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President Donald Trump has made it his mission to banish offshore wind farms from America. He has derided wind energy as unreliable and expensive while freezing permitting and halting projects already under construction.
Yet a new report suggests that the president’s moves could be working against grid reliability in key parts of the country. Along the Northeast and mid-Atlantic regions, offshore wind can play a critical role in keeping the lights on year-round, especially through the winter, according to a study published this month by New York City–based consultancy Charles River Associates.
Trump’s attacks on offshore wind and other renewable sectors come amid dire challenges for the nation’s power system. The world’s wealthiest companies are building power-hungry data centers as grid infrastructure ages and households’ energy bills skyrocket. The White House itself has declared an “energy emergency,” which it’s using to push for more fossil-gas, coal, and nuclear power plants.
But offshore wind is well suited to “meeting the moment,” in part because gas plants are reliable in the summer but can buckle under winter weather, according to the study. Ocean winds in the Northeast are at their strongest and steadiest in winter months, making turbines there a way to boost the reliability of power grids connected to underperforming gas plants.
Oliver Stover, a coauthor of the study, called offshore wind farms a “near-term solution,” saying that turbines at sea and gas plants on land complement each other throughout the Northeast’s changing seasons: “They’re stronger together.”
Stover explained that if grid reliability is the goal, it makes sense for planned offshore wind farms to reach completion. Those projects will help regional grids burdened by extreme winter weather and data-center demands “buy time” as more infrastructure is built.
“Every megawatt is a good megawatt,” he said.
The periods in which offshore wind performs best also align with the time of increasing grid strain: winter mornings and evenings, when people tend to crank up the heat. While peak electricity demand has historically happened during the summer months, it is shifting to these winter moments in many parts of the country, largely due to the mass electrification of space-heating systems.
That means securing power generation during colder months must be, according to Stover, “a priority going forward.”
Stover and his colleagues aren’t the first to underscore the reliability benefits of offshore wind. Other analysts, along with grid operators, have warned that Trump’s efforts to squash certain projects that East Coast states were planning to rely on could raise blackout risks and power bills in the region.
Take Revolution Wind: Trump paused construction of the Rhode Island project in August due to “national security concerns” that a federal judge said were not rooted in “factual findings.” Having won an injunction in court, developer Ørsted eventually resumed construction one month later.
But during the pause and amid mounting uncertainty over the project’s fate, ISO New England — the region’s grid operator — released a statement saying that delaying delivery of power from Revolution Wind “will increase risks to reliability.”
Susan Muller, a senior energy analyst at the Union of Concerned Scientists, told Canary Media that if Revolution Wind were killed, the impact would be most acutely felt in winter months. That’s when the region’s limited supply of fossil gas is stretched even thinner, since the fuel is used for both building heating and power generation.
Losing Revolution Wind’s electricity entirely would have cost New England consumers about $500 million a year, according to Abe Silverman, a research scholar at Johns Hopkins University. His estimation was based on the value that the offshore project had secured in ISO New England’s forward capacity market as well as its potential to supplant costlier power plants used during grid emergencies, like snowstorms.
“We don’t need a bunch of fancy studies to tell us that these units are needed for reliability,” Silverman told Canary Media in September during Revolution Wind’s government-ordered pause.
In Virginia, the world’s data-center capital, America’s largest offshore wind farm is slated to start generating power in March 2026. Trump has not yet targeted the 2.6-gigawatt project, but if it doesn’t come online as planned, the mid-Atlantic grid region run by PJM Interconnection would be less reliable and have higher electricity costs, this month’s study says.
In a large swath of the Mid-Atlantic region, offshore wind has one of the highest “resource-adequacy” scores among energy types, according to the study. In other words, when it comes to lowering the probability of blackouts there, offshore wind outcompetes all other types of renewable energy — and is even on par with the most efficient gas-fired power plants.
But the sector is not without its issues, Stover emphasized. Even before Trump’s anti-wind policies made investors skittish and permits no longer guaranteed, construction costs had been ballooning for years, given supply chain issues and inflation.
Offshore wind farms are also, by nature, megaprojects that come with inherent logistical hurdles. Just last month, New York’s Empire Wind lost the turbine-construction vessel it was banking on, due to a skirmish between two shipbuilding companies. Only a handful of boats in the world are capable of doing that kind of work.
The report’s conclusions stand in stark contrast to rhetoric coming from top officials implementing Trump’s war on offshore wind. The sector was just taking off in the U.S. when the president was inaugurated in January, with the first commercial-scale project coming online last year and five more arrays now under construction.
“Under this administration, there is not a future for offshore wind because it is too expensive and not reliable enough,” Doug Burgum, secretary of the Interior Department, told an audience in September at a fossil-gas industry conference in Italy.
Burgum’s statements mirror some of Trump’s favorite talking points that have long misled the public about the risks of wind power. In September, Trump told the United Nations General Assembly in a speech that “windmills are so pathetic and bad” because of their unreliability, falsely claiming that wind power is “the most expensive energy ever conceived.”
The grid does not automatically face problems when “the wind doesn’t blow,” as Trump falsely claimed at the United Nations. Grid operators routinely handle the intermittent nature of power generation from multiple sources — whether it be solar, gas, or wind turbines — through grid-management techniques and, increasingly, battery storage.
Trump is wrong about costs, too.
While offshore wind energy is currently expensive, nuclear energy — a sector the Trump administration aims to boost — is typically the most expensive type of power.
Globally, power generated from wind turbines in the ocean is comparable to other sectors such as geothermal and coal when it comes to cost-competitiveness. In fact, offshore wind has become more cost-competitive relative to other power types in recent years as the sector has matured in Europe and China, according to the most recent analysis by financial advisory firm Lazard.
But when temperatures plummet, offshore wind power could be a huge cost-saver for many U.S. residents. One analysis found that in New England, if 3.5 gigawatts’ worth of under-construction offshore wind farms had been online, households there could have saved $400 million on power bills last winter. In the coming months, cost savings and reliability will take center stage as Vineyard Wind, the region’s first large-scale offshore wind farm to break ground, feeds the grid for its first full winter season.
Two new battery projects on Virginia’s remote eastern peninsula could signal a growing trend in the clean-energy transition: midsize energy-storage units that are bigger than the home batteries typically paired with rooftop solar, but cheaper and quicker to build than massive utility-scale projects.
The 10-megawatt, four-hour batteries, one each in the tiny towns of Exmore and Tasley, represent this “missing middle,” said Chris Cucci, chief strategy officer for Climate First Bank, which provided $32 million in financing for the two units. Batteries are a critical technology in the shift to renewable energy because they can store wind and solar electrons and discharge them when the sun isn’t shining or breezes die down.
When it comes to energy storage, “we need volume, but we also need speed to market,” Cucci said. “The big projects do move the needle, but they can take a few years to come online.” And in rural Virginia, batteries paired with enormous solar arrays — which can span 100-plus acres — face increasing headwinds, in part over the concern that they’re displacing farmland.
The Exmore and Tasley systems, by contrast, took about a year to permit, broke ground in April, and came online this fall, Cucci said. Sited at two substations 10 miles apart, the batteries occupy about 1 acre each.
Beyond being relatively simple to get up and running, the systems could help ease energy burdens on customers of A&N Electric Cooperative, the nonprofit utility that owns the substations where the batteries are sited, said Harold Patterson, CEO of project developer Patterson Enterprises.
Wait times to link to the larger regional grid, operated by PJM Interconnection, are up to two years. So for now, the batteries will draw power only from the electric co-op, Patterson said. Once they connect to PJM, the batteries will charge when system-wide electricity consumption is down and spot prices are low. Then, the batteries’ owner, Doxa Development, will sell power back when demand is at its peak, creating revenue that will help lower bills for co-op consumers.
“That’s the final step to try to drive down power prices” for residents of Virginia’s Eastern Shore, Patterson said. “Get it online and increase supply in the wholesale marketplace.”
Though the batteries aren’t paired with a specific solar project, they are likely to lap up excess solar electrons on the PJM grid. And since they’ll be discharged during hours of heavy demand, they could help avert the revving up of gas-fired “peaker plants.”
“Peaker plants are smaller power plants that are in closer proximity to the populations they serve, and [they] are traditionally very dirty,” Cucci said. “They’re also economically inefficient to run. Battery storage is cleaner, more efficient, and easier to deploy.”
Gas peaker plants are wasteful partly because of all the energy required to drill and transport the fuel that fires them, said Nate Benforado, senior attorney at the Southern Environmental Law Center, a nonprofit legal advocacy group.
“Then you get [the fuel] to your power plant, and you have to burn it,” Benforado said. “And guess what? You only capture a relatively small portion of the potential energy in those carbon molecules.”
Single-cycle peaker plants, the most common type, can go from zero to full power in minutes, much like a jet engine. Their efficiency ranges between 33% and 43%.
“Burning fossil fuels is not an efficient way to generate energy,” Benforado said.
“Leaning into batteries is the way we have to go. They’re efficient on the power side but also on the price side.”
Texas proves the financial case for batteries. The state has its own transmission grid, no monopoly utilities, and no state policies to speed the clean-energy transition. Yet it’s gone from zero to some 12 gigawatts of batteries in five years.
In Virginia, A&N Electric Cooperative isn’t the only nonprofit utility investing in energy storage: The municipal utility in the city of Danville, on the North Carolina border, announced earlier this year that it’s building a second battery project of 11 megawatts. Its first system, a 10.5-megawatt battery, which went online in 2022, is on track to save customers $40 million over two decades, according to Cardinal News.
“You look at Texas, where developers are trying to make money on projects,” said Benforado. “And now you see co-ops and municipalities saying, ‘This can save our customers significant amounts of money.’ That, to me, is very telling about the economics of batteries.”
Those economics are even rosier in light of the federal tax credits available for grid batteries, among the few green incentives to survive the budget bill that congressional Republicans passed this summer. Those credits start phasing down in 2033.
While nonprofit utilities in Virginia aren’t impacted by a 2020 state law that requires investor-owned Dominion Energy and Appalachian Power Co. to decarbonize by 2045 and 2050, respectively, they help show what’s possible for the state.
“We need to build things,” Benforado said, especially in the face of skyrocketing demand from data centers. “The question is, are we going to build clean resources or not? We need to build batteries, not gas.”
Climate First Bank and Patterson Enterprises, for their part, have more midsize energy-storage systems in the works. In fact, in December they expect to break ground on another 10-megawatt project — in Wattsville, 20 miles up the road from Tasley.
“We are talking to a lot of developers on projects ranging from 2 megawatts to 10 or 15 megawatts,” Cucci said. “A lot of those players are saying, ‘Let’s shift a little more heavily into storage.’”
The data-center boom is pushing electricity costs to the breaking point for PJM Interconnection — the country’s biggest grid operator, serving more than 65 million people from the mid-Atlantic coast to Illinois — and that’s fueling a popular backlash.
Democratic gubernatorial candidates pledging to combat rising utility bills just won landslide victories in New Jersey and Virginia, two states bearing much of the brunt of data-center-driven cost increases. Congress members along with state governors and lawmakers are demanding that PJM take action.
PJM is poised to make a key decision this week on a fast-track process to get data centers online quickly while mitigating the impact of the facilities, which can use as much power as small cities. But a conflict has emerged over how far the grid operator can go. It boils down to this: Can PJM force data centers to stop using electricity at moments when demand for power peaks?
Data-center trade groups say no. But a growing number of politicians and environmental and consumer advocates say that requiring data centers to be the first to get disconnected from power during grid emergencies is the only surefire way to protect customers.
Last week, a bipartisan coalition of state legislators representing many of the 13 states served by PJM submitted its Protecting Ratepayers Proposal, which argues for data centers to be allowed to connect to PJM’s grid with the stipulation that they will be “‘interrupted’ during grid emergencies until they bring their own new supply.”
“We have a responsibility to ensure that technological growth doesn’t push vulnerable residents into financial hardship or enable a massive transfer of wealth from ratepayers to data centers,” said Maryland state Sen. Katie Fry Hester, a Democrat and organizer of the coalition, in a press release introducing the proposal.
“This proposal is about fairness and responsibility,” added Illinois state Sen. Rachel Ventura, also a Democrat. “We’re making sure data centers carry the cost of their own energy demands instead of passing it on to the public.”
That’s a salient concern, because the peak power needs of data centers are what’s driving electricity costs through the roof in PJM territory.
The grid operator must secure enough capacity from power plants and other resources to serve its peak loads. The prices of securing that capacity have skyrocketed in the past two years, from $2.2 billion in 2023 to $14.7 billion in 2024 and to $16.1 billion in PJM’s latest capacity auction this summer.
Growing demand forecasts of yet-to-be-built data centers are the primary culprit for these price spikes, and constitute the “core reliability issue facing PJM markets at present,” according to an August report from Monitoring Analytics, the company tasked with tracking PJM’s markets. “There is still time to address the issue but failure to do so will result in very high costs for other PJM customers,” the report warns.
Utility bills are rising across much of the U.S. due to a combination of factors, including volatile fossil-gas prices and the expense of repairing and expanding power grids. Data-center growth is not directly increasing costs in most regions yet, but in PJM, utility customers’ bills already reflect the capacity cost increases tied to serving future data centers.
Groups including consumer advocates in Maryland and the Natural Resources Defense Council agree that requiring new data centers to get cut off first during grid emergencies is a vital backstop to the suite of interventions PJM is considering for its fast-track process.
“We’re proposing to allow data centers to join PJM’s grid as fast as they want, but not guarantee them firm service, so they’ll be given interruptible service until they bring their own capacity,” Claire Lang-Ree, clean-energy advocate at the Natural Resources Defense Council and coauthor of the environmental group’s proposal, explained during an Oct. 22 webinar. “We think that’ll solve both the cost and reliability problem, because by removing all these large loads out of the capacity market until they bring their own supply, … capacity prices might go back down to historic levels.”
PJM’s Members Committee is expected to vote Wednesday on a final advisory recommendation to send to the grid operator’s board of managers. PJM has said it intends to file a proposal in December with the Federal Energy Regulatory Commission, in hopes of gaining approval to institute changes in 2026.
Data-center companies and utilities are not happy about mandatory power cutoffs for new computing facilities, however — and their arguments have so far carried the day at PJM.
In August, PJM issued a “conceptual proposal” that included a “non-capacity-backed load” (NCBL) structure. The approach would force loads of 50 megawatts or larger to curtail power use to forestall grid emergencies as a precondition to interconnection.
That proposal was lambasted by the Data Center Coalition, a trade group that includes Google, Microsoft, Meta, Amazon, and dozens of other companies that own, operate, or lease data-center capacity. In comments to PJM, the coalition warned that by imposing NCBL status on data centers, the grid operator “risks exceeding its jurisdictional authority” over customer interconnection and interruptibility status, which are generally managed by utilities regulated at the state level.
“PJM has not provided a defensible rationale for creating this new class of service, and on its face the proposal is unduly discriminatory,” the coalition wrote.
PJM responded by pulling the NCBL concept from its next round of proposals, instead offering new data centers a voluntary method to commit to curtailing their peak power use through tweaks to a structure called “price-responsive demand,” or PRD.
As PJM explained in an October update, “With these changes, PRD becomes similar to voluntary NCBL,” since data centers that opt in would be exempt from paying for capacity but be obligated to “reduce demand during stressed system conditions.”
The big question is if data-center developers will choose to act at the scale required to “move the needle,” as analytics firm ClearView Energy Partners put it in a November research note. The authors wrote that, according to their observations in recent PJM meetings, “it’s far from clear whether new large load[s] would take service via this voluntary program.”
Consumer advocates aren’t happy with the data-center industry’s resistance to mandatory controls. Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based consumer-advocacy group, told Canary Media that the Data Center Coalition’s positions “are generally disappointing, given how some individual members of the DCC have shown a willingness to hammer out decent solutions that actually take responsibility for their own costs.”
Summers is referring to a handful of efforts by tech giants and data-center developers to use their own capacity resources to reduce their grid impacts. One such rare example is an agreement Google reached in August with PJM utility Indiana Michigan Power that commits the tech giant to bringing additional new capacity online and lowering power use during times of peak demand to alleviate the impacts of expanding a massive data center in Fort Wayne, Indiana.
Most of the groups submitting proposals to PJM agree that its new rules should enable data centers to fast-track development by paying for generation and other capacity resources to serve their own needs. Stakeholders also agree that data centers that can use less power during times of peak demand should be rewarded for the relief that would provide to PJM’s system.
The Data Center Coalition has also won backing from the governors of Maryland, New Jersey, Pennsylvania, and Virginia, four states in PJM territory courting data centers for economic development. Those governors joined the coalition in submitting a proposal for the fast-track process that would task state regulators with expediting interconnection for data centers that can add enough new generation capacity to the grid to cover their energy demand at the time they are connected.
But groups arguing for mandatory restrictions say these alternatives may not take effect quickly enough to prevent data-center growth from outpacing the capacity of PJM’s grid.
PJM’s notoriously backlogged interconnection queue is impeding the addition of new power plants to the system. The grid operator’s efforts to fast-track new generation resources have yielded only a handful of projects expected to come online before 2030.
PJM is still in the early stages of developing options to add capacity to existing generators, such as pairing batteries with solar and wind farms. And proposals that let data-center developers tap into the flexibility of virtual power plants remain a work in progress.
Meanwhile, PJM’s grid is only just beginning to feel the pressures of data-center expansion. The latest forecasts of large-load growth across PJM territory show 32 gigawatts of additional demand by 2028 and about 60 gigawatts by 2030, or a 37% increase from PJM’s peak load today, according to the Maryland Office of People’s Counsel, the state’s consumer advocate.
The sheer scale of proposed data-center construction beggars belief. To meet that projected demand, “by 2028, [developers] would have to be investing about $1 trillion within PJM in the next three to four years,” David Lapp, who leads the Maryland office, said during a press conference last month. “That’s an insane amount of money.”
Many groups are arguing to keep price caps on PJM’s capacity auction in place to mitigate the pass-through costs of rising data-center demand. They’re also pushing for PJM to order utilities to more stringently clear their load forecasts of speculative or redundant data-center applications, which experts agree are inflating expectations of how much load utilities and grid operators will have to serve.
But utilities, power-plant owners, data-center developers, and the tech giants spurring the AI boom have little reason to constrain these outsized growth plans, or to concede to restrictions on their peak power use, Lapp said. These are “some of the most powerful corporations in the world, all increasing their bottom line on the backs of existing customers,” he said.
As the 20th century ended, the National Academy of Engineering chose the top 20 engineering achievements of the past 100 years. At the top of the list was electrification, which beat out space travel, automobiles, computers, and the internet.
The 21st century may also be defined by electricity. The future unfolding before our eyes — from advances in artificial intelligence (AI) and automation to the electrification of transportation — depends on vast and growing quantities of electricity. The International Energy Agency (IEA) expects global electricity consumption to grow by nearly 4% annually through 2027 and declared the world is entering a “new Age of Electricity.”
With the world increasingly dependent on electricity, grid resilience is essential. Unfortunately, threats to grid resilience are quickly growing in both volume and seriousness. Extreme weather events, for instance, are now more frequent and powerful. The U.S. experienced an average of 23 natural disasters causing at least $1 billion in damages each year between 2020 and 2024, compared with just nine per year over the prior three decades.
Other challenges to a resilient grid include the influx of distributed energy resources (DER), such as rooftop solar, energy storage, and electric vehicle (EV) charging, which can create two-way power flows, overload local feeders, and cause voltage fluctuations that strain grids. As the volume of DERs has spiked, so too has the threat from cybercriminals, who take advantage of the increased attack surface that so many grid-connected assets provide. The number of cyberattacks on U.S. utilities increased by 70% from 2024 to 2023.
The avalanche of threats to the grid was enough for the North American Electric Reliability Corporation President Jim Robb to warn of a “five-alarm-fire” for grid reliability. And when the grid is not resilient to growing threats, there are real-world consequences.
Between 2000 and 2023, for example, 80% of all major power outages were due to weather — primarily extreme weather including severe winds and thunderstorms, winter storms, and hurricanes. A recent study published in the journal Nature Communications found that one-, three-, and 14-day power interruptions reduce GDP in the area impacted by $1.8 billion, $3.7 billion, and $15.2 billion, respectively.
Utilities understand the importance of a resilient grid and have long been focused on improving their System Average Interruption Duration Index (SAIDI) and System Average Interruption Frequency Index (SAIFI) scores. However, the existing tools and approaches to resilience planning and operations are inadequate to today’s challenges. Siloed outage management systems (OMS), supervisory control and data acquisition (SCADA) systems, and geographic information systems (GIS) combined with advanced metering infrastructure (AMI) data, static studies, and limited DER visibility result in fragmented, slow, and ultimately inadequate approaches to resilience.
A modern approach to grid resilience
The key paradigm shift that utilities need to make is to go from imprecise and reactive resilience strategies to proactive planning driven by full grid visibility and sophisticated data analysis. Software platforms with access to OMS, SCADA, GIS, and other utility data sources make that shift possible by providing a foundation for a comprehensive analysis, which is impossible to do when information is siloed.
With comprehensive data, software can perform three types of analysis that are essential to grid resilience in today’s complex environment:
The best software platforms don’t just identify risks and vulnerabilities. They also translate results from analysis into recommendations for improved resilience through infrastructure investments, operational changes, demand response, strategic DER deployment, and other measures.
Transmission and distribution system operators worldwide face an increasingly common resilience challenge. “We are seeing massive increases in load from the electrification of vehicles and heating and cooling systems, as well as from data centers, coupled with increased variability from renewable energy. This is creating a greater need for analytical and optimization software solutions,” said John Dirkman, vice president of product management at Resource Innovations, whose Grid360 software platform provides contingency, sensitivity, forecasting, and critical-load analysis to help utilities understand and address resilience challenges.
Recently, a large utility in Europe worked with Resource Innovations to model various loading scenarios, including what would happen if 10% or more EVs began charging in specific neighborhoods. The analysis identified where the added EVs would strain transformers and feeders and then produced a system heat map showing where the grid would be most vulnerable.
The software also provided recommendations to address potential problems. It analyzed the utility’s urban distribution system, where much of the infrastructure is underground and grid upgrades would be expensive and disruptive. The analysis suggested alternative actions to provide increased flexibility: demand response to reduce peak load, battery storage or vehicle-to-grid capabilities to provide localized system backup, and strategic placement of switches and power electronic devices to shift load between feeders.
While utilities around the world face different specific threats to grid resilience, the value that software can deliver in analyzing the grid for risks and suggesting tangible action is similar. For instance, in wildfire-prone regions, software allows utilities to systematically assess vulnerability by overlaying grid networks onto topographical and fire-potential maps.
This highlights the transmission and distribution lines that face the highest wildfire risk — in places like California, that is often in difficult-to-access canyon areas. Contingency analysis provides valuable intelligence, such as alternative routes if a line goes down during a fire and how much load those backup options can serve. Analysis can also suggest where backup generation or storage is most needed.
One example of software that does scenario planning by integrating data from multiple utility systems to model the grid under stressed conditions is Resource Innovations’ Grid360 Grid Impact Assessment System (GIAS). The web-based platform allows utilities to simulate everything from wildfire impacts to DER integration challenges and cyberattacks. This provides system planners and operators with real-time visualization and forecasting tools to prevent predicted problems with voltage, loading, and power quality before they occur. Grid360 GIAS also integrates with Resource Innovations’ iEnergy platform for interconnection, demand-side management, and demand response, allowing utilities to coordinate both infrastructure investments and customer-side resources to strengthen resilience.
“Our software allows the utility to model the grid and find ways to provide power under any scenario,” Dirkman said. “That kind of planning can be done either on a very specific location basis or network-wide.”
“Our software allows the utility to model the grid and find ways to provide power under any scenario. That kind of planning can be done either on a very specific location basis or network-wide.”
John Dirkman, Vice President of Product Management at Resource Innovations
There is little chance that threats to grid resilience will diminish in the future, and the consequences of inadequate resilience can be measured in billions of dollars and growing risks to public safety. It is not a time to rely on reactive approaches. Software platforms that analyze unique vulnerabilities and recommend solutions give utilities the tools they need to act proactively and ensure the grid remains reliable as the world enters its new age of electricity.
Surging power demand from new data centers is reaching unprecedented — and potentially unrealizable — heights.
Over the next five years, U.S. utilities expect to see new electricity demand equal to 15 times New York City’s peak load, the majority of which will come from data centers.
So finds a report released Tuesday by Grid Strategies tracking the growth in power demand for data centers being built and planned to feed tech giants’ artificial intelligence ambitions. The consultancy’s tally of utility load forecasts indicates that peak grid demand will boom to 166 gigawatts by 2030, a sixfold increase from what was forecast three years ago.
“These are just phenomenal numbers for an industry that was built over the past couple of decades to handle much lower load growth,” said John Wilson, Grid Strategies’ vice president and the report’s lead author.
Data centers make up roughly 90 gigawatts of that forecasted load growth, a reflection of the hundreds of billions of dollars that tech giants are pouring into AI, as well as smaller but still substantial investments in crypto-mining operations, enterprise cloud computing, telecommunications, and other IT services.
Back in late 2023, Grid Strategies offered an early warning about how data centers were causing power demand to spike. It has also cautioned that outsize plans for growth in key U.S. data center hot spots are threatening to exceed the physical capacity of power plants and power grids. These factors could result in higher costs for consumers and more carbon emissions as utilities plan to ramp up fossil-fuel use to serve new demand.
But Grid Strategies and others have also counseled that utilities might be exaggerating things.
For one, there’s lots of double-counting going on; data center developers often pitch the same project in multiple utility jurisdictions while searching for the best deal. For another, the gold-rush quality of the data center boom is leading developers to make speculative proposals for projects that may never materialize.
For its new report, Grid Strategies compared utility forecasts with alternative methods of projecting data center load growth, such as industry analysis of technological bottlenecks, and found that utilities may be overstating data center demand by as much as 40%.
That discrepancy indicates how utility forecasts need to better reflect underlying uncertainties, Wilson said. This is particularly important for the rising number of data centers being planned that will use a gigawatt or more of power — the equivalent of a small city’s total power demand.
“The fact that these facilities are city-sized is a huge deal,” Wilson said. “That has huge implications if these facilities get canceled, or they get built and don’t have long service lives.”
Utilities are using their sky-high forecasts to justify massive investments in power plants and grid infrastructure around the United States.
Those forecasts, in turn, have already driven up utility bills in some regions, including those for many of the more than 67 million people served by PJM Interconnection, the country’s biggest energy market. For PJM, future data center forecasts have driven capacity costs — the prices paid to power plants and other grid resources to meet peak grid demand — from $2.2 billion in 2023 to $14.7 billion in 2024 and to $16.1 billion in this summer’s capacity auction.
PJM customers in heavily impacted states like New Jersey are taking notice. Popular anger at rising bills helped propel Democratic gubernatorial candidates who pledged to combat increasing power costs to outsize wins in New Jersey and Virginia elections earlier this month.
Many utilities aim to meet this surging demand by building new fossil-gas-fired power plants, which could not only increase costs for customers but also slow down the transition to clean energy. Across much of the Southeast and the Midwest, in particular, utilities aim to build gigawatts’ worth of these power plants, which emit carbon dioxide as well as toxic air pollution.
In Virginia, home of the world’s largest data center hub, Dominion Energy is proposing gigawatts of new gas-fired power that, critics warn, could make it impossible for the utility to meet a state-mandated phaseout of fossil fuel use by 2045. The utility argues that the plants are needed to maintain reliability in the face of data center growth.
Meanwhile, in Georgia, major utility Georgia Power is seeking regulator permission to build gigawatts of gas-fired power capacity to meet load forecasts swollen by proposed data centers. Opponents fear that the plants will balloon already fast-rising utility bills, and this month voters overwhelmingly elected to the state’s Public Service Commission two Democratic challengers who ran on a platform of constraining unchecked utility spending.
Elsewhere, state lawmakers, regulators, and data center developers are seeking ways to accommodate growth without overwhelming the grid and utility customers.
In Texas, the country’s second-hottest data center market outside of Virginia, “large load” forecasts within the territory served by the Electric Reliability Council of Texas (ERCOT) have nearly quadrupled over the past year, representing a potential doubling of its peak demand. The state legislature passed a law this spring that requires new data centers to disconnect at moments of peak grid stress, although the rules for how that will happen are still being worked out by ERCOT and state regulators.
Other states are also passing laws and instituting regulations aimed at forcing data center developers to bear the cost of new power plants and grid infrastructure. And some data center companies are promising to shift when they use power in order to relieve peak grid strains that drive much of the costs that utilities face. PJM, for its part, is considering new rules aimed at requiring new data centers to reduce their impact on the region’s capacity costs, although consumer and environmental advocates say the grid operator’s proposed plans don’t go far enough.
The Grid Strategies report also highlights that U.S. utilities and grid operators haven’t yet committed to expanding the transmission grid at the scale needed to support the growing electrification of vehicles, buildings, and industries — however the data center demand plays out. “Even conservative growth trajectories outpace recent years and would require substantial grid expansion to accommodate,” it notes.
Ultimately, Wilson suggested that utilities, lawmakers, and regulators will need to make sure the cost of meeting whatever demand does materialize is not shifted to everyday customers.
“We’ve got a gigantic amount of additional load over the next five years to manage from a supply-chain, planning, and construction standpoint,” he said. “These are questions that regulators and intervenors should be asking, and not just trusting the utilities, who say, ‘This is the way we’ve always done it.’”
Due north of Chattanooga, a power line runs through a wooded tract called Sale Creek before it dead-ends at the Tennessee River. On Oct. 8, this line lost power. But the lights stayed on for nearly 400 customers because Sale Creek has a new tool to neutralize outages.
Chattanooga’s municipal utility, EPB, had installed a Tesla Megapack battery system on this lonely stretch of the distribution grid back in June. If anything knocked out the line, residents would have 2.5 megawatts/10 megawatt-hours of storage capacity at their disposal while crews fixed the problem.
In this case, utility workers unexpectedly needed to de-energize the line to finish making repairs. EPB was able to switch the neighborhood over to battery power for about half an hour until the job was done. Without the battery, EPB would have had to tell its customers it was cutting off their power on purpose.
“This was the first time we used it in an outage situation,” said Ryan Keel, president of the energy and communications business unit at EPB. “In the future, it’ll be even more unplanned. It’ll be a response to a tree falling through the line or a car hitting a pole or something.”
EPB, which serves some 500,000 people across 600 square miles, plans to roll out more targeted, resilience-oriented batteries to other outage-prone stretches of its grid. The nonprofit public power company currently has a 45-megawatt fleet of batteries, almost all of which were built this year. Besides keeping the lights on, they save money for the whole customer base by lowering the utility’s peak electricity consumption.
The United States is racing toward yet another record year of grid battery construction, as power companies tap lithium-ion batteries to store solar power, improve grid reliability, and free up capacity for new data centers. Most of these batteries are getting installed in California and Texas, where they’ve pushed down wholesale prices and banished heat wave–induced power shortages. Utilities elsewhere, though, too often bide their time in exhaustive studies of the technology, which is new by their standards, despite its mass deployment in some regions.
But batteries are starting to catch on in Tennessee: The Tennessee Valley Authority, the federal entity that generates electricity for EPB and scores of other local power companies, just committed to build 1.5 gigawatts of grid batteries across its territory by the close of 2029, its largest battery deployment by far. The TVA board approved this in its November meeting, setting the stage for the utility to solicit competitive bids from battery developers, spokesperson Scott Fiedler told Canary Media.
And although Chattanooga’s battery buildout is far smaller than what’s happening farther west, or even the installations planned by TVA, it shows how a responsive local utility can adopt new clean-energy technology to make life a little better for its customers. It doesn’t take a massive R&D budget or piles of cash from Wall Street shareholders — just a willingness to embrace a readily available technology.
EPB had explored batteries for years. It researched them with the Department of Energy and Oak Ridge National Laboratory, located 100 miles northeast of Chattanooga. But EPB moved beyond research and installed a solar-and-battery microgrid at the Chattanooga Airport, learning how to work with the technology in practice.
Building on that experience, EPB leaders took a new look at batteries after Winter Storm Elliott rocked the region just before Christmas 2022, leaving TVA short on supply as households cranked their electric heating. For the first time since its founding in 1933, the TVA had to cut power to its customers in order to avoid damaging the grid infrastructure. So it told local power companies that they had to reduce demand by a certain amount.
“That event shaped our strategy,” Keel said. “We want to deploy a large amount [of batteries], because it gives us some local insulation from what may be happening on the TVA system that could impact our customers.”
Homes in TVA’s territory use a lot of electric heating and cooling, which drives grid peaks in both winter and summer. Typical hot summer and cold winter peaks for EPB reach 1,200 megawatts of demand, Keel said, but the utility set a demand record above 1,300 megawatts this January.
That means the current battery fleet meets just a small percentage of the total peak demand — enough to help on the margins, but pretty limited in its impact. Keel said his strategy is to raise that capacity to around 150 megawatts.
“Our hope is that if TVA calls for a 10% required reduction of our load, we can achieve that completely with the battery systems that we’ve put in, and we don’t need to do any unplanned outages to customers at all, like we had to” during Winter Storm Elliott, Keel said.
That battery strategy is akin to an insurance policy, responding to the concerning frequency of polar vortices and extreme heat in recent years. But the batteries don’t just sit around waiting for record cold snaps or heat waves. When the batteries aren’t acting as local backup, EPB puts them to work to save money for all customers.
When EPB buys power from TVA, it pays a demand charge for the hour of highest consumption each month. By discharging the batteries when it looks like a peak hour is approaching, EPB can shave its monthly charge. That lowers the rates it pays to TVA, which puts downward pressure on utility bills for Chattanooga residents.
“We make our decisions based on community benefit,” said J. Ed. Marston, EPB’s vice president for strategic communication. “The more we can keep our costs down operationally, the more we can avoid having to do electric rate increases that impact our customers.”
This dynamic parallels the way Vermont utility Green Mountain Power pays for a program that helps customers install home batteries: The utility dispatches all the small-scale batteries to reduce its peak-demand charges to the New England grid operator.
EPB expects to get payback on its battery installations within five years from the reliability and peak-demand uses. The utility has elected not to run the batteries on a daily basis, because the wear and tear that frequent cycling puts on batteries offsets the benefit of short-term savings on energy charges. (TVA territory doesn’t have wholesale markets that let batteries bid in for various services to make money.)
EPB’s battery buildout puts it ahead of many bigger peers, in both absolute and relative terms.
It’s part of a pattern of the municipal utility embracing new technology to help its residents.
Perhaps most strikingly, the nonprofit installed fiber internet in city homes in 2009, before for-profit telecom providers were widely offering it. EPB became the first company to sell gig-speed internet to an entire community network, Keel said. (Current monthly rate for 1-gig Wi-Fi: an envy-inducing $67.99.)
That fiber also improves the efficiency of the electric grid: EPB piggybacked on the fiber to upgrade its grid network to advanced metering infrastructure, which sends real-time information to the utility and allows it to respond instantly to issues. EPB won accolades for the number of “smart grid” automated devices on its high-voltage distribution system per mile or per customer, Keel said.
“EPB has been incredibly impressive and forward-thinking and on the leading edge — sometimes maybe even on the bleeding edge — of technology innovation, all in the spirit of working for the benefit of their customers,” said Matt Brown, regional vice president for the Tennessee Valley at Silicon Ranch, the major solar developer based in Nashville.
Silicon Ranch is working with EPB on a different kind of money-saving clean-energy project. A large-scale solar project in West Tennessee will produce 33 megawatts for EPB as part of TVA’s Generation Flexibility program, which lets local power companies generate up to 5% of their annual demand. The project is slated to be operating by mid-2028.
That solar development will be located outside EPB’s territory, where there’s more land available. So it won’t be able to help with local reliability in Chattanooga, the way that the community batteries do. But it will generate power at cheaper rates than those of TVA, which itself has cheaper rates than most U.S. utilities, meaning that EPB can pass those savings to its customers.
“Prices are going up on everything from food to energy to housing. This provides them comfort to be able to have some rate stability and flexibility,” Brown said.
America’s data centers used a whopping 176 terawatt-hours of electricity in 2023, representing 4.4% of the nation’s total power consumption. Those numbers are only going up as AI tools gain popularity, pushing computing loads higher. By 2028, data centers could gobble as much as 580 TWh of power, or 12% of the U.S.’s total electricity consumption that year, Lawrence Berkeley National Laboratory has projected.
The surge seriously complicates goals set by hyperscalers to slash planet-warming pollution — tensions that Canary Media discussed with Google and Microsoft during last week’s SOSV Climate Tech Summit.
Utilities from Virginia to Nevada are planning to build large numbers of gas-fired power plants and to extend the life of aging coal plants to satiate the tech industry’s rising demand — moves that could spike both utility customers’ bills and carbon emissions. Data centers themselves typically rely on diesel-burning backup generators to ensure our increasingly digitized world runs without interruption.
On the panel, I spoke with Lucia Tian, Google’s head of advanced energy technologies, and Sean James, Microsoft’s senior director of energy and data-center research.
Tian helps lead Google’s efforts to commercialize cutting-edge “clean, firm” technologies that could supply around-the-clock power to data centers. Google was among the earliest backers of Fervo Energy, a startup that’s operating and building next-generation geothermal plants in Nevada and Utah. The search giant has also signed a unique deal with Kairos Power to potentially develop a fleet of small modular nuclear reactors.
Microsoft, meanwhile, has inked a long-term power purchase agreement with Constellation Energy to support the company’s $1.6 billion plan to reopen its shuttered Three Mile Island Unit 1 nuclear reactor in Pennsylvania. James said that, inside its own fenceline, Microsoft is developing cleaner alternatives to diesel generators, such as hydrogen fuel cells and advanced batteries. The tech giant is also improving the design of server racks and other hardware to improve energy efficiency and reduce the need for new power capacity.
Tian and James emphasized the potential for data centers to operate more flexibly — limiting the strain on the broader grid and curbing utility costs. Google, for example, partnered with Omaha Public Power District in Nebraska last year to reduce its machine-learning load during severe weather events. More recently, the tech company signed demand-response agreements with the utilities Tennessee Valley Authority and Indiana Michigan Power.
The two panelists also shared their hopes that long-duration energy storage will eventually be able to commercialize and scale, bottling up enough power from wind and solar farms to provide days’ worth of backup for data centers. Today’s lithium-ion batteries typically only last a few hours, though startups are making progress on medium-term systems that can provide eight to 24 hours’ worth of power.
Companies like Form Energy are trying to push the envelope even further. Canary Media’s Julian Spector spoke with Form’s CEO Mateo Jaramillo about the firm’s 100-hour, iron-air battery technology at last week’s SOSV Climate Tech Summit. You can watch the conversation here.
A correction was made on Nov. 10, 2025: This story originally incorrectly identified an image of the Blue Mountain power plant as an image of Fervo Energy’s enhanced geothermal pilot in Nevada. Fervo’s project sends power to Blue Mountain.
Many households in rugged and rural southwest Virginia are already struggling to make ends meet. But they pay some of the highest electric rates in the nation, with prices that have risen at more than three times the pace of inflation over the last decade and a half.
Last week, residents of the Appalachian region voted to do something about it, joining Americans around the country in electing candidates who made affordability and spiking electricity bills central to their campaigns.
To wit: Voters in Montgomery and Roanoke counties elected Lily Franklin, a Democrat and former schoolteacher from Blacksburg, as their representative to the state House of Delegates. With 51% of the vote, she beat out a Republican incumbent in a district that voted for President Donald Trump three times in a row.
“It is a huge deal that we won this,” she told Canary Media.
The price of electricity wasn’t the only economic issue on voters’ minds as they cast their ballots across Virginia, giving Democrats the governor’s office, a larger majority in the House of Delegates, and a governing trifecta in Richmond. But Franklin said the topic came up again and again in her district, home to Virginia Tech as well as large swaths of mountain countryside.
“I talked to thousands of people across the district, and rising energy bills was a top concern,” she said. “I would hear it time after time — people were like, ‘My bill is almost three times what it was last year, and I haven’t changed anything.’”
Franklin is determined to tackle the problem when she’s sworn in on Jan. 14. “I’m not fixing inflation as a state legislator,” she said, “but I can work on energy in Virginia and bring down people’s bills.”
Of course, that’s easier said than done. But Clean Virginia, a Charlottesville-based nonprofit with a research division and a campaign arm that endorsed Franklin and numerous other candidates, just issued a report that could serve as a guide. The study homes in on Appalachian Power Co., or APCo, the investor-owned utility that serves all but a few patches of southwest Virginia.
“The last General Assembly session on the energy front was really dominated by intensive focus on the cost crisis in APCo territory,” said Brennan Gilmore, executive director of Clean Virginia.
That effort culminated in legislation heavily influenced by the utility that temporarily scaled back some fuel costs for customers, he said. “But it was not a holistic look at what the actual drivers of the crisis were, [or] a holistic look at how to resolve those crises.”
So, Gilmore’s staff spent months digging into regulatory filings in both Virginia and West Virginia, where APCo is headquartered. What they found is that base rates aren’t the main problem. Instead, add-on fees known as riders are the real culprits — and they typically receive far less regulatory scrutiny.
Riders, especially to fund grid upgrades, are hardly confined to APCo territory, rising in multiple jurisdictions nationwide and even sparking a popular internet meme that cheekily sums up the charges: “Distribution fee. Processing fee. … Transmission fee. Fee fee. Fee fi fo fum fee. Might as well fee. … Another dollar won’t hurt fee.”
In deep-red Patrick County, south of Franklin’s district on the border of Virginia and North Carolina, the internet hive mind mostly blames the monopoly-utility model for these costs, with scores of commenters on a local Facebook page bemoaning bills that doubled and even tripled in the span of a month.
The Clean Virginia report authors tend to agree, saying the rising bills overall are propelled by a regulatory system that “incentivizes utility overspending, inflates utility profits, and puts disproportionate costs on residential customers.” But the study also drills down on specifics.
The researchers note that Virginia’s 2020 Clean Economy Act, which requires APCo to sell 100% renewable energy by midcentury, is causing some of these riders. But they’re relatively paltry: Solar and wind generation to comply with the law makes up less than 1% of households’ monthly bills today, the report found, and is expected to comprise just 3% of monthly costs next year.
Riders for fuel costs and for high-voltage, long-distance electrical wires, by contrast, make up nearly half of the average household bill in southwest Virginia. Fuel costs more than tripled between 2007 and 2024. Transmission fees rose fivefold from 2009, when regulators first allowed them as a separate line item.
Fuel costs are closely tied to national markets for coal and gas, which make up over 80% of APCo’s power-generating capacity. Coal prices more than doubled in 2021 alone, the report says. Likewise, natural-gas prices jumped 540% between 2020 and 2022. Since APCo customers pay 100% of fuel costs, they bear the full brunt of these increases, while shareholders bear none, Clean Virginia notes.
“If you’re using generation technology that requires a lot of fuel, customers are going to pay more than if you use a renewable source with no fuel,” Gilmore said. “Add the volatility and the spike in natural-gas prices because of global and other economic issues, then you see a direct correlation between increased bills and fossil-fuel prices.”
But fuel fees appear to be rising for other reasons, too, the study says. The charges include power purchases from other utilities, and last year, the report notes, the Virginia attorney general found that APCo was buying coal power at above-market rates from an affiliate company, Ohio Valley Electric Corp.
“Legislators should urge [regulators] to order refunds if APCo’s interaffiliate power purchases exceed market benchmarks,” the report suggests.
APCo may also be using more coal power than is cost-effective.
Across the country, plant operators have scaled back use of coal-fired units not just because the fuel itself is expensive, but because the aging plants cost a lot to operate and maintain. Last year, the average run time for U.S. coal plants was a little over 40%. But regulators in West Virginia — where APCo operates two coal plants — have ordered the utility to run the facilities at least 69% of the time, the report says, citing testimony from a recent rate case.
Passthrough of volatile fuel costs is a common problem for utility customers, Gilmore said. “But there are some specific APCo elements of this,” he said, “including uneconomic dispatch of their coal plants, and a sort of self-dealing with some of the APCo affiliate-owned coal plants.”
Perhaps the biggest challenge is the utility’s ballooning transmission fees. One problem, according to the study, is that the cost of building and maintaining these high-voltage electric lines in the area’s hilly terrain is spread among relatively few customers. The much larger Dominion Energy, for instance, charges less than half as much in transmission costs per household as does APCo.
Data centers could well be a factor, too. Though virtually none are in southwest Virginia, hubs in Ohio, northern Virginia, and elsewhere are crowding the grid run by the regional transmission organization PJM Interconnection. PJM allocates the resulting costs for upfitting lines across its member utilities, without factoring in where these large electric loads are located.
For its part, APCo said in an emailed statement that “investing in and maintaining [our] generation, transmission and distribution network is essential for minimizing and shortening outages, accommodating growing energy demands and integrating new energy sources.”
Like utilities nationwide, the statement continued, APCo faces high interest rates and inflation, driving up a number of the expenses associated with generating and delivering power, including “higher material and labor costs; … cost recovery for major storms; fuel-related costs not yet recovered through the fuel factor, and cost recovery for investments made in generating plants and distribution infrastructure.”
The company also touted its energy-efficiency programs and noted that a $10 decrease in fuel costs took effect Nov. 1.
The price cut grew out of the law Gilmore said inspired his group’s study, which notes, “given that methane gas prices are projected to double between 2024 and 2026, fuel costs are likely to increase again in the near future.”
Incoming Del. Franklin called the reduction woefully insufficient.
“It’s not a whole lot of relief when your wages haven’t gone up any, your groceries are still more expensive, and your rent’s really high — or your property taxes have gone up,” she said. “We have to have a more substantial plan to bring down rates.”
The recommendations in the plan by Clean Virginia, such as requiring utilities to pick up a share of fuel costs and reducing reliance on riders, echo a recent report that grew out of a bipartisan resolution from the 2024 General Assembly.
But Franklin believes neither party is fully united on how to lower prices.
“There are folks that think if we have an all-of-the-above approach — that is how we bring down costs,” she said. “Then you’ve got some people on both sides that think nuclear is the direction.”
Neither of those are quick fixes, Franklin said, with lead times of five to seven years for new gas plants and even longer timelines for nuclear.
Her own aspirations for office range from sweeping reforms, like prohibiting APCo and Dominion from making campaign contributions, to incremental steps like shifting some of the rate burden from residential customers to industrial ones and providing incentives for rooftop solar.
“And at the end of the day, we’ve got to help the people,” she said, “and that’s what I’m going to remind members of my party.”
Electricity is getting more expensive — and Americans are getting worried.
Just look at last week’s election, when Democratic candidates who put a spotlight on energy affordability won key races in Virginia, New Jersey, and Georgia.
Fortunately, state and local lawmakers, including those just elected, have the authority to do something about this increasingly urgent problem. Here are three immediate steps they can take to save consumers money on their power bills.
State regulators can lower skyrocketing electric bills practically overnight by reducing utility profit rates. Investor-owned utilities earn a guaranteed profit on every dollar they spend. State public utilities commissions set these profit rates, and right now they’re way higher than they used to be.
Former utility executive Mark Ellis estimates the average American household overpays utilities by $300 per year, because the companies extract 3 to 7 cents more on every dollar of investment than they ought to.
Utilities consistently try to scare regulators off from lowering their excessive profits, claiming service quality will decrease or costs will actually rise — but there’s little evidence that doing so will negatively impact consumers.
We know that utilities can maintain high-quality service with lower profit rates because they’ve done it before. Recent research by RMI shows that utilities still received enough capital to build new infrastructure when profits were more reasonable in the late 1970s and early 1980s. Returning profit rates to those lower levels can also more than offset any increases in borrowing costs that might result from impacts to credit ratings.
Lawmakers can save consumers billions by adjusting incentives to pay utilities for performance rather than construction.
Under current rules, utilities profit significantly more from building new infrastructure than from investing in energy efficiency or cheaper upgrades to existing poles and wires. Most analyses of high electricity prices find that utility spending on transmission and distribution infrastructure is a main or major culprit.
The more utilities build, the more they profit, so they build a lot. Every grid problem looks like a nail to a utility that can use a gold-plated hammer to “solve” it — and consumers get bent out of shape as a result.
Customers in New York saved big when, in 2013, the state directed utility Con Edison to prioritize reducing energy demand via efficiency initiatives and solar panel installations. The investment successfully put off a $1 billion substation upgrade, saving New Yorkers $500 million in profits not paid to utility shareholders on top of $800 million in avoided hardware upgrades.
We could significantly reduce electricity use with energy-efficiency investments that routinely cost less than the fossil-fuel power generation favored by most utilities.
Instead, utility grid spending has exploded in recent years, outpacing inflation and electricity sales combined, according to the Energy Information Administration. And for each dollar of capital utilities invest in infrastructure, they’ll extract as much as 50 cents back in profits from customers over the life of the pole, transformer, or equipment.
A few states have comprehensive programs requiring utilities to prioritize cost-effectiveness rather than construction, but only Hawaii has discarded the conventional wisdom connecting utility profits to spending. State legislators can act now to align utility profit motives with performance, or at least efficient investment, and lower electricity bills in the process.
Local solar and batteries make electricity right where people use it, and more of each saves everyone money. Models suggest that dramatically scaling up energy resources like rooftop solar and batteries, and coordinating them with tools like smart thermostats, could cut future grid costs by half a trillion dollars.
But state and local laws, and utilities’ own policies around crucial processes like connecting to the grid, are mostly written to block and slow down small-scale clean energy.
It’s up to lawmakers to enact policies that remove those barriers by, for example, simplifying and automating permitting and zoning requirements, allowing non-utility ownership of solar projects, and fairly compensating solar owners through net metering. They’ll have to overcome vehement opposition from utilities, which see these kinds of policies as endangering their profits and allocate their lobbying dollars accordingly.
Electricity prices are rising at more than twice the rate of inflation. The Trump administration’s obstruction of clean energy and commitment to fossil fuels, particularly coal, are expected to make bills climb even further. Data-center development won’t help either. Most Americans feel this trend happening, and they are concerned.
It’s time to get a handle on the problem.
We’re all tired of paying more for electricity. We can pay less if state legislators and utility regulators seize the moment and act in the interest of consumers — rather than the shareholders of utility companies.
For decades, Puerto Ricans have struggled with a dysfunctional energy system. Now residents are grappling with two very different plans for how to fix it.
President Joe Biden’s administration invested heavily in distributed generation: rooftop solar and battery arrays on homes and businesses across Puerto Rico. But President Donald Trump has rolled back those commitments, redirecting funds toward hardening the grid and shoring up centralized — mostly fossil-fueled — power production.
Energy experts and community leaders say that continued reliance on fossil-fuel power plants is harmful and that sending electricity on transmission lines across rugged mountains plagued by hurricanes is impractical. Distributed generation, they argue, is the best way to supply Puerto Ricans with reliable, affordable power that can withstand natural disasters.
A federal judge’s Oct. 2 ruling on hurricane recovery funds offers a measure of hope to those advocating for this latter vision in the archipelago, which includes the main island and two smaller inhabited islands: Vieques and Culebra.
In September 2017, Hurricanes Irma and Maria battered Puerto Rico in quick succession, devastating homes and infrastructure and causing the lengthiest blackout in U.S. history, leaving some households without power for over a year. The Federal Emergency Management Agency is tasked with rebuilding the island’s energy infrastructure, which still has frequent outages. In 2020, the first Trump administration awarded $9.6 billion for this purpose, and other federal grants bring the pot of FEMA recovery funds for the energy system to over $12 billion.
In its 2020 grid-rebuilding study, FEMA proposed to fix and harden the existing grid and repair fossil-fuel plants. The agency made only cursory mention of distributed solar as supplemental power at critical facilities.
Community groups argued in official comments that instead of rebuilding a grid that has proved vulnerable to disaster, the agency should use federal funds for distributed solar paired with batteries. That would give homes, businesses, hospitals, and schools dependable power even when the grid goes down. FEMA did not incorporate that feedback into its final proposal in 2021, so in April 2023 the community groups, plus the national conservation organization Center for Biological Diversity, filed a lawsuit alleging that FEMA had violated the law by failing to study the environmental impacts of its plan or to consider other alternatives.
Federal Judge Jay A. García-Gregory ruled in the plaintiffs’ favor this October, sending FEMA back to the drawing board to fully study the impacts of various grid-overhaul alternatives, including one based on distributed solar.
“This is a pretty good outcome, an order from a federal district judge requiring FEMA to consider distributed renewable energy for all of this historic amount of funding,” said Ruth Santiago, an environmental attorney who grew up and lives in Salinas, a coastal fishing town located near an oil-fired and a coal-burning power plant.
Under the National Environmental Policy Act (NEPA), before undertaking any project that could significantly affect the “human environment,” a federal agency must release an environmental impact statement after studying the direct and indirect effects the project would have, as well as its cumulative effects with other existing or planned developments. The agency also must take a “hard look” at alternative ways to achieve the same goals.
FEMA argued that its grid-rebuilding plans would not have a significant impact, therefore an in-depth study wasn’t required.
But in their lawsuit, the community groups argued that the impact of FEMA’s rebuilding plans would indeed be massive, and that the agency failed “to engage in meaningful analysis of the environmental effects” of its rebuilding plans.
The judge agreed and ordered FEMA to study the impacts of its plans as well as the alternatives the community groups had proposed: rooftop solar, microgrids that can be disconnected from the main grid in case of a larger outage, and incentives for energy efficiency and power use at times of lower demand.
It’s a measured victory though: FEMA can appeal the decision, take months or years to do the study, and even ignore its own environmental impact statement, as the agency isn’t required to take any action based on its findings.
“If they do an environmental impact statement, it doesn’t mean they will adopt distributed renewable energy options,” said Alfredo Vivioni, a member of the board of directors of the community organization Frente Unido Pro-Defensa del Valle de Lajas (United Front for the Defense of the Lajas Valley), one of the plaintiffs in the lawsuit. “But at least it requires them to make a deeper evaluation of the variables.”
Meanwhile, Trump has threatened to eliminate FEMA altogether, and he has long been skeptical of efforts to mitigate and prepare for climate change.
“When you have a president that says climate change is a hoax, this is going to be interesting,” Vivioni said. “It could also be sad. But you learn to fight and keep on going. You build stamina for this.”
Rebuilding Puerto Rico’s electricity system is a challenge with very high stakes.
More than 4,000 Puerto Ricans died as a result of Hurricane Maria. Lack of electricity was a contributing factor, since residents could not refrigerate medicine or run medical equipment, and ailing people sweltered in high heat and humidity without air conditioning. The Centro de Periodismo Investigativo (Center for Investigative Journalism) in Puerto Rico told the stories of 166 people who died specifically from a lack of electricity.
Advocates for distributed power warn that more fatalities are likely if residents aren’t equipped with solar and batteries to survive future natural disasters. Meanwhile, residents — particularly those on the south coast of the main island — suffer health effects from fossil-fuel generation, and the continued reliance on fossil fuels will contribute to the very climate change–related events that damage the grid and endanger electricity supply, as the community groups pointed out in their lawsuit.
Perpetuating the existing energy system would be an environmental injustice, they argue, since the coal and oil plants on the south coast are located amid some of the island’s poorest communities.
They point to studies showing it is possible to power Puerto Rico with distributed solar while phasing out centralized fossil-fuel plants.
The groups’ lawsuit cites a 2020 National Renewable Energy Laboratory report that found distributed solar could generate more power than the archipelago needs. And it notes that a 2021 Cambio PR and Institute for Energy Economics and Financial Analysis (IEEFA) study found that by 2035, operating a system relying on 75% distributed generation — including rooftop solar, batteries, and microgrids — would be less expensive than operating the current grid, measured in the price of energy per kilowatt-hour.
Rooftop solar paired with batteries, sometimes networked among houses and businesses into microgrids and virtual power plants, has already been invaluable for many Puerto Ricans. Grassroots organizations, tapping federal and philanthropic funds, have installed rooftop solar in communities across the island, as Canary Media chronicled in a 2022 special reporting project.
Biden Energy Secretary Jennifer Granholm touted distributed solar during multiple visits to Puerto Rico, and Biden EPA Administrator Michael Regan talked with residents about the burden of coal power. In December 2022, Biden signed a funding omnibus bill including $1 billion for rooftop solar for low-income households and households with disabilities in Puerto Rico.
As of June 2025, 1.2 gigawatts of grid-connected rooftop solar were installed on homes and businesses, according to the IEEFA, supplying more than 10% of the total energy used.
But the need for more distributed solar is still great. The IEEFA determined that at least 350,000 low- and moderate-income households are unlikely to install rooftop solar without financial assistance, based on 2021 data from the National Renewable Energy Laboratory, leaving them vulnerable during storms.
The Trump administration has gutted such assistance. Federal funding for solar in low-income areas nationwide was canceled, over $156 million of which was promised to Puerto Rico. On Oct. 1, the Department of Energy announced $365 million in Biden administration funds for rooftop solar and battery storage will be redirected to “strengthen grid stability and harden critical infrastructure.”
From his hillside porch on Puerto Rico’s south coast, retired sports medicine professor Miguel Rivera can see a coal-fired power plant, an oil-fired power plant, and an increasingly vast expanse of solar panels stretching across the otherwise lush, green landscape. He is among the residents and experts who say distributed generation is the only real solution for Puerto Rico.
As of spring 2024, 235 megawatts of utility-scale solar were deployed in Puerto Rico, and over 800 megawatts’ worth of such contracts were approved and executed by the federal fiscal control board, which oversees Puerto Rico’s financial affairs.
AES Puerto Rico, the company that owns the coal plant, has installed solar farms on the south coast near Rivera’s home, with the 200-megawatt solar project Marahú scheduled to go online this year. While the installations provide clean energy, they pose the same problem as fossil-fuel plants: The electricity they generate needs to be transported on vulnerable long-distance transmission lines. Meanwhile, the solar panels are being built on swaths of flat, fertile land ideal for farming, which is increasingly scarce on the island.
Though FEMA’s previous energy study did not delve into utility-scale solar, beyond backup power at critical facilities, Santiago said its pros and cons must be considered in the new study.
“What the utility-scale projects, whether renewable or fossil, have in common is that they’re very centralized, and they’re concentrated in one place and then depend a lot on high-voltage transmission lines and towers and substations,” said Santiago. “Distributed renewables on rooftops, parking lots, as close as possible to the point of use — avoid what happened with the existing system after Hurricane Maria. It’s so clear that this is a reasonable opportunity that needs to be considered. Otherwise, we will have more loss of life in the next storm.”
On an October Sunday afternoon a few weeks after the judge’s ruling, Rivera drove through the mountains with his wife, Maridalys Nieves, and friends including José Cora, leader of Acción Social y Protección Ambiental (Social Action and Environmental Protection), a grassroots local environmental justice organization.
They pointed out the broken power lines swinging from poles and lines drooping under curtains of green vines. The well-being and safety of residents in small mountain villages is threatened by the deteriorating power lines. Rooftop solar panels paired with batteries could make these locals largely energy self-sufficient.
But given the median household income of under $25,000 a year in the mountainous regions — Jayuya, Orocovis, and Utuado — that the friends drove through that day, it is nearly impossible for many residents to pay for solar. Cora, an IT professional who maintains computer servers, noted that despite his commitment to clean energy, his family can’t afford to install solar and batteries on their own home.
As the car descended down a mountain, Nieves received a social media alert on her phone that many would not have power because of a problem at the coal plant.
Rooftop solar and batteries are the only way to free residents from such frequent occurrences, the friends agreed. They hope FEMA follows the judge’s orders and does a thorough study, and then funds scores of distributed solar arrays as a result.
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