “the imbalance we're seeing today will become more severe, and the consequences will be felt by American households and businesses.”

King told the committee that he supports permitting reform efforts but will not participate in discussions “as long as the administration is arbitrarily putting its thumb on the scale and canceling wind and solar projects that, in many cases, have already been permitted. Then, permitting reform only benefits one side of the equation — that's fossil fuel. I'm not going to participate in that discussion.”

“I feel like I'd be dumb to agree to permitting reform which only affected one half of the equation,” King said.

The distribution system is another area where the power sector can get more capacity from existing infrastructure, Heinrich said. The U.S. already has 30 GW to 60 GW of distributed energy resources operating as virtual power plants, he said.

“Deploying another 60 GW could save consumers $20 billion by 2030,” Heinrich said. “But these aren't silver bullet-solutions for long-term growth. We must also build high voltage transmission lines to reduce congestion and reliability risks.”

Transmission congestion cost consumers $12.1 billion in 2024 alone, he noted, but interregional transmission made up only 2% of new circuit miles installed between 2011 and 2023. 

NERC in 2024 recommended the addition of 35 GW of U.S. interregional transfer capability, a 40% boost to current capabilities. The U.S. needs “narrow and clear federal authority” to build interregional transmission, Reed said.

Instead, existing market structures create barriers to the deployment of new transmission technologies, Reed said. Grid operators do not compensate high-voltage direct-current transmission technology for some reliability services, she noted.

“China has built tens of thousands of miles of high capacity transmission in the last two decades to our hundreds,” she said. “We are behind on increasing capacity. We are behind on adopting modern technology. And this will put us behind on attracting and maintaining top industries. A shortage of grid capacity is the primary barrier to cost effective and swift deployment of AI in this country.”

In December, BloombergNEF said U.S. data center power demand could reach 106 GW in 2035. By the end of 2025, more than 50 GW of data center capacity was operating in the U.S., representing 24% compound annual growth since 2020, according to the Federal Energy Regulatory Commission.

Todd Snitchler, president and CEO of the Electric Power Supply Association, told lawmakers that one of the greatest risks to reliability and affordability is uncertainty around the demand growth associated with large loads.

“There's a wide disparity about just how much electricity will be needed, when the demand increases will be most prevalent and how quickly the predicted demand will actually materialize,” he said. That introduces the “danger of over- or under-producing capacity during a time of volatile demand projections.”

EPSA supports allowing large demand customers to procure their own new generation “to provide certainty over their supply cost,” Snitchler said. The growing interest in voluntary bilateral partnerships between power plants and large demand customers “embody the competitive characteristics and ratepayer protection that wholesale markets encourage.”

Travis Fisher, director of energy and environmental policy studies at the libertarian Cato Institute think tank, told lawmakers that Congress should enact a policy known as Consumer Regulated Electricity, or CRE, to allow off-grid electric utilities to serve new customers under voluntary contracts.

Those utilities would not be subject to economic regulation at the state or federal level because they do not connect to existing systems or pose a risk to existing customers, he said.

The approach “would enable speed to power for the customers who value it most while not burdening the existing grid,” Fisher said. 

Puget Sound Energy began testing vehicle-to-home technology in its service territory last month in the first bidirectional electric vehicle charging pilot of its kind in Washington state, the utility said on March 18. 

Puget Sound Energy said it’s running the test in partnership with Ford, Kia, EV charging equipment provider Wallbox and ChargeScape, a vehicle-grid integration platform. Participating EV owners will use their vehicles’ batteries to provide backup home power “while simultaneously supporting grid reliability during peak demand periods,” the utility said.

In an email, ChargeScape CEO Joseph Vellone called the test a “technology demonstration” that will run through the first quarter of 2027. It includes three Ford F-150 Lightning and two Kia EV9 vehicles, he said.

Puget Sound Energy “will continue to explore opportunities to expand the demonstration scope as other [auto manufacturers’] and charging partners’ bidirectional capabilities advance,” Vellone said.

The utility said the demonstration will test two use cases. The first is time-of-use optimization, where participating vehicles charge during cheaper off-peak periods and discharge during higher-priced peak periods to reduce their owners’ electricity bills. The second is demand response, where Puget Sound Energy calls on the vehicles to help stabilize the grid by discharging during high-demand periods.

Active managed charging, where utilities or other intermediaries use software to control power flows to and from plugged-in EVs, can reduce peak charging demand by 50% or more and significantly reduce the associated system costs, according to a January study commissioned by EnergyHub. The study relied on a cohort of 58 drivers in Washington.

Using EV batteries for distributed energy storage also aligns with Puget Sound Energy’s clean energy goals, the utility said.

Though most of its sales already come from clean sources, Puget Sound Energy has identified demand response as a key lever for integrating more carbon-free power. In 2023, it announced a partnership with Autogrid — now part of Uplight — to deploy 100 MW of virtual power plant capacity within two years. More recently, it inked a deal with BrightNight and Cordelia Power to purchase power from a 200 MW/800 MWh battery facility that a utility spokesperson said would help alleviate grid congestion and integrate more clean energy when it comes online, likely next year.

As for the vehicle-to-home demonstration, Vellone said Puget Sound Energy will use its technical results and feedback from participants to “inform its future product development and deployment strategy.” That could include an expansion of the bidirectional charging program, which would require a filing with the Washington Utilities and Transportation Commission, he said.

The WUTC cleared Puget Sound Energy in 2023 to run “limited-scale” EV technology demonstrations to advance its energy transition and transportation electrification plans.

Washington has one of the country’s most ambitious frameworks for electric vehicle adoption. It’s one of about a dozen states to adopt California’s Advanced Clean Cars II road map, which requires 100% of new light-duty vehicles sold in 2035 to meet zero-emissions standards. A state law passed in 2022 set a nonbinding target of 2030 for new vehicle sales to be 100% electric.

Recent sales trends suggest Washington will have a difficult time meeting the earlier target, according to an analysis from the Washington Policy Center, a free-market think tank. Sales data from the Alliance for Automotive Innovation, an automaker-backed trade group, shows EV sales growth in Washington stalling out in 2025 after brisk growth in 2024, consistent with national trends.

EPB of Chattanooga has deployed five battery-based microgrids with 29 MW/58 MWh of combined capacity across two sites, the Tennessee public distribution utility said Tuesday.

Two more battery-based microgrids will follow “very soon” as EPB works to harden its grid and reduce demand charges levied by the Tennessee Valley Authority, its bulk power supplier, Ryan Keel, EPB’s president of energy and communications, said in an interview. EPB has 45 MW/95 MWh of front-of-the-meter energy storage in service today, including the new microgrids, and another 45 MW it expects to deploy over the next 12 months, Keel said.

Next year, EPB plans to deploy an advanced microgrid control platform developed by longtime partner Oak Ridge National Laboratory. The control platform will allow microgrid boundaries to expand or contract based on power demand and available supply, EPB said.

The microgrid project was supported by the U.S. Department of Energy’s Office of Electricity, EPB said. On Monday, Katie Jereza, assistant secretary for the office, appeared at events celebrating the microgrids and Oak Ridge’s new control system.

“Microgrids make electricity more dependable when it’s needed most and help reduce energy costs when demand spikes,” Jereza said in a statement.

The public utility’s service territory has about 200,000 customer meters and saw peak demand hit a new record of around 1,350 MW during a cold snap this January, Keel said. Its unique customer mix — spanning urban Chattanooga in the Tennessee River Valley and semi-rural areas in the city’s mountainous exurbs — makes it “almost a sort of hybrid of a municipal utility and a rural electric cooperative,” he said.

Keel said the two microgrid sites announced this week include 2-hour battery systems in urban Chattanooga. They, along with most other energy storage systems on EPB’s grid, will help offset monthly demand charges that can account for one-third of the utility’s total power purchase costs, he said.

That demand charge is set by the hour of each month with the highest demand, “so whenever that hour occurs, we have a financial incentive to reduce that peak with energy storage and other measures,” Keel said.

Under its agreement with TVA, energy storage does not count toward EPB’s self-generation limit of 5% of its own load, Keel said. EPB expects to have 100 MW to 150 MW of energy storage on its distribution system within “two to three years,” he added.

“It’s all front-of-meter from the customer’s perspective, but it’s all behind-the-meter when you’re talking about our relationship with TVA,” Keel said. 

Though there’s always a risk that TVA’s posture toward energy storage could change, Keel sees that as relatively unlikely as the nation’s largest public utility grapples with surging power demand.

“The way we see it, this stuff only has increasing value to us and this area,” he said.

In addition to allowing microgrids to expand and contract as conditions change, Oak Ridge’s microgrid platform will enable “nested” microgrids that can provide critical support to EPB’s distribution system and improve reliability, the utility said.

Stephen Streiffer, Oak Ridge’s laboratory director, said in a statement that his organization’s work — and its relationships with utilities like EPB — will help mitigate the effects of extreme weather and other disruptions to the power system and the communities that depend on it. 

“Microgrid innovations demonstrated through utility partnerships are enabling safeguards for critical infrastructure and community services in the face of disasters,” Streiffer said.

EPB is developing a smaller battery-based microgrid in a rural area near the end of a radial distribution line, Keel said. Its four-hour discharge capacity reflects the utility’s expectation that it will serve the resiliency needs of an area where power outages are more frequent, he said.

“This is more of an ‘end of our electric system’ residential setting where it will be used more frequently [and] isolated from the grid to serve customers,” Keel said.

The microgrids are part of a larger effort, supported by DOE, to improve grid reliability and resilience in the area.

In 2023, DOE said it would give EPB $32.3 million in matching funding to replace more than 1,300 utility poles, underground over 100 miles of power lines and deploy 15 MW of energy storage at six sites.

Keel said the utility’s work with Oak Ridge on energy storage began “years ago,” when battery technology was not as commercially viable as it is today. 

“It has grown into this, but what Oak Ridge has done [in contributing] to our deployment today … goes back to our partnership over many years,” he said.