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California lawmakers face a make-or-break choice about the state’s biggest and most successful virtual power plant program: Give it enough money to keep running this summer or scrap it altogether.
The administration of California Gov. Gavin Newsom (D) has proposed ending the four-year-old Demand Side Grid Support program, which pays homes and businesses to send rooftop solar power back to the grid or reduce their energy use during times of peak electricity demand. DSGS has more than 1 gigawatt of capacity, making it one of the biggest VPPs in the country.
The proposal has set off alarm bells for environmental advocates and clean energy companies, which say that eliminating the program would be a costly mistake. And some state lawmakers briefed on the plan have questioned the logic of ending a program that’s successfully delivering grid relief.
DSGS backers argue that the program saves money not only for those who participate but also for all Californians, who face some of the highest utility rates in the country.
A study conducted by consultancy The Brattle Group and commissioned by Sunrun and Tesla Energy, two companies with large numbers of solar-and-battery-equipped customers enrolled in the program, indicates that “DSGS is a significantly lower-cost alternative” to relying on costly fossil gas–fired power plants or other resources available during grid emergencies.
In February, the Newsom administration’s Department of Finance issued two budget proposals regarding DSGS. One proposes ending DSGS, which is administered by the California Energy Commission, and shifting its customers to another program administered by the California Public Utilities Commission — either a current program that has been far less successful to date or one that has yet to be created.
For the past two years, environmental and clean energy groups have been fighting to protect DSGS from a series of funding cuts ordered by the Newsom administration, and have so far been unsuccessful. “California has already invested years of effort and hundreds of millions of dollars to build out DSGS. It’s a model now for clean reliability,” said Laura Deehan, state director of Environment California, one of the dozens of environmental advocacy groups that have signed a letter protesting the plan. “We have to make sure we keep the lights on on the program and not abandon what’s already been built up.”
A coalition of industry groups that have enrolled customers in DSGS echoed that view in a March letter to state lawmakers. It warned that “dissolving an existing successful program and attempting to re-create the same type of program at a different agency causes delays, wastes public resources, and has no assurances that it will be as successful.”
Environmental and industry groups are throwing their weight behind the Newsom administration’s other budget proposal, which would instead increase DSGS funding. This alternative calls for shifting money from another, underfunded distributed energy program to DSGS, bringing its funding for the coming year to roughly $53 million, up from the $26.5 million now remaining in its budget.
This is still short of the $75 million that backers have been asking for, said Caleb Weis, clean energy campaign associate at Environment California. But it should be enough to ensure enrolled customers are ready to help the grid through what’s expected to be a much hotter summer and fall season than the state has seen over the past two years, he said.
“The DSGS program kicks on when the primary alternative would be importing expensive energy from out of state or firing up expensive peaker plants that are dirty and cost money just sitting there, not being used,” he added. Meanwhile, DSGS “has clean assets that are ready to protect the California system during times of extreme stress and high cost. It’s almost a no-brainer to use this.”
Supporters of the proposal to end DSGS have been less vocal. While the state has underscored that DSGS was always meant to be temporary, few other justifications have been offered for ending the program before its original 2030 sunset date — and no major stakeholders have come out in support of that plan.
The conversation around DSGS is heating up ahead of key budget decisions. California must pass its 2026–2027 budget by June 15, and that budget must be finalized before Aug. 31. Sometime between now and that deadline, state lawmakers will be forced to decide on the future of the program.
Lawmakers raised concerns about the proposal to scrap DSGS during a March 5 hearing of the Senate Budget Subcommittee on Resources, Environmental Protection, and Energy at the state capitol.
“DSGS has largely been a successful program,” said Sen. Eloise Gómez Reyes, a Democrat who chairs the subcommittee. “Why is the administration proposing to start over?”
David Evans, a staff finance budget analyst at the state’s Department of Finance, responded that the “original vision and intent of the program was not allowed for it to be an indefinite, ongoing program.” He highlighted the state’s ongoing budget shortfall, which the Newsom administration had cited as the rationale for cutting DSGS funding in 2024 and 2025.
But Gómez Reyes pushed back on that justification, noting that the administration’s alternative proposal — shifting funds from elsewhere — could allow DSGS to successfully operate this year without impacting the budget.
“If something is successful, and it appears that this is a successful program, why don’t we continue … even if we intended it to be something that was temporary?” she said.
Gómez Reyes also questioned the wisdom of shifting DSGS participants to the California Public Utilities Commission, given the agency’s comparative lack of success in managing VPP programs.
Under the CPUC’s oversight, California’s biggest utilities have largely failed to follow through on the state’s decade-old policy imperative to incorporate rooftop solar systems, backup batteries, smart thermostats, and other distributed energy resources into how they manage their grids. California remains well short of current targets on that front.
DSGS has been the most successful of a set of programs created in response to California’s grid emergencies in the years 2020 through 2022 designed to utilize individual customers’ devices to help the grid. Unlike those other programs, which are overseen by the CPUC and administered individually by the state’s three biggest utilities, DSGS is credited for its ease of enrollment, clear rules for participants, and availability to all state residents.
In particular, DSGS has been able to scale up and deliver grid relief much better than the Emergency Load Reduction Program, which the CPUC established in 2021.
Both programs enlist customers with batteries, EV chargers, smart thermostats, and other devices. But according to data provided by legislative staff for the March 5 hearing, while DSGS ended 2025 with an estimated 1,145 megawatts of peak load reduction enrolled — “enough to power the peak electricity demand for all of San Francisco” — ELRP has enrolled only about 190 megawatts. Its residential program was discontinued last year “due to very low cost-effectiveness.”
A recent test of both programs underscored once again the difference in scale. In July 2025, utilities measured how much solar-charged battery power capacity each program provided over the course of two consecutive hours.
The test delivered a total of 539 megawatts of capacity over that time. According to the Brattle Group’s analysis, roughly 476 megawatts of that capacity was provided by about 100,000 participants in the DSGS program — while only 64 megawatts came from ELRP participants.
Utility Pacific Gas & Electric lauded the test, noting that it “showed that home batteries can be counted on during peak demand.”
Sen. Catherine Blakespear, a Democrat, brought up the relatively poor performance of ELRP during the March 5 hearing. “It does seem like there are members of the legislature and stakeholders who really have a lot of confidence in DSGS and want it to continue, and that there’s a concern that ELRP is just not as effective,” she said. “We should focus back on the thing that’s already working and that might have a better chance of being successful.”
CPUC Executive Director Leuwam Tesfai noted at the hearing that ELRP isn’t the only alternative on the table. The budget proposal that would eliminate DSGS would also allow enrolled customers to join a new program administered by the CPUC. The agency has yet to create this new program but is actively exploring it as part of an ongoing proceeding scheduled to wrap up by the end of 2026, she said.
But Gómez Reyes replied that any work the CPUC might or might not undertake to create an alternative program to the ELRP wouldn’t be finished until “after we have completed this budget. And that becomes a problem for us as we make our decisions.”
It’s unclear how quickly state lawmakers and the Newsom administration will move to resolve these conflicts.
“It’s not out of the question that it goes through the end of August,” said Katelyn Roedner Sutter, California senior director at the Environmental Defense Fund, an environmental group that supports DSGS. “I hope it goes faster, because by the end of August is when we need to be drawing on some of these resources.”
Roedner Sutter also highlighted that the DSGS program is funded through taxpayer dollars. Most CPUC-administered programs, by contrast, are financed by authorizing utilities to pass on the costs of operating them to their customers.
“At a time when we’re trying to find ways to pay for these things outside of electricity bills, it makes less sense to move things over to the CPUC,” she said.
Sen. Josh Becker, a Democrat who authored a VPP bill that was vetoed by Newsom last year, told Canary Media that he would “strongly urge the administration to reconsider” ending the DSGS program and shifting its participants to a CPUC program. “[For] those in the legislature that have been focusing on this and care about this, it’s not a move any of us think is in the right direction.”
Becker highlighted that dozens of states are pursuing VPPs to make “better use of the clean energy resources that people already have in their homes to lower cost, to improve reliability, and to reduce pollution.” He has introduced another VPP bill in this legislative session that he said would instruct the CPUC to modify “rules that prevent these resources from participating fully in the market.”
Leah Rubin Shen, managing director at the trade group Advanced Energy United, said its member companies involved in DSGS support eventually shifting to a new program that might emerge from the kind of efforts that Becker and other lawmakers are proposing. But “you’ve got to make sure that everyone knows what the rules are, and that the rules aren’t going to change,” she said.
“DSGS has been a great program,” she said. “Keep it humming along for a few more years, until it’s supposed to be put to bed. And in the meantime, set up this market integration pathway that can funnel what we’ve learned from DSGS into something bigger and better.”
The Cow Palace arena, just south of San Francisco, has hosted Dwight Eisenhower, the Beatles, the San Jose Sharks NHL team, and an annual rodeo since it opened in 1941. But an even bigger act is setting up next door: an enormous battery that will perform a starring role in the Bay Area’s energy ecosystem.
Developer Arevon has begun construction of the Cormorant Energy Storage Project, which will occupy an 11-acre vacant lot just southwest of the Cow Palace in Daly City. The battery facility will be large by industry standards, with 250 megawatts of Tesla Megapack containers, capable of discharging for four hours straight, for 1 gigawatt-hour of total stored energy. Bigger batteries have been built, but when Cormorant comes online in about a year, it will be poised to be the country’s largest battery nestled within a major urban area.
Arevon has contracted the battery for 15 years of use by MCE, one of California’s biggest community choice aggregators — entities that purchase electricity on behalf of local residents as an alternative to Wall Street–owned for-profit utilities. The state requires MCE to buy grid capacity commensurate with its members’ usage, and the Cormorant project will fulfill 10% of this annual requirement, known as resource adequacy in California bureaucratese.
MCE has become a major force in the greater Bay Area: It now serves all of Marin and Napa counties, most of Contra Costa, and half of Solano. The aggregator can contract for power plants across California, but it looks for sites within or near its service territory when possible, said Jenna Tenney, MCE’s director of communications and community engagement.
“Having a storage project in a community is going to add to resiliency in that community,” she said. The battery will bring $73 million of property tax revenue to Daly City, she added, and Arevon will donate $1.5 million in community benefits.
Cities need power, but generating it within urban cores is a difficult feat. California effectively stopped building gas-fired power plants, but even if that were an option, sticking a smokestack in San Francisco wouldn’t fly. These days, California expands generation by building large-scale solar plants in wide-open spaces, but those plants need to ship their power over many miles of transmission lines to reach the cities where it gets consumed.
The Cormorant battery provides something new: a dense source of on-demand power that can slip into the urban fabric without any local air pollution, and which absorbs the far-off solar generation at midday to discharge later at night. Arevon CEO Justin Johnson estimated that the battery, fitting on the site of a former drive-in movie theater, could cover the electricity needs of some 321,000 homes for four hours straight.
“It couldn’t keep the whole city going, but it certainly, without a doubt, increases the reliability of the grid in that area in a substantial way,” he said.
Arevon didn’t jump to the highest echelon of energy storage development from nothing. The firm has invested $11 billion in projects and owns 6 gigawatts of solar and battery installations operating across 18 states.
The company launched in 2021 as a spinout of Capital Dynamics, a private equity fund that amassed an early portfolio of energy storage assets. Arevon is owned by the California State Teachers’ Retirement Fund, Dutch pension fund APG, and the Abu Dhabi Investment Authority. Those firms invest for steady, long-term growth, and their patience lends itself to Arevon building and owning batteries for the long haul, instead of building to flip to other buyers.
“When we’re in there developing assets in the community, we can tell them, hey, we’re going to be here a long time,” said Johnson, who stepped up from COO to CEO in March. “You’re incentivized to engineer it well, construct it well, operate it well.”
Arevon focused on the Daly City location because electricity price volatility tends to be highest in proximity to major consumption, Johnson said. Places like that — whether metro areas or large industrial hubs — see the greatest swings from peak to off-peak hours, and having battery facilities to arbitrage between those times should push prices down in the long run. But building within a city comes with obvious trade-offs.
“Siting any infrastructure, whether you’re putting in a Walmart or upgrading an intersection or doing anything in a high-density area, is tough … especially so for power plants or facilities like this,” he noted.
Tough but not impossible, as Arevon proved in San Diego’s Barrio Logan community with its Peregrine project (another entry in a portfolio of projects sporting avian nomenclature), which came online last year. There, the company squeezed 200 megawatts of batteries between a naval shipyard and a light-rail track, in the shadow of the Coronado Bridge. In Daly City, Arevon will need to carve through roughly a mile of streets to run high-voltage cable underground to the nearest substation.
Such projects “reduce your lifespan a little bit” from the stress, Johnson said, but once built, the intrinsic difficulty becomes a sort of strategic moat. If a competitor wanted to open up next door to Cow Palace, well, they probably couldn’t find a viable space.
“Those are assets I’m really proud to own, and I think they’ll become just more and more valuable over time, because they’re hard to replace,” Johnson said.
To achieve that longevity, the batteries need to survive, and that premise is not to be taken for granted, given their location 90 miles north of Moss Landing, where the largest battery fire combusted a little over a year ago. Safety concerns are understandably higher in dense urban areas, so assuring the community that a Moss Landing–style disaster won’t happen here was integral to securing permits.
Arevon’s choice of battery, Tesla’s Megapack 2 XL, addressed the safety question. The containerized storage product is filled with the lithium-ferrous phosphate cells, a battery chemistry known to be significantly less fire-prone than earlier lithium-ion varieties. The older Moss Landing facility packed a huge amount of batteries into a single legacy structure, where they became fuel for an immense conflagration. The Megapack containers, in contrast, will be spread out across the site in a design that will prevent a fire from spreading beyond a single metal box. If one unit ever did catch fire, it would damage only a fraction of 1 percent of the plant’s capacity.
Workers are grading the site and installing “geo piers,” columns of aggregate that extend about 30 feet underground to stabilize the site during earthquakes. This is not an idle threat — the Bay Area just experienced a 4.6 magnitude tremor in the wee hours of Thursday morning. After that work is complete, the 280 Megapacks will take their places so that Cormorant can make its debut.
AI infrastructure startup Crusoe has always differentiated itself from its competitors by finding creative ways to tap energy. Now, it’s investing in two of the most potentially transformative battery technologies on the market.
Crusoe has signed a deal with Form Energy to purchase 120 megawatts of iron-air batteries, which would store a massive 12 gigawatt-hours of electricity. Form promises that this novel type of battery — the first commercial installation is still under construction — will make renewable energy available for days on end, a crucial breakthrough for cleaning up the grid but also for cleanly powering data center operations. The deal comes just a month after Form won a 30-gigawatt-hour contract to supply a Google data center in Minnesota with round-the-clock clean energy.
Crusoe also said Tuesday it was doubling down on used electric vehicle batteries as a tool for cheaply storing electricity for computing.
Last summer, the company installed four modular data centers on the Nevada campus of battery recycling startup Redwood Materials; the latter built a field of solar panels and wired up an array of EV battery packs to serve round-the-clock clean power to Crusoe. After about nine months of operations, Crusoe decided to add 20 more of its modular Spark data centers to the site, utilizing the existing microgrid for a lot more computing. And Redwood said Wednesday it had passed key safety tests for its used-battery architecture, clearing the way for broader deployment.
The two announcements, emerging from the bustling CERAWeek energy conference in Houston, signal how one of the nation’s leading energy-savvy data center developers is scouting futuristic clean energy tech to speed the AI buildout today.
Crusoe launched in 2018 as a bitcoin miner that leveraged stranded energy resources, like oil-field gas that would have been flared. Its founders designed rugged computing modules that could survive in harsh circumstances, and built up domestic supply chains to give them more certainty on timing and delivery. Later, they flipped that expertise into the emerging AI infrastructure market.
Then, Crusoe shot to an improbable level of prominence for a startup of its size (it closed a $600 million fundraise in late 2024, valuing the company at $2.8 billion). Oracle chose Crusoe in 2025 to build the largest and most famous data center project to date: the Stargate flagship in Abilene, Texas. Stargate is typically described as a $500 billion effort, though that number actually refers to the broader joint venture between AI juggernaut OpenAI, cloud provider Oracle, and Japanese investment firm SoftBank. Crusoe has delivered two buildings in Abilene, which each consume about 100 megawatts to run their GPUs.
Setting aside the lingering questions around how much of the $500 billion investment pledge actually gets spent, it’s clear that Crusoe has leaped to the upper echelon of the AI industry. That means its choices to embrace novel clean energy technologies could turbocharge their pace of deployment and inspire new customers to follow suit.
The Form deal is a confident first bite. The purchase of 12 gigawatt-hours represents more storage capacity than any existing battery plant on the grid. To be clear, the deal does not imply that all that capacity will go to one site (and there’s no indication that iron-air batteries will go to Abilene in particular).
“They have a lot of projects that they’re working on simultaneously,” Form CEO Mateo Jaramillo told Canary Media. “They can choose where these first installations happen.”
The deal reserves iron-air batteries that will be manufactured in Weirton, West Virginia, and sets terms for the eventual purchase, Jaramillo said. Form is expanding its production capacity from 15 megawatts to 50 megawatts in a few months and will start initial deliveries of Crusoe’s 120 megawatts in 2027. At this point, Form has sold out its production through 2028 and is focused on executing the factory expansion, Jaramillo said.
Form chose iron as its key battery ingredient because it’s so cheap, which makes it economically viable to store and release clean energy over much longer time horizons than the four or five hours that today’s lithium-ion batteries are designed for. This means that a data center could rely on cheap wind and solar power, but call on Form’s tech to ensure on-demand electricity through multiday bouts of bad weather.
That serves Crusoe’s goal of bringing its own capacity as it builds data centers. Doing so avoids having to wait around for lengthy grid upgrades, and portends better community relations than having data centers compete with everyone else for existing power supplies.
Like Form, Redwood is working to deliver batteries with many more hours of storage, and at a radically lower price, than today’s lithium-ion batteries. Redwood does this not through breakthroughs in electrochemistry but by repurposing battery packs that would otherwise be dismantled.
Redwood’s original system looked like the product of creative tinkering — a field full of oddly shaped packs propped up on cinder blocks, quite unlike the uniform metal containers at most grid battery plants. Since then, it has formalized the architecture. Metal racks have replaced the cinder blocks, for instance, and the packs are mounted vertically so that more fit in a given space.
For performance, the company noted that its solar-battery microgrid has operated 99.2% of the time since installation. That’s commendable for a microgrid powered only by solar panels, but not up to the usual standards for AI computing. A spokesperson for Crusoe noted the data centers at Redwood’s campus tapped grid power as backup to maintain 99.9% uptime.
For the business to grow, Redwood founder JB Straubel (formerly CTO at Tesla, where Jaramillo once helmed the energy storage business) also needed to prove that the system wouldn’t catch fire. Just this month, Redwood cleared a barrage of safety tests by UL Solutions, the renowned independent safety lab. The repurposed batteries prevented the spread of fire from pack to pack, said Andrew Hoover, who leads product safety and compliance for Redwood. The Redwood team also ran a high-octane “deflagration” test by injecting explosive gases into a pack and igniting them. In this “absolute worst-case” scenario, Hoover noted, “the pack safely vented those gases out.”
Redwood’s battery installations buck the industry convention of stuffing batteries in a big metal container. But that decision makes the systems “inherently safe without relying on all these complex mitigation systems,” Hoover said. There’s no big box for explosive gas to build up in, and the packs are spread out enough to isolate any fire that might start.
With this safety credential to assuage potential customer concerns, Redwood is in a position to ship beyond its own campus in Nevada. Crusoe has plenty of other data center developments in need of power, and its latest storage deals expand its energy arsenal.
Big batteries have begun reshaping the U.S. grid. Now, the country has made surprising strides in making those energy storage systems itself, rather than depending on imports from China.
Batteries were always crucial for the effort to scale up renewable energy production, but they have taken on even more significance as AI leaders look for quick-to-build power sources to supply their headlong data center expansion.
That’s why batteries will account for some 28% of new U.S. power plant capacity built this year. For the first time, the country will be able to produce enough grid batteries to meet that surging demand on its own, according to new data from the U.S. Energy Storage Coalition, an industry group.
The onshoring began in earnest when President Joe Biden signed the Inflation Reduction Act in 2022, creating incentives both for domestic battery producers and for storage developers who use Made-in-America products.
Already, the U.S. has enough capacity to meet demand for finished grid battery enclosures. That involves connecting battery cells to power electronics, controls, and safety equipment in weatherproof steel containers that are ready to install. By the end of this year, the U.S. will also achieve self-sufficiency in a higher-value part of the supply chain: the battery cells themselves. It’s a major industrial coup that is bringing thousands of high-tech manufacturing jobs to communities across the country.
“For the first time, the United States now has the capacity to supply 100% of domestic energy storage project demand with American-built systems,” said Noah Roberts, executive director of the U.S. Energy Storage Coalition, on a Wednesday press call. “That is a fundamental shift from where we were just a year and a half ago, when the majority of battery storage systems were imported.”
This success outstrips the country’s considerable progress in solar panel manufacturing, too. The U.S. is self-sufficient in assembling solar modules, but that finished product still often depends on high-value components imported from far away — namely, solar cells. U.S. solar cell production remains a tiny fraction of its solar panel capacity.
By the end of 2025, U.S. factories had mustered the capacity to produce about 70 gigawatt-hours of finished grid storage systems each year, according to the coalition’s survey. Roberts expects that number to rise to 145 gigawatt-hours by year’s end. U.S. storage developers are likely to install about 60 gigawatt-hours annually this year and next, he noted, so the country will actually have a sizable surplus in manufacturing capacity.
As for the underlying cells, it’s a similar story with a slight delay. By the end of 2025, 20 gigawatt-hours of dedicated storage cell lines had opened, and the industry is on pace to hit 96 gigawatt-hours by the end of this year.
Now, the question the industry faces is not whether it can keep up with domestic demand — but whether it can export enough batteries to maintain that mismatch between manufacturing potential and domestic installations.
The development of U.S. grid-battery manufacturing has happened at a dizzying pace. Roberts called it “one of the fastest industrial scale-ups in recent American history.”
At the close of 2024, the U.S. had “effectively zero” factory capacity for battery cells designed for grid usage, which have different specifications than those in electric vehicles and which typically use the lithium iron phosphate chemistry.
LG Energy Solution Vertech, the grid-storage subsidiary of the Korean industrial giant, started turning things around last summer when it completed a dedicated cell production line for grid storage in Holland, Michigan. The company originally envisioned 4 gigawatt-hours of production, but quickly expanded that to 16.5 gigawatt-hours, said Chief Product Officer Tristan Doherty. Now LG plans to hit 50 gigawatt-hours of cell production capacity across North America this year.
“If you had told me that 10 years ago, that this is where we would be, I never would have believed it,” Doherty said.
The upstream supply chain, it must be said, still needs work. U.S. factories can only build the lithium-ion battery cells by importing the high-value battery materials, and China runs the show in that arena.
It’s also worth noting that this scale-up was accelerated by an unintentional nudge from the Trump administration, a sort of collateral benefit.
When the Trump administration passed its budget legislation last summer, it maintained Biden-era incentives for domestic energy manufacturing and grid battery projects even as it removed them for electric vehicle purchases.
The outlook for EV sales in America suffered as a result, and that prompted some manufacturers to repurpose their EV-battery facilities for the red-hot grid storage market. In just the last year, car companies like Ford and General Motors have retreated from their earlier EV ambitions and pivoted their battery lines to storage.
Just last week, LG said it and partner GM would retool an EV battery plant in Spring Hill, Tennessee, to make grid batteries instead; this will bring 700 people back to work after earlier layoffs. LG is also converting a plant in Lansing, Michigan, to make grid batteries instead of EV batteries, and will sell them to Tesla as part of a $4.3 billion supply deal.
It’s a stark reversal. In earlier years, grid battery developers had accepted surplus EV batteries as a sort of hand-me-down from the more mature supply chain; now, struggling EV battery producers are turning to grid storage in their moment of need.
Other companies have made their own direct investments in grid storage in recent years, including Tesla, Samsung SDI, Fluence, and SK On.
Even as the White House fights clean energy broadly, it’s showing interest in strengthening battery supply chains to reduce the upstream dependence on China. Just this month, the Department of Energy rolled out $500 million in funding for processing or recycling battery materials domestically.
The localization of grid storage supplies does more than stroke the national ego. As data center customers ravenously seek immense power supply as quickly as possible, domestic supply chains shorten the time it takes to add storage to the grid, argued Pete Williams, chief supply chain and product officer for Fluence, a major grid storage vendor.
“To deliver this ‘speed to power’ you need a resilient and a responsive supply chain, and that’s been certainly a challenge in the international markets,” he said. “With U.S. manufacturing, we can improve delivery certainty. We can also shorten project timelines for our customers.”
In the past, analysts framed industrial reshoring as a way to protect against the vagaries of geopolitical adversaries. These days, with the White House itself regularly upending global trade through tariff declarations and military interventions in crucial waterways, a local supply chain protects against U.S.-led disruptions as well.
See more from Canary Media’s “Chart of the Week” column.
California and Texas are far ahead of the pack when it comes to grid batteries. But another state is seeing storage expand quickly as it looks to store more of its abundant, cheap solar power for later.
Arizona saw blistering growth in utility-scale battery capacity last year, more than doubling its fleet to a total of 4.7 gigawatts at the end of 2025, according to U.S. Energy Information Administration data analyzed by research firm Cleanview.
The two leading states each installed far more capacity last year than Arizona did, but neither of these more mature markets grew as quickly. California expanded its fleet by 29%, to 15.2 GW, while Texas’ grew by 69%, pushing it to just over 14 GW of total installed capacity.
Batteries continue to fall in price and are among the fastest ways to add capacity to the grid. At a time when demand for electricity is skyrocketing, threatening to push already elevated utility bills even higher, cost and speed are critical factors. The Republican budget bill passed last summer notably let batteries hang on to their generous tax incentives while sunsetting the same credits for solar and wind.
Still, the technology is relatively new to the grid — even if it’s just a supersize version of the batteries in your phone and computer. Less than a decade ago, hardly any batteries were plugged into the grid, but a combination of those falling costs, surging solar, clean energy targets, and tweaks to energy market designs have opened the floodgates in certain regions.
It makes sense that Arizona is now third on the battery leaderboard.
For one, it has lots of solar power. It’s fourth in the nation in utility-scale solar, after Texas, California, and Florida. Energy storage is most potent when used to soak up dirt-cheap, excess solar — something states like Arizona have in spades, especially on afternoons when power demand is low but the sun is shining.
Meanwhile, Arizona is staring down a bigger increase in electricity demand than “almost anywhere in the country,” writes Cleanview founder Michael Thomas. Arizona is not only a hot spot for the data center boom but also the site of a massive, energy-hungry chip-manufacturing hub being built by the Taiwan Semiconductor Manufacturing Co.
Put simply, Arizona needs to build a lot more energy capacity, fast — and batteries are a cheap and easy way to do it.
The surge of new data center development is making people worried.
How much energy and water will these resource-hungry centers consume?
Will they drive new fossil fuel pollution?
How much will household electricity prices go up?
These questions have answers, but in many cases, the details of new data centers are blocked from public view.
Take this example from Montana. Quantica Infrastructure is planning to build a 5,000-acre energy and technology hub near Billings, Montana, which would use more electricity than all of the households in the state combined. The specifics are spelled out in the documents below – but they’re redacted.
Bipartisan opposition to data centers is growing fast, with 20 projects blocked or delayed nationwide in just a three-month period during spring 2025, according to the research group Data Center Watch.
But secret agreements make it nearly impossible for residents and elected officials to understand the impacts of data center development in their communities – or whether their electricity bills will soon be subsidizing Big Tech.
In Montana, advocacy groups are challenging NorthWestern Energy’s plans to serve data centers. (I’ve been involved as well: I serve on the steering committee of a fledgling nonprofit called Montanans for Affordable Energy.)
State Rep. Kelly Kortum, a Democrat from Bozeman, said he is wary of the proliferation of data center proposals in Montana, and he’s ready to push back.
“I’m looking to make sure the people don’t get screwed over,” he said. Kortum is a computer scientist who works in IT.
“I personally really need to know how much energy is being used and how much of that is public electricity,” he added. “And what’s that going to do to our rates?”
As data center developers scope out plans for new projects, they first need to make sure they can get enough electricity to feed the data center. Often, they turn to the local utility and make basic arrangements to purchase electricity.
The agreement reached between the data center developer and the utility is spelled out in a letter of intent. It includes how much energy will be delivered, the prices, the time frame for when the new electric service will start, and how the utility will ensure that it delivers sufficient electricity to keep the data center churning along.
NorthWestern Energy in Montana has signed letters of intent with developers of three proposed data centers. These three agreements alone would more than double the average amount of electricity used by NorthWestern’s customers. The electricity would be generated by burning coal at Montana’s Colstrip power plant, one of the most polluting power plants in the U.S.
Ari Peskoe is the director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program and an author of “Extracting Profits from the Public: How Utility Ratepayers Are Paying for Big Tech’s Power.” The report lays out tactics that data centers are using to off-load their costs onto households, such as making secret deals with utilities.
“I mean, look, these are monopolies,” Peskoe said. “They ought to be held to a standard about transparency. That requires they provide meaningful information about major deals that they’re a part of.”
NorthWestern Energy, like many utilities in the U.S., is a regulated monopoly. That means that the company can operate without competition, but it’s overseen by a governmental body. In theory, public utility commissions serve as a backstop against price gouging and other unfair practices.
“The whole point of utility regulation is to really dive into the accounting records, the details, and make sure that the public is protected from their monopoly power,” Peskoe explained.
But in this instance, Montana’s Public Service Commission sided with NorthWestern Energy. The commission decided that “proprietary Letters of Intent information derives independent economic value or competitive advantage from its secrecy.”
Peskoe disagrees.
“They’re claiming that this is a private business deal, but it’s kind of not when you’re a regulated monopoly,” he said. “They ought to have a higher standard for the information they disclose to the public than other private companies.”
“’Trust us’ doesn’t really cut it when you’re a monopoly provider,” he added.
A Montana bill that sought to address some of these issues (HJ-46) failed in the last legislative session, but Kortum, the representative from Bozeman, said that lawmakers will try again.
“Repeating the same bill builds knowledge with the legislators,” he said, noting that data centers are a new topic and many lawmakers are unfamiliar with the issues and possible solutions.
Kortum said when legislators don’t have a firm position one way or another, public input can hold more sway. For some lawmakers, “They have no dog in this race,” Kortum said. “I am expecting them to fall back on what the public wants,” he said.
For the Quantica Infrastructure project, the company already purchased 5,000 acres of land in a county with no zoning and limited local oversight. The project is scheduled to begin construction this year.
NorthWestern Energy said it plans to release a set of proposed terms and conditions for new data centers. These arrangements are called large load tariffs, and in theory, they can contain safeguards that help protect household energy users from shouldering the burden of new infrastructure. For example, the tariff could specify a minimum demand, so that if a data center uses less electricity than originally planned, it would still have to pay for the costs of all of the infrastructure built to bring electricity to the site.
NorthWestern Energy said it planned to file its large load tariff with Montana’s Public Service Commission by the end of 2025, but to date has not released a public plan.
In a recent NorthWestern Energy earnings call, the company appeared to walk back its earlier statement.
“We had said we will file a large load tariff, but I would note that that was tied to signing an ESA,” said Crystal Lail, NorthWestern Energy’s vice president and chief financial officer.
An ESA is an electric service agreement that spells out the specifics of the service between the utility and the data center. By the time a utility and a developer have an electric service agreement, it means the project is less of a proposal and more of a sure bet. In other words, the utility won’t share more details until the project is closer to reality, which also means it could be harder for communities to intervene.
What’s more, electric service agreements are also sometimes hidden from the public. For example, here’s an excerpt from the electric service agreement between Leola Data Center and Montana-Dakota Utilities in North Dakota.
NorthWestern’s Lail said the company wants to “get ahead of this argument that data centers aren’t paying their fair share.”
NorthWestern Energy CEO Brian Bird said the company expects to release its new large load tariff by the middle of 2026, six months later than originally promised.
An upheaval is underway in the nation’s electricity sector, and Virginia is ground zero. As the data center capital of the world, the state faces surging demand, ballooning utility bills, and a bottlenecked grid — all challenges that policymakers are navigating while maintaining a legally mandated course toward carbon neutrality.
Now, the state is poised to become the first in the nation to quantify and examine ways to reduce waste on the electric grid — a potentially monumental move toward reining in rates and speeding the clean energy transition. Maximizing usage of our existing network of power lines and related infrastructure, backers say, could also help close the gap between the public interest and that of investor-owned utilities.
House Bill 434 would direct Appalachian Power Co. and Dominion Energy, the state’s two predominant vertically integrated utilities, to gather and report detailed data on their grid utilization. The measure won final approval from Virginia’s Democratic-controlled legislature this week and now heads to the desk of Gov. Abigail Spanberger — a Democrat whose victory in November was fueled in part by anxiety over rising electricity costs. As one of the earliest proposals Spanberger offered after her election to address energy affordability, the bill looks certain to become law.
Many experts say the information the measure would require is itself meaningful: Utilities have long resisted gathering and reporting such metrics, in part because doing so could hurt their case to build out more infrastructure that pads their bottom lines.
But advocates for HB 434 say its real impact could come after the utilization data has been reviewed by regulators, who must then establish a timeline for utilities to optimize grid usage. The bill directs officials to give special consideration to “non-wires alternatives” like batteries and line sensors.
“The fact that Virginia became the first state to introduce this sort of legislation is pretty significant,” said Charles Hua, the founder and executive director of PowerLines, a nonprofit that aims to lower utility bills and supports HB 434. “But this would just be the first step of a long journey.”
The legislation is premised on an incredible reality: Roughly half the electric grid goes unused about 99% of the time. Poles, wires, substations, and other components are built out to deliver electrons during periods of maximum demand, such as during the recent cold snap brought on by Winter Storm Fern. But those peak events are rare.
“This is where this conversation has been stuck for 20 years,” said Pier LaFarge, the co-founder and CEO of Sparkfund, which helps utilities deploy and manage distributed energy sources. “We’ve built the grid to peak … then said, ‘How much space is left?’ But what’s amazing is, the grid only is at peak 50 to 200 hours a year out of 8,760.”
Another factor is that some kilowatt-hours are lost as they travel from the point of generation to the customer, especially along lower-voltage AC distribution lines.
“Local poles and wires, that is, the distribution grid, is really not that efficient,” Hua said. “But you never would really know, because there’s not a ton of transparency around spending.”
HB 434 would prompt Appalachian Power and Dominion to examine and quantify these utilization gaps and inefficiencies as part of a regulatory proceeding this fall. The state’s utilities commission would then review and approve that data and direct the companies to increase grid utilization.
The measure requires regulators to evaluate key technologies — from energy storage to synchronous condensers, which reduce line loss — to improve use of the grid. It also opens the door for regulators to weigh grid utilization when considering utility proposals to instead expand their infrastructure.
In theory, these steps should lead to lower rates for customers. “Electricity rates are a math equation,” Hua said, where the top of the fraction is the cost of grid infrastructure, among other investments, and the bottom half is the number of kilowatt-hours sold.
Increasing grid utilization divides the fixed cost of the poles and wires — roughly the same numerator — by more electrons, a much higher denominator. “Therefore, you’re lowering the per-unit price of electricity,” Hua said, “and you’re lowering utility bills for all consumers.”
Exactly how significant this “denominator effect” will be isn’t clear yet – not without the data HB 434 requires utilities to compile. But experts say that growing the bottom of the fraction is a win for both customers and the investor-owned utilities, which make more money the more kilowatt-hours they sell.
Grid optimization also gives these utilities a pathway to making capital investments that earn them a guaranteed profit more quickly than building new power plants. That pathway runs through grid-scale batteries, according to LaFarge.
“Batteries have enormous value to the grid because they’re electron time machines. You can charge them up when there’s plenty of energy on the grid and no congestion or scarcity,” LaFarge said, and then discharge them when demand is at its height. “It creates more room on the grid using the grid you have. That unique nature of batteries is their superpower.”
While storage technology has been around for a decade, until very recently it was more expensive than building poles and wires and harder to justify to regulators.
“What has changed in the last 18 to 24 months is batteries have gotten staggeringly cheap,” LaFarge said, and utilities can invest in them and improve their bottom lines. “This is one of our most important messages around utilization: Utilities can earn more on capital assets [and] have higher revenue while delivering cheaper power to people.”
LaFarge’s company has worked with Dominion on other forms of distributed generation, including EV charging. For batteries, he said, “the Virginia utilization bill certainly creates an even bigger opportunity.”
To be sure, increased grid utilization is far from the only step Virginia lawmakers can take to tamp down skyrocketing electricity costs. Tying rates to performance metrics such as affordability and efficiency, increasing targets for batteries and other cheap sources of clean energy, and enabling more large-scale solar projects are among a host of legislative proposals that would also help lower prices — and that all could also become law this year.
It’s also true that the one-page HB 434 is more suggestion than mandate, and its speedy passage through the Virginia General Assembly — including by a nearly unanimous vote in the House of Delegates — raises questions about its impact. And the onus will be on the state’s utilities to measure, report, and improve grid utilization, albeit with prodding from regulators.
Still, Jigar Shah, a longtime energy entrepreneur and the director of the U.S. Department of Energy Loan Programs Office under former President Joe Biden, believes the legislation will put utilities on the hook, even as it gives them leeway to collect and analyze utilization data.
“What’s not acceptable is for folks to say, ‘It’s not possible and rates are going up 9% a year,” said Shah, who helped shape and advocate for the bill as an adviser to the nonprofit Deploy Action. He also pointed out Spanberger’s support and regulators’ engagement in the bill.
“It’s not something that we expect to be buried in a [utility] filing and it goes to die,” he said. “I think there’s actual interest in it from folks on the commission to continue moving it.”
For LaFarge, the broad consensus around the legislation is a reason for optimism, not skepticism.
“This is a bipartisan idea that really is having its moment, and we’re excited to see the successes of this bill replicated in dozens of states,” LaFarge said. “I think the regulated utility compact is about to surprise people with its ability to solve these problems to the benefit of the climate, the economy, and people who use energy in their daily lives.”
Disclosure: Charles Hua is a member of Canary Media’s board of directors. The board has no influence over Canary Media’s reporting.
Electricity consumption growth rates are increasing across the United States, driven, in part, by a boom in hyperscale data center development. Although the long-term market outlook remains uncertain, the Lawrence Berkeley National Laboratory predicts that data center demand will grow from 176 terawatt hours (TWh) in 2023 (or, about 4.4% of total U.S. electricity consumption) to between 325-580 TWh (6.7-12.0%) by 2028.1 In some parts of the country, AI-driven energy demand is outpacing available capacity, driving companies to delay projects, contract power directly from private producers, and/or install multiple, inefficient reciprocating generators using natural gas.
Data centers may impact grid reliability in some regions. In July 2024, a voltage fluctuation in northern Virginia triggered the simultaneous disconnection of 60 data centers, prompting a 1,500-megawatt (MW) power surplus, which forced emergency adjustments to prevent cascading outages.2 Investors claim that massive investments in energy generation and grid infrastructure are needed to power data center development while mitigating outage risks. However, if the anticipated demand does not materialize, utilities (and their consumers) could face stranded costs.3
Data centers have enjoyed discounted energy tariffs and tax incentives, as state and local governments compete to attract business. Although these early incentives have driven substantial data center investments, emerging regulatory debates are impacting market development across the country. Policy shifts in major data center markets, such as the passage of Texas Senate Bill 6, signal the probability of future market intervention by both regulators and policy makers to address local-level concerns over reliability and affordability.
As data center infrastructure continues to expand, developing effective regulatory policies becomes critical. The future of data centers and their energy needs, as well as the policy decisions made in this realm, will impact U.S. technological competitiveness for decades to come. While overregulation could hinder AI development, insufficient regulation risks grid instability, rising consumer costs, reliance on high-emission energy sources, public backlash, and setbacks to state and corporate climate goals.
This policy brief outlines the current state (and potential consequences) of U.S. data center electricity usage and corresponding grid expansion. The paper provides an overview of the current data center and grid landscape followed by a discussion of potential engineering and policy approaches to address ensuing challenges. The foundations laid herein will inform our future research under the Project on Grid Integration at the Harvard Kennedy School (HKS) and the Harvard School of Engineering and Applied Sciences (SEAS). This Initiative aims to advance 1) the development of new regulatory tools to incentivize increased grid flexibility and 2) the creation of more equitable cost-sharing mechanisms in the wake of expanding data center development. The brief concludes by outlining several critical questions which will guide the Project’s research over the next year.
According to the National Telecommunications and Information Administration (NTIA), there were over 5,000 data centers in the United States in 2024, with demand for data center services expected to grow through 2030.4 Accordingly, capital spending on hyperscale data center infrastructure has risen to unprecedented levels over the past five years. Amazon CEO Andy Jassy noted that AWS’s AI-related revenue is already a multibillion-dollar business “growing at a triple-digit, year-over-year percentage.” In 2024, Amazon, Microsoft, Google, and Meta collectively spent over $200 billion on capital expenditures (CapEx), representing a 62% year-over-year increase from 2023. Each firm’s spending reached an all-time high: Amazon’s CapEx was $85.8 billion5 (up 78% year-over-year), Microsoft’s was $44.5 billion6 (up 58%), Google’s was $52.5 billion7 (up 63%), and Meta’s was $39.2 billion8 (up 40%). Looking ahead, Amazon’s total CapEx9 in 2025 is projected to surpass $100 billion, while Microsoft’s and Google’s are each expected to exceed $80 billion. The data center buildout race reflects both strategic and financial drivers, as companies race to secure long-term returns and future competitive advantages. By investing ahead of demand, these companies are ensuring infrastructure is available when customers need it. From the industry’s perspective, failure to build ahead of demand places companies at a competitive disadvantage.
While data center financing stems primarily from parent-company balance sheets, corporate bonds, and public incentives, project finance is occasionally used, with green bonds emerging as a supplementary tool. Financing the electricity infrastructure upgrades needed to power data centers, however, is a much more challenging endeavor, as utilities operate under tight financial and regulatory constraints that complicate the acquisition of the large-scale capital deployment needed to fund expansive upgrades.
As data centers continue to seek rapid power interconnection, alternative financing mechanisms for power procurement—through both utilities and third-party providers—are gaining prominence. For example, firms are increasingly relying on third-party power contracts, which include collateral commitments, long-term power purchase agreements (PPAs),10 availability payments, and upfront capital payments. Additionally, companies are weighing the costs and benefits of co-locating data centers and power generation, despite challenges surrounding siting rules, asset ownership, and regulatory oversight. Overall, this unprecedented capital outlay exposes both firms and utilities to a range of risks, from increased stranded assets to rising financing costs; therefore, the sustainability of the data center build out depends on both resilient financing structures and continued demand realization.
Future data center market expansion, and its consequent energy usage, remains highly uncertain. Past data center energy studies display numerous flaws. In a review of 258 data center energy consumption estimations, Mytton & Ashtine (2022) found systematic defects within study methodologies, particularly with regards to data availability and transparency.11 The opacity of data center operations, site planning, and energy efficiency complicate energy estimations and projections.12 Subsequently, institutional projections of data center electricity demand range from about 200 TWh to over 1,000 TWh by 2030, according to the World Resources Institute. This range complicates medium-to-long term grid planning, as utilities struggle to determine both the true magnitude of the industry’s future energy needs and its relationship to economywide electrification.
The 2024 United States Data Center Energy Usage Report13 attempted to clarify the extent of current and future data center energy consumption. After a period of stagnation from 2014 to 2016, center energy demand grew in 2017 due, in part, to expanded efforts to digitalize data across economic sectors. From 2018 to 2023, data center energy use increased from roughly 76 TWh (comprising 1.9% of the nation’s total annual electricity consumption) to 176 TWh (4.4%); future data center energy usage could range from 325 to 580 TWh by 2028, or 6.7-12.0% of 2028 national electricity consumption. However, this range remains uncertain, due to the continued opacity of data center and utility planning as well as uncertain data center market trajectories.14
Project risks are assumed by external stakeholders, not just data center companies. For example, utilities face stranded-asset risks with regards to generation and transmission buildout; if infrastructure is built to serve projected data center demand and said demand does not materialize, these assets could be underutilized. Furthermore, increased contract-based financing has shifted projects away from guaranteed “rate-base” recoveries, instead favoring special tariffs and PPA contracts, arrangements which lack transparency and may shift power costs onto other consumers.
These threats raise urgent questions about who should shoulder data center buildout costs and whether returns (and cost recovery) to the utility will remain predictable. Who should pay for grid improvements spurred, at least in part, by data center development? Who are the beneficiaries of these improvements? How should costs be allocated across consumers? How can local communities be protected from rising energy costs and natural resource depletion as data centers expand to new markets across the United States? Rigorous policy, economic, and engineering research—in conjunction with increased transparency from data center operators and utilities serving them—is crucial for future grid planning as well as for mitigating unwanted environmental, social, and economic impacts.
As data center markets continue to expand, regional differences in electricity market design and energy needs are shaping regulatory and market reforms. Simultaneously, local-level impacts are introducing additional variables for policy consideration. This section surveys two of the largest U.S. data center markets, Virginia and Texas, to demonstrate how locales facing similar challenges differ in the pace and substance of their responses.15
Virginia is the epicenter of the global data center industry, with over 4,900 MW of operating capacity (and another 1,000 MW under construction) in Northern Virginia alone.16 By some estimates, about 70% of global internet traffic passes through the region daily.17 The area’s dense fiber network, linkages with federal facilities, and systemic incentives enabled its market dominance. First, Northern Virginia was an early node in the U.S. government’s ARPANET18 and still hosts major internet exchange points.19 Second, the state’s low power costs, strong electric reliability, economic incentives, and mild climate reduce data center operation costs, while some Northern Virginia counties provided early permit acceleration for large campuses.
Data center growth in Virginia will add thousands of megawatts of nearly constant demand over the next few years, thereby compressing planning timelines and raising new questions around who should bear the costs of system improvements. Dominion’s20 2024 resource plan projects nearly 27 GW of new generation by 2039, including 21 GW of renewable energy (i.e., solar, wind, and nuclear small modular reactors [SMRs]) and 5.9 GW of gas.21 Simultaneously, Virginia’s energy rates are increasing. In February 2025, Dominion proposed its first base-rate increase since 1992, adding about $8.51 per month in 2026 and $2.00 per month in 2027 for a typical household.22
Furthermore, rapid demand growth has led PJM, Virginia’s regional transmission organization, to review how it both defines firm service and manages reliability obligations. The region’s wholesale design depends on a balance between competitive generation, long-term capacity procurement, and regulated local service. This dynamic is strained by data center expansion, as a single, fast-growing class of customers with unique load profiles present system needs that differ from those around which PJM was built. Data centers use large, steady electricity loads with limited ability to reduce (or ramp down) their power usage; simultaneously, their energy demand can fluctuate according to equipment usage and job complexity. This pattern differs from the more gradual, weather-sensitive load patterns. Overall, Virginia is under pressure to embrace new rates, financing, and reliability tools to allocate risks to the drivers of this new demand: data centers.
As the data center industry continues to expand, the Virginia grid must adapt. Cost allocation rules and policy incentives will evolve as the state considers how to sustain reliability investments while stabilizing rates for other customers. Several policy reforms have been proposed. For example, lawmakers have debated scaling back Virginia’s data center tax exemptions for both performance and sales. However, proposals to repeal these incentives stalled in the budget process. Furthermore, several 2025 bills sought 1) to link eligibility to tax incentives to improved energy efficiency or clean energy performance, 2) to pause new projects in Northern Virginia, and/or 3) to set uniform development standards, but none of these advanced.23,24 A separate bill establishing statewide standards, including land use reviews, reached the governor’s desk but was vetoed.25 That said, local governments are considering enhancing land use and environmental regulations, in order to slow the data center build out process. As of the time of writing, the state tax exemptions remain in place through 2035, signaling Virginia’s intent to support competitive market development, but serious concerns around land use and affordability are looming on the horizon.
Texas, with its lightly regulated, “energy-only” electricity market structure, offers a contrasting example of how U.S. electricity systems are responding to rapid data center development. The state demonstrates how a market that historically favored low-friction interconnection processes is adjusting its regulatory framework in response to unprecedented new load growth.
Over the past several years, Texas data center investments have been attracted by the state’s competitive electricity prices, business-friendly policies (including state sales and use tax exemptions on servers, cooling equipment, backup energy, and other hardware), and rapid interconnection speeds. As a result, the Dallas-Fort Worth area has emerged one of the largest data center markets in the United States and is continuing to witness massive build out. The Electric Reliability Council of Texas (ERCOT)26 projects that peak summer power demand could approach 145 GW by 2031, up from 85 GW in 2024; this represents a significant acceleration relative to the gradual 1-2% annual growth in demand experienced over the past two decades. Over half of this new demand (about 32 GW) is projected to come from data centers (including cryptocurrency miners).27 Unlike past gradual and dispersed growth, the current demand surge is rapid, lumpy, and increasingly clustered around specific localities, leading to increased concerns around demand-supply mismatch, insufficient energy reserve margins, and transmission congestion.28
By mid-2024, state lawmakers grew increasingly alarmed by emerging energy risks, particularly with regards to: (1) fairness in cost recovery, with concerns that data center’s speculative or duplicative29 interconnection requests could shift upgrade costs onto smaller customers; (2) behind-the-meter (BTM) co-location that might pull existing grid-facing generation behind a private fence, reducing available capacity in the system under30 tight conditions; and (3) managing resource adequacy and emergency operations if large loads remained uncurtailed31 during an emergency.
In June 2025, the Texas State Senate enacted Senate Bill 6 (SB6), a package of planning, interconnection, cost-sharing, transparency, and emergency operations reforms aimed at strengthening and protecting the state’s energy grid. The law formalizes ERCOT’s Large Load Interconnection Study (LLIS) process;32 directs the Public Utility Commission of Texas (PUCT) to determine a “reasonable share” of upgrade costs for new large loads;33 and requires improved disclosure to reduce speculative filings.34 Overall, SB6 signals the growing potential for expanded regulation across regional markets in response to increased energy affordability and cost-sharing concerns.
In conclusion, Virginia and Texas face similar energy challenges in the wake of rapid data center development, but their approaches demonstrate different regulatory philosophies. The actions (or lack thereof) taken in these states will serve as models for regulators elsewhere across the country.
Future policy and regulatory solutions for data center energy usage will only work if they are technically feasible, economically sound, and politically acceptable. Data center interconnection is often framed as a choice between grid reliability and economic growth. However, past policies have not been anchored in how large loads behave in the real world. Effective policy solutions must account not only for local-level impacts and cost sharing concerns, but also for computational realities. A modeling-first approach can elucidate policy opportunities by first screening for system reliability, then evaluating system-wide price and congestion effects under certain operational criteria that reflect real flexibility. This exercise will require close collaboration between policymakers, engineers, and business leaders across both the energy grid and corporate sectors.
Ongoing research at the John A. Paulson School of Engineering and Applied Sciences (SEAS) aims to address this gap. By linking security-constrained operations (i.e., reliability screening, congestion and ramping limits) with market outcomes (i.e., price volatility, renewable curtailment risks, and uplift payments), the SEAS team is developing realistic engineering solutions to be integrated into real-world policy tools. This analysis will extend across operational levels, considering everything from hosting capacity to transformer loading to thermal equipment aging. Together, these views link system-wide constraints to local reliability and power-quality considerations to develop standardized, transparent workflows that can align planner decisions, regulatory approvals, and developer obligations on predictable timelines.
Rigorous modeling of data centers’ reliability and economic impacts across transmission and distribution enables evidence-driven policymaking. For example, planners could maintain a public shortlist of locations where the grid can reliably host new large loads, aligning private proposals with places with sufficient grid capacity. A similar structure could apply to transmission and distribution by clarifying non-negotiable conditions (such as contingency margins and equipment limits) and possible trade-offs (such as construction timelines). This transparency would enable faster construction, fairer decisions, and clearer expectations among all stakeholders.
At the same time, AI data center power consumption still lacks a standard electricity load profile. Such a baseline would help grid operators, planners, renewable energy developers, and policymakers compare scenarios, estimate future energy costs, gauge resource adequacy, design demand-side flexibility incentives, and set accurate emissions policies. Job submission scheduling provides opportunities to enhance data center demand-side flexibility. Using a bottom-up, minute-by-minute model informed by real job data (i.e., job-arrival traces, per-job resource demands, GPU power profiles, and standard cluster resource allocation mechanisms), SEAS researchers have demonstrated that queuing dynamics (or, how jobs arrive, wait, and are scheduled under finite resources) shape electricity demand. This detailed modeling provides a more granular understanding of power profile dynamics across multiple time scales, ranging from seconds to hours, thereby clarifying the impact of job dynamics on the energy system. This work will provide the basis for regulatory tools designed to mitigate excess power usage and fluctuations stemming from job-level dynamics.
While the outlook for data centers and their energy needs remains uncertain, future solutions must leverage robust policy instruments to spur technological and/or operational changes. For example, data centers may be able to improve grid reliability by reducing their power usage during peak periods; however, it is unclear which incentives would best encourage these practices. Theoretical solutions must be translated into effective, real-world policy initiatives that consider economic, political, and social realities as well as technological feasibility. Rigorous policy, economic, and engineering research—in conjunction with increased transparency from data center operators and utilities serving them—will facilitate successful reforms.
The Project on Grid Integration (PGI) is well-positioned to address these challenges. A joint project of the Harvard Kennedy School of Government (HKS) and the Harvard John A. Paulson School of Engineering and Applied Sciences (SEAS), the Project aims to develop new policy, technical, and operational tools that leverage the data center boom in order to strengthen and modernize the U.S. electric grid; at the same time, the project works to minimize the economic, social, and environmental repercussions of rapid data center expansion.
Moving forward, the Project will examine the following questions:
The views expressed in this paper are the opinion of the authors and do not reflect the views of PJM Interconnection, L.L.C. or its Board of Managers of which Le Xie is a member.
The U.S. desperately needs to make more room on its electricity grid. But for years, the country has struggled to build new power lines at a reasonable pace, and despite fast-rising electricity demand, there’s no sign of that changing in the near term.
A project taking shape near Boston could help make the case for an alternative to expanding the grid: big, strategically placed batteries.
In fact, energy storage has already helped defer the need for costly, slow-moving transmission upgrades in Australia, Europe, and South America. But it hasn’t yet caught on in the U.S.
The Trimount battery project, four miles north of Boston, could spur grid planners and operators to take another look at this concept of using storage as a transmission asset. At the very least, it will be hard for them to ignore. With 700 megawatts of power capacity and 2.8 gigawatt-hours of stored energy, the battery installation would be one of the largest in the nation, and by far the largest in New England.
The Trimount project is targeted for a key pinch point in the region’s grid. It will be located at a former Exxon Mobil oil-storage facility in the city of Everett and will plug into a major substation that connects Boston to the greater New England grid. Boston is a “load pocket,” a spot on the grid where peak electricity demand sometimes exceeds what transmission lines can supply — whether because of emergencies or more predictable spikes in usage on hot and cold days.
But those moments tend to be relatively short-lived, making batteries a viable tool for weathering imbalances. Batteries can store electricity when it is abundant and then discharge it when the transmission system faces high demand.
“At hours when the grid is overly stressed, the ability to discharge the batteries in the middle of the load pocket alleviates the strain on all the major lines going into the metro area,” said Hans Detweiler, senior director of development for Jupiter Power, the Austin, Texas–based company behind the battery project.
Jupiter Power is seeking approval from Massachusetts’ Energy Facility Siting Board for Trimount and hopes to secure utility contracts later this year, Detweiler said. If everything goes according to plan, the company expects to break ground in 2027 and start operating in late 2028 or early 2029.
That will put Trimount smack-dab in the middle of near-term and long-range planning for the Independent System Operator New England, the entity that manages the region’s transmission grid. And ISO-NE is actively searching for ways to relieve Boston’s peak electricity demands.
To that end, Jupiter Power hired RLC Engineering to conduct a study of how energy storage could help solve challenges identified in ISO-NE’s “Boston 2033 Needs Assessment” report. Specifically, the study looked at options for managing when two major transmission lines go out of commission successively, called an N-1-1 event, which could force utilities to institute widespread power outages.
Trimount’s “pivotal” position in the grid could allow it to keep the grid up and running during such an emergency, RLC’s study said. The other alternative would be upgrading a number of high-voltage transmission lines, many of them buried underground — a costly, disruptive, and time-consuming process in dense urban environments.
RLC’s analysis found that the Trimount battery project could provide an “avoided transmission cost benefit” of about $2.27 billion by avoiding those upgrades — “a much more cost-effective way to solve the reliability issue.”
“There are all these ways that storage can save consumers’ money,” Detweiler said. “One is that storage — at least in certain locations, like our project — can avoid massive transmission upgrades.”
This use of batteries as a sort of shock absorber for the grid has gained more traction outside the U.S.
Take the work of Fluence, a global leader in energy storage solutions, for example. The firm, a joint venture of Siemens and AES Corp., is building what could be the world’s biggest storage-as-a-transmission-asset project in Germany, and it has more than 1.2 gigawatt-hours of projects with transmission-asset components around the world, according to Suzanne Leta, the company’s vice president of policy and advocacy.
If the idea catches on in the U.S., the impact could be significant.
A study from Astrapé Consulting commissioned by the Natural Resources Defense Council found that building 3 gigawatts of energy storage by 2030 could obviate the need for about $700 million in transmission upgrades to serve Illinois as it closes fossil-fueled power plants to meet state climate goals.
And in New York, adding battery storage as a transmission asset could “mitigate grid congestion, reduce renewable curtailment, and defer the uncertain need for new power lines,” according to a study by Quanta Technology on behalf of the New York Battery and Energy Storage.
But right now, it’s hard to make these projects happen in the U.S., Leta said. The reason? ISO-NE and other regional grid operators require such batteries to be exclusively used to aid the transmission grid. The battery owners cannot make money from performing other services.
“You have a transmission revenue stream — that may need first priority. But you need additional revenue streams,” Leta said. “The reason that hasn’t happened is generally because policymakers have not allowed for those combined revenue streams.”
That’s the case for the Trimount project, which won’t earn money from any grid relief the battery might provide. Instead, like the other large-scale battery projects being built in Massachusetts, it will earn money through the state’s Clean Peak Energy Standard, which offers credits for charging up with renewable energy and discharging it during times of peak demand. And Trimount is seeking to contract the project to one of Massachusetts’ major utilities, which are under state mandate to procure 5 gigawatts of energy storage by 2030.
But if ISO-NE wants to take advantage of the potential transmission savings of Trimount and similar battery projects, it may need to work with stakeholders on another way of doing it. At present, the grid operator’s “storage as a transmission-only asset” (SATOA) structure, approved by federal regulators in 2023, bars batteries from doing anything else if they’re used to relieve transmission constraints.
There’s a market rationale for this separation. Grid operators draw a hard line between transmission assets and other energy-market resources like power plants and batteries. If a battery project is collecting money for being a transmission asset, that revenue could subsidize the other energy-market services it provides, giving it an unfair advantage over competitors.
The same kind of limitations apply to the storage-as-transmission-asset rules at the Midcontinent Independent System Operator, which manages the transmission grid and energy markets across 15 U.S. states from Louisiana to North Dakota. It has limited its use of those rules to only one relatively small project to date.
Other major grid operators, such as PJM Interconnection, which covers Washington, D.C., and 13 states from Virginia to Illinois, have yet to develop rules for storage as a transmission asset. In PJM, that absence has played a role in stymieing proposals to use batteries to facilitate the closure of aging fossil-fueled plants.
Alex Lawton, a director at trade group Advanced Energy United, suggested that grid operators may want to find ways for batteries to make money across both energy markets and transmission services in order to use energy storage to help relieve their increasingly urgent transmission shortfalls.
“Yes, we are going to need to build more lines. But we want to do that cost-efficiently,” he said. “If it can be solved with a battery, that needs to at least be considered. And we want an analysis that shows all those things.”
Market rules aren’t the only barrier. There’s also the issue of forcing these projects to be part of the glacial pace of planning, approving, and building power lines. Under ISO-NE’s SATOA plan, any battery meant to help defer a grid build-out has to be identified through regional transmission plans, which take years to develop.
Currently, ISO-NE’s soonest opportunity to update its approach to integrate batteries into its transmission planning may be as part of its upcoming work to comply with the Federal Energy Regulatory Commission’s 2024 order to modernize long-term transmission planning, Lawton said. Among the mandates in that sprawling order, FERC calls on grid operators and utilities to incorporate advanced transmission technologies, which can expand the capacity and flexibility of existing power lines.
“We’ve always advocated with long-term transmission planning that there should be a robust process to evaluate alternative transmission technologies,” he said. “Storage is, in some cases, the most cost-effective solution.”
But just as companies that own power plants jealously guard their market position against new competitors, utilities that own and operate transmission grids tend to guard their incumbent advantages in winning contracts to build new power lines. ISO-NE’s current SATOA rules don’t provide incentives for transmission owners to consider adding battery storage as an alternative to building power lines, which earn them guaranteed rates of profit, Lawton noted.
The Trimount project “could be a really excellent case study to make a case for revisiting SATOA, and strengthening it and expanding it,” he said. It will certainly be worth observing how the project’s future patterns of charging up with excess clean energy and discharging during peak hours, which it’s incentivized to do under the Clean Peak Energy Standard, coincide with relieving the congestion on that part of the transmission grid.
In the meantime, building an enormous battery right next to a major city will bring multiple benefits, Jupiter’s Detweiler noted. The company commissioned a study by Aurora Energy Research that found the Trimount project could save ISO-NE customers about $1.6 billion in capacity market costs over its 20-year lifetime by deferring the need to build other power plants to serve the region’s peak needs.
It remains unclear how ISO-NE will choose to incorporate the Trimount project into its transmission planning once it’s operational, Detweiler said. “We are confident that they will notice when a project like ours goes up. The question is how they do the valuation.”
Sitting below sea level along the hurricane-prone Gulf of Mexico, New Orleans is particularly vulnerable to losing power during extreme weather. But the city plans to tackle that problem by helping residents buy backup batteries, which will make the grid more resilient.
In December, the New Orleans City Council ordered local utility Entergy New Orleans to design a $28 million battery incentive program for homes, businesses, and nonprofits (plus $2 million for administration and implementation). Crucially, the scheme won’t cost New Orleanians a dime: It will be paid for by a settlement Entergy reached with the city over problems at one of the utility’s nuclear power plants.
Entergy has until March 1 to file an implementation plan for the program, which is expected to launch later this year. Once the plan is up and running, the incentives could support batteries at around 1,500 homes and 150 community institutions. Those systems would provide backup power for the properties they’re sited on, but also inject power onto the grid when it’s strained.
This would propel New Orleans to the forefront of localities adopting virtual power plants, the concept of aggregating energy devices in homes and businesses and wielding them like a traditional power plant for the good of the broader community. Vermont’s biggest utility has used home batteries to lower costs during heat waves; California tapped home batteries to meet demand in extreme moments; Texas has opened up a market-based version of the concept. But New Orleans would become a pioneer of virtual power plants in the Deep South, and would stand out for the scale of the program relative to the size of the territory.
“We hope if you were already on the fence about getting a battery, here’s a chance to participate in a utility program,” said Ross Thevenot, senior project manager at Entergy New Orleans, who oversees the customer-facing battery effort. “We’re the Crescent City — we’ve got water on all sides of us. Customer resilience is obviously important.”
The new investment builds on Entergy’s pilot virtual power plant, which enrolled nearly 140 customer-owned battery systems across the city last year. EnergyHub, a cleantech startup acquired by smart-home company Alarm.com in 2013, manages the distributed controls for the pilot and will run the expanded program. The initiative also builds on a grassroots effort called Community Lighthouse, which formed after 2021’s Hurricane Ida and has installed backup-battery systems at nearly 20 churches so that they can offer shelter and light to neighbors during grid failures.
“We’ve seen how useful those can be when there’s a power outage,” said Nathalie Jordi, who works with Together New Orleans, the nonprofit that spearheaded Community Lighthouse, and who advocated for the new virtual power plant. “But how great would it be if, when the power goes out long-term after a hurricane, we have nursing homes that don’t lose their power, we have hardware stores, we have bodegas, we have firehouses?”
If the emerging plan succeeds, New Orleans could teach other parts of the U.S. how to build a cleaner, more responsive grid in a way that brings the whole community along.
Arushi Sharma Frank, a D.C.-based distributed energy expert, got an urgent message from Jordi in September 2024. The New Orleans City Council, which, unusually, serves as the city’s utility regulator, wanted to hear how the Community Lighthouse locations had performed during outages from Hurricane Francine earlier that month. Together New Orleans knew there was settlement money available, and it wanted to bring the council a fully-fledged virtual power plant proposal that could put those funds to work. Jordi wondered if Frank could propose a turbocharged virtual power plant like she’d helped design in Texas and Puerto Rico.
For Frank, this offered a chance to harness existing grid technologies to save lives in the aftermath of a hurricane or other disaster.
“There are life-threatening conditions that can be averted if people can get to shelter with power and cooling quickly,” Frank said. Small-scale batteries could ensure that “we have a place that any human in New Orleans can walk to in 15 minutes that has power after a storm.”
She got to work, compiling a proposal in 72 hours and arranging for people to testify from 12 other states with operating virtual power plants. The last-minute blitz worked: The City Council green-lit an effort to explore the concept, culminating in the December order.
Often, the companies selling energy devices to regular people cast themselves as electric Davids taking on the utility Goliath — as disrupters of a failing status quo.
In New Orleans, Frank said, the community groups were able to “remove this tone of adversarialism” that frequently crops up in virtual power plant proceedings around the country, and instead design something “generative, as exposed to extractive.”
The program creates a new market opportunity for solar-battery installers, with upfront incentives that can shave up to $10,000 off the cost of batteries for homes or $100,000 for businesses. It will still be up to cleantech companies — local ones or national brands like Sunrun or Tesla — to compete for customers’ business and guide them through the sales process. Those companies will be the ones designing the systems to provide backup power in the event of outages. And the order earmarks 40% of the residential funds for households with low to moderate income, ensuring installers don’t just pitch to more-affluent customers.
Once the batteries are installed and hooked up to EnergyHub’s control software, it becomes Entergy’s job to decide how and when to use them to benefit the power system more broadly. The regulated monopoly utility has knowledge that battery vendors don’t: which parts of the grid need more capacity or struggle to manage voltage when clouds interrupt rooftop solar production, for example, and other such nuances of a complex interconnected network.
Since Entergy runs the grid and charges customers for the service, it’s also able to pass along savings in the event that the virtual power plant lowers overall grid costs.
“Nonparticipating ratepayers are definitely enjoying the benefits of just having more affordable power, because VPPs are cheaper than traditional grid infrastructure and much quicker to stand up,” said Gabriela Olmedo, EnergyHub’s manager of policy and regulatory affairs.
If Entergy can eventually harness tens of megawatts of aggregated battery capacity, Thevenot said, the utility could bid that into the Midcontinent Independent System Operator’s regional grid and use the ensuing revenue to pay down costs for the overall customer base.
Utilities habitually seek an extended trial phase for “new” technology, even if the same equipment has been operating successfully for years elsewhere in the country. Sometimes, that preference for diligent study pushes off adoption of viable grid technologies. In this case, though, New Orleans was able to move swiftly on its virtual power plant because Entergy’s initial foray had laid a careful groundwork.
Under its existing pilot project, EnergyHub manages those nearly 140 batteries — mostly in homes, but also about a dozen in Community Lighthouse installations. The program pays homes up to $600 per year for sending energy to the grid for two-hour stints when demand is especially high. Last year was the first full year this system operated, and Entergy dispatched it six times, Olmedo said, largely to test that the system works.
“We started slow and steady: Let’s learn what the positives and potential speed bumps are,” Thevenot said. “It was a true pilot. We were trying to learn as much as possible.”
Entergy “got great data,” he added, and learned to troubleshoot in situations when batteries didn’t respond because of issues like internet-connectivity lapses or system settings preventing power from being dispatched.
Having six dispatches per year falls on the leisurely end of the virtual power plant spectrum. A program in Oahu, Hawaii, for instance, pays customers to set their batteries to discharge for two hours every evening, when the island grid is bound to have high demand.
That said, in this pilot phase, Entergy wanted to be judicious about using the batteries that customers had already bought and paid for, Thevenot said. And the summer of 2025 proved to be far less stressful for the local grid than the previous summer, dampening the need for battery assistance.
The plan had been to increase dispatches to 30 per year, Olmedo noted. (The forthcoming implementation plan will decide what the target is going forward.)
Each dispatch will make a far bigger difference once the new funds get disbursed: The incentives are expected to support roughly 10 megawatts of residential batteries and 10 megawatts of nonresidential, Olmedo said. All that capacity will fall within the city boundary, making for a far more concentrated impact than programs that sprawl over, say, the state of California.
Normally, a small customer base can make it hard for a utility like Entergy to propose spending on innovative programs like a virtual power plant, Frank said. The cost of a battery subsidy would be divided among the customer base, and there simply aren’t many customers to split the tab; many New Orleans households earn a low or moderate income, making them especially sensitive to jumps in utility bills.
“If we were forced to do this and run $28 million through some kind of rider we’d have to collect from customers, that would be a different conversation,” Thevenot said.
The pot of settlement dollars circumvented this dynamic, funding innovation without adding to anyone’s monthly bill. “Any dollar that they do spend on creating socialized infrastructure, it also goes further because of the same math,” Frank added.
This may limit how replicable the New Orleans experience can be in other locales. “Wait for a bucket of utility penalty funds to materialize” is not a particularly actionable directive for would-be grid reformers. But New Orleans can show the world what good a bunch of batteries can do, and quantify eventual operational savings for the whole customer population. Then, advocates can argue for funding this sort of program on its own merits, based on evidence of how useful it has been in the Crescent City.
Jeff St. John contributed reporting.
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