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In western Illinois, ComEd is tapping a rarely used technique to fast-track community solar installations — working with, not against, environmental groups and solar project developers.
For years, utilities have explored the concept of flexible interconnection, in which solar projects are allowed to come online even when, by the books, there’s not enough space on the grid for these arrays. In return, these solar farms must promise to curtail output during the handful of hours each year when their production would overwhelm power lines and substations.
Flexible interconnection is a speedy way to get cheap new solar online without requiring utilities to spend even more on costly grid upgrades, which are a key driver of the nation’s fast-rising utility bills.
But U.S. utilities haven’t made use of the technique at any significant scale — until ComEd got its program off the ground late last year.
Since then, the utility has fast-tracked more than 50 megawatts of community solar projects using flexible interconnection, and more are likely to be approved before federal tax credits sunset in July.
That’s much faster than utilities in other states have been able to move on flexible interconnection, said Samantha Weaver, senior director of interconnection and grid integration policy at the Coalition for Community Solar Access, a trade group representing community solar developers. In fact, ComEd is “leading the country right now,” she said.
ComEd plans to accelerate that work, said Jessie Bauer, the utility’s senior manager of smart grid and innovation. “Our plan was to do 50 megawatts a year, and we’re hitting that cadence,” he said. “We’re proposing in our grid plan to go even faster, and do 100 megawatts a year, and get to 650 megawatts by 2031.”
The utility has previously committed to deploying 240 megawatts of distributed energy capacity by 2030 to meet its requirements under Illinois’ landmark 2021 climate law.
ComEd was able to succeed where other utilities haven’t thanks to a nudge from regulators that spurred it to collaborate with solar developers and environmental groups.
Historically, utilities and solar developers have struggled to establish the basic mutual trust required to move a flexible interconnection program forward, Weaver said. Utilities are often skeptical that solar farms will reliably cut back as promised during those key hours of potential grid overload. Meanwhile, solar developers suspect utilities will force them offline more than is absolutely necessary.
Illinois’ flexible interconnection process didn’t go that way.
Instead, in 2024 ComEd collaborated with environmental groups represented by the consultancy Eclipse on a flexible interconnection plan. Then, the utility worked out mutually agreeable solutions with those groups, solar developers, and the nonprofit collaborative the Charged Initiative, in a series of workshops that resulted in a program design that gave each side enough of what they needed to move ahead.
Both the utility and solar developers had to make some compromises, Weaver said. But that effort bore its first fruit last November, when 27 megawatts of community solar was green-lit in a region where it would have been excluded by traditional processes. Another 25 megawatts of projects were approved in February.
This coordinated approach is now gaining some momentum in Maryland, Massachusetts, New York, and other states where community solar is struggling, said Nikhil Balakumar, Eclipse’s CEO and founder.
“Now, more than ever, especially in this climate, we need unprecedented collaboration,” Balakumar said. We can’t just slog it out and fight and litigate every little thing till the end of time. There has to be a new way forward.”
ComEd’s push into flexible interconnection was less a choice than a necessity.
Since 2016, Illinois has created and expanded programs that offer lucrative incentives to build community solar projects, which are generally limited to no larger than 5 megawatts. Households can subscribe directly to these projects, which often allow them to lock in cheaper, cleaner energy. The state’s programs are explicitly meant to reduce utility rates for low-income customers.
In Illinois, developers have flooded into the programs over the years, snapping up the most suitable land for community solar arrays.
This posed a problem for ComEd: Everyone wanted to build their solar arrays in the same relatively concentrated geographic area — the rural western reaches of its territory — where there simply wasn’t enough space on the grid.
“We quickly saw all that grid capacity evaporate with the community solar being connected,” Bauer said.
In a situation like this, the standard utility playbook is to require community solar developers to shell out for grid improvements. In western Illinois, that would mean multimillion-dollar system upgrades, he said — a cost that few solar developers can afford.
However, the grid actually does have the space to accommodate those solar farms — at least, most of the time.
Distribution grids are built to serve the times when electricity demand is at its highest. These peaks in demand are relatively rare, happening only during a handful of hours per day, or days per year. That means for the vast majority of the year, there’s unused capacity sitting there.
Flexible interconnection takes advantage of this fact — and helps developers and consumers avoid exorbitant grid upgrade costs as a result.
“If you can give up some of your energy during times of system constraints, you can interconnect much more affordably,” Bauer said.
But this is easier said than done. Utilities can’t perfectly predict how often demand will peak. They need flexibility to handle unexpected changes and respond to emergencies. A major storm or flood could knock out an entire substation for months, leaving other parts of the grid straining to supply power until it’s repaired.
That uncertainty constrains utilities from setting guaranteed limits on how often they’ll ask solar projects to curtail their generation. But for solar developers, “projects aren’t financeable if curtailment is unpredictable,” Weaver said. “We need certain details to be able to literally take to the bank.”
To resolve this conundrum, ComEd and solar developers collaborated on a compromise.
Solar developers calculated that they — and their investors — could bear having about 5% of their annual solar production curtailed. They conceded that ComEd couldn’t guarantee it would stick to that curtailment limit. But if the utility was willing to share historical data on how often its grid was likely to face overloads, developers could use that to convince those investors that the risk was worth taking.
That wasn’t the solar industry’s initial ask, Balakumar noted. Solar developers started out asking for “some sort of fund that compensates us if you do go over 5%,’” he said. But ComEd pays for the power it purchases by passing those costs on to its customers — and the prospect of charging customers for power that didn’t actually get onto the grid was a nonstarter for consumer advocates and regulators.
“We went in wanting a guarantee,” Weaver said. “But we came to the understanding that that wasn’t realistic and that we needed to give up a degree of certainty.”
Nor was it easy for ComEd to agree to sharing confidential data on its substations. Bauer said that process was helped along by community solar developers limiting what data they needed and how they would use it.
Already, the real-world data coming in from ComEd’s flexible interconnection projects could allow it to tighten curtailment expectations for future rounds of development, Bauer said. That could make community solar projects more lucrative to financial backers — and given that the alternative was to not be able to build them at all, or to wait for years for utility grid upgrades to plug them in, that’s better than nothing.
Regulated utilities like ComEd earn profits from the investments they make to expand or upgrade their power grids, not from connecting third-party solar projects. If anything, flexible interconnection exposes them to grid instability risks. Meanwhile, sharing data on how efficiently they utilize their grids can weaken the case for investing in moneymaking upgrades.
But in Illinois, policymakers and regulators forced ComEd’s hand.
Under the 2021 Clean Energy Jobs Act, ComEd and fellow utility Ameren Illinois must invest in their grids to improve customer affordability and meet state climate and clean energy goals. In 2023, the Illinois Commerce Commission rejected the initial grid modernization plans filed by ComEd and Ameren Illinois, because of critiques including an absence of commitments to streamline interconnection of distributed energy resources like community solar systems.
That’s when Eclipse started working with the Environmental Law and Policy Center, the Environmental Defense Fund, the Natural Resources Defense Council, the Union of Concerned Scientists, Vote Solar, and other groups to get ComEd to the planning table, Balakumar said. The following year, these groups agreed to a memorandum of understanding with ComEd, which led to the joint plan submitted to regulators in late 2024.
ComEd then set up that workshop series with solar developers and environmental advocates over the course of 2025. That’s where parties hashed out their positions and came up with compromises that they could live with, Weaver said.
“To give credit where credit is due, the utility came with a lot of information and proposals they’d developed in advance for developers,” she said.
That included detailed information on the capabilities — and limits — of the utility’s technologies to make flexible interconnection possible, Bauer said. For example, one solar developer asked for hour-ahead forecasts of when the utility would curtail projects, he said. “We can do that in the future — in fact we plan to,” he said. But if ComEd had been forced to wait until it could warn solar projects that they would be curtailed an hour in advance, “we wouldn’t have launched this year — we would have launched in a year or two.”
ComEd also chose not to immediately incorporate all the different distributed energy resources that state law requires it to eventually handle, he said. “We were deliberate and focused on community solar, because we recognized that those were not only where the need was, but because those are the most technically sophisticated customers.”
The flexible and collaborative approach that ComEd and solar developers have undertaken stands in contrast to some much slower processes in other states. In California, for example, it took nearly four years between regulators ordering utilities to make flexible interconnection possible and finalizing the rules that allow it to happen — and California still hasn’t created a workable community solar program to make use of those rules.
But speed is of the essence as community solar developers rush to start their projects before July. That’s the deadline for achieving “safe harbor” status for earning tax credits set by the massive tax and spending package passed by Republicans in Congress last year. “Because of these changes happening in the tax credits, we realized we needed to move faster,” Bauer said.
Balakumar agreed that “to go from March workshops to a full-blown program in November for a utility is lightning speed.” But regulators and utilities in states with clean-energy and climate goals that haven’t moved as quickly are setting themselves up for even greater costs — and arguments over who’s going to pay for them — once the window for securing federal tax credits has closed, he said.
That’s not to say that other states can’t still learn from Illinois, he said. Take New York and Massachusetts, two states where Eclipse is closely involved in flexible interconnection work.
“We were in workshops in New York with Avangrid and National Grid,” two utilities serving upstate regions with a lot of community solar and grid constraints, Balakumar said. There, solar developers are “talking to banks and thinking about how they can get much more creative.” In January, National Grid filed a proposal to enable flexible interconnection at seven substations, each potentially hosting 30 to 60 megawatts of new projects.
And in Massachusetts, where utilities have struggled for years to connect more community solar projects, Eclipse has been involved in a workshop jointly hosted with a state regulator–created interconnection working group, with the goal of jointly filing flexible interconnection proposals with National Grid and Eversource “as soon as possible this year,” he said.
Those utilities are actively expanding their grids to accommodate more community solar. But flexible interconnection could allow many projects to connect while deferring $239 million in proposed upgrades, Balakumar said in November 2025 testimony in a proceeding reviewing new grid investment proposals.
In March, ComEd engineers came to a Massachusetts flexible interconnection workshop to share their experience, according to Nick Burica, senior director of grid planning and interconnection engineering at community solar developer Nexamp.
Utilities have plenty of reasons to be leery of requests to operate their grids in this new and unfamiliar way, noted Burica, who previously led development of distributed energy engineering for ComEd. But when those kinds of objections arose, ComEd was “in the room,” able to say that “it will provide energy affordability, and you’ll be able to operate your system better,” Burica noted.
“I was so happy to see ComEd come out and champion what can be done with flexible interconnection,” he said. “Getting people together — industry, utilities, and outside consultants — we’re starting to see the fruits of this labor.”
A community north of San Diego has blocked a major grid battery that a developer had hoped to build in a residential area near a major hospital.
Independent power producer AES Corp. withdrew its application to develop the Seguro battery system in Escondido, 30 miles from San Diego. The company had intended to fill a former horse ranch with 320 megawatts of battery containers, which would have been one of the most powerful stand-alone energy storage facilities in the country. The facility would have strengthened the Southern California grid late in the day, when solar generation fades and home consumption surges, pushing the state forward on its quest to produce 100% clean electricity by 2045.
But the development ran into a barrage of local opposition, as residents decried adding large-scale power infrastructure so close to homes and 1,600 feet from Palomar Medical Center Escondido, especially given the multiday, high-octane fires at other large batteries in the state. The outcome was a high-profile win for local battery opponents, and a warning sign to developers in famously pro-battery California.
AES said in a statement that it would prioritize other development efforts, but remained “committed to advancing projects that can provide the safe, reliable, and affordable power needed to strengthen the region’s electric grid and generate meaningful economic benefits locally.”
JP Theberge, a board member of the Elfin Forest Harmony Grove Town Council who rallied resistance to the battery, framed his neighbors as a victorious David smiting a corporate Goliath.
“The forces of greed are very powerful in this world. The only way to stop them is to be united and determined and forceful,” he wrote in a post on the Stop Seguro Facebook group. “This was a great win and we should all be proud of our efforts.”
AES is, to be sure, a profit-driven company, but the vast majority of U.S. energy infrastructure is built and operated by for-profit entities. What AES hoped to profit from was delivering a large amount of emissions-free grid capacity at a time when California desperately needs more of it — and when the nation as a whole is grasping for more power.
Opponents also called out the risks of large agglomerations of lithium-ion batteries, which have in certain circumstances gone into “thermal runaway,” when cells heat up and kick off ferocious blazes that spread to all the batteries within reach.
Escondido has experience with batteries. AES built a large-scale lithium-ion battery in 2017 that utility San Diego Gas & Electric owns and operates on its substation property. One battery container at that site caught fire in 2024 and prompted local evacuation orders that were lifted two days later. Two other California batteries loom even larger in the minds of the Stop Seguro advocates: An Otay Mesa battery, also in San Diego County, caught fire and then smoldered for 17 days in 2024, destroying one section of a larger facility. A Moss Landing project had a string of small fires, followed by catastrophic one in January 2025, which forced the evacuation of the surrounding community.
Crucially, those two fires involved older models of battery cells, and a now-outdated design that packed them into buildings, which was like piling dry timber ahead of lighting a spark. Since then, battery cell technology has improved, and the industry has abandoned storing batteries in large buildings in favor of compartmentalized containers spread across a site. These designs are tested to make sure that a fire in one unit cannot reach surrounding units. Thus, a really bad failure could burn up one container but not produce the kind of dayslong conflagration seen in the highest-profile battery fires.
That’s where separating fact from fearmongering can get tricky. Otay Mesa and Moss Landing were approved by the necessary authorities, and then combusted in catastrophic fashion. Any community would be justified in wanting to prevent something like that from happening. At the same time, the physical causes of those massive blazes simply don’t exist in the battery projects that are getting built today.
Even so, Seguro would have pushed the boundaries in terms of proximity to homes and to the hospital. If one container started smoking, that could be enough to force the hospital’s patients and staff to either evacuate or shelter in place. This fact became pertinent to the case, because AES needed the hospital to sign off on running high-voltage wires through its property, which the hospital board voted down in 2024.
Generally speaking, though, recent battery failures have not put a stop to new battery construction.
Elsewhere in California, developer Arevon broke ground this year on a 250-megawatt battery in Daly City, just south of San Francisco. The battery fires in other parts of the state did not stop the company from securing permits and easements to connect to a nearby substation. That project will inject $73 million dollars into the local tax base, and give San Francisco a major new source of on-demand power to carry it through heat waves and other moments of stress for the grid.
Indeed, batteries continue to set records for participation in California’s energy system. On a given spring day, they show up in force in the evening hours, displacing expensive, more polluting gas plants by shifting the day’s solar production to meet the hours of highest demand. On March 29 at 7 p.m., for instance, batteries delivered a record 44% of total electricity demand, with more than 12 gigawatts injected into the grid.
A clarification was made on April 9, 2026: This story was updated to clarify that the battery AES built at the utility substation has been owned and operated by San Diego Gas & Electric since 2017.
There’s nothing like a common enemy to bring people together. This midterm election year, that enemy may be data centers.
As AI grows more powerful and more popular, tech companies are rushing to build facilities that house all that computing capability — and to secure tons of power to run them. But no one knows exactly how many of those data centers will get constructed, and how much electricity they’ll need. That’s a problem for utility customers, who may be saddled with the costs and climate impacts of an unnecessary gas power and grid infrastructure buildout.
Some states are tackling the problem with what are known as large-load tariffs: essentially, special rates and requirements that force big power users to shoulder the costs of grid buildouts. But this week, a small city in Wisconsin put its foot down. Port Washington, a suburb of Milwaukee, voted by a roughly 2-to-1 margin to require that city leaders get voter approval before awarding tax breaks to data centers and other large development projects. It’s a clear response to the $15 billion OpenAI and Oracle megaproject that’s being built in the city, though this newly approved measure comes too late to affect that project.
At the federal level, Democrats have spearheaded most of the campaigns against data centers, with Sen. Bernie Sanders (I-Vt.) and Rep. Alexandria Ocasio-Cortez (D-N.Y.) even proposing a nationwide moratorium. But Port Washington is part of Ozaukee County, which has voted for Republicans over the past 20-plus years of elections.
Also this week, residents in Festus, Missouri, voted to oust every incumbent on their City Council, in large part because the decision-makers had approved a controversial $6 billion data center in the area. Jefferson County, where the city is situated, voted overwhelmingly for Republicans in the 2024 elections.
Indianapolis, meanwhile, saw a more violent reaction: Someone fired over a dozen bullets at City Council member Ron Gibson’s home on Monday, and left a note reading “No Data Centers” on the legislator’s doorstep. Gibson is a Democrat who has publicly supported a data center project in the city.
Across the U.S., more data center questions are on the ballot. Residents in Monterey Park, California, will determine in June whether to completely ban construction of the facilities. In the fall, Boulder City, Nevada, will vote on whether a municipally owned plot should host a data center, and residents in Janesville, Wisconsin, will decide whether to add more hurdles to a project turning a former General Motors plant into a data center.
At least 11 states are also considering legislation that would pause new data center construction, with a bill in Maine likely to be the first to become law.
City-level data center restrictions like Port Washington’s certainly don’t have the heft of state-level bans or even a nationwide moratorium, as far-fetched as its passage may be. But they do show that data center opposition is on the rise in every nook and cranny of the country — and it may have a massive influence on more than just local elections this November.
Clean Energy Team dominates Arizona utility election
Arizona voters this week selected a slate of candidates known as the Clean Energy Team to run the state’s largest public utility, the Salt River Project.
The winners may have Turning Point USA, the Charlie Kirk–founded conservative organization, to thank. The SRP delivers power and water to more than 1 million customers in the Phoenix area, and its leaders are chosen through an unusual election in which the number of acres a customer owns determines how many votes they can cast. These races typically don’t get much turnout, but this year, Turning Point stepped in to endorse candidates who supported converting retiring coal plants to gas. That prompted clean energy advocates, including the Sierra Club and actor and advocate Jane Fonda, to get involved.
All that attention definitely juiced turnout: This year’s election saw four times as many ballots as 2024’s, The New York Times reports. Two Turning Point–backed candidates did win races for SRP’s board presidency and vice presidency. But candidates who support clean energy swept the remaining races to take majority control of the board and double their representation on SRP’s advisory council.
Here’s where balcony solar is taking off
You’ve probably noticed that electricity bills are on the rise. If only curbing them were as easy as buying a portable solar panel and plugging it into your wall to generate your own clean power.
In two states, it pretty much is. This week, Maine joined Utah to become the second state to legalize the use of “balcony solar” panels, which can be plugged into standard outlets to help offset homeowners’ power usage. Other states may soon join them: Canary Media’s Sarah Shemkus has put together a map showing where bills to legalize balcony solar are in the works, with some needing only a governor’s signature to become law.
Whale, whale, whale: The Trump administration struck down Endangered Species Act protections for whales to unleash oil and gas development in the Gulf of Mexico — even though it has used unfounded claims about offshore wind’s risks to the creatures as an excuse to undermine that industry. (Canary Media)
Ceasefire’s energy impacts: Oil prices have fallen since the announcement of a two-week ceasefire between the U.S. and Iran, which analysts say may quickly translate into gasoline price relief for Americans. (The Hill, Axios)
New Jersey goes nuclear: New Jersey lifts its de facto ban on nuclear power construction, becoming the sixth state to reauthorize reactor development in the past decade and the second, after Illinois, to do so this year. (Canary Media)
Winds of change: The U.S. Interior Department quietly fails to appeal court decisions that allowed work to restart on offshore wind projects halted by the administration, an omission that experts say could be an early sign of hope for the industry. (Grist)
Digging clean heat: A geothermal heat pump system that’s heating and cooling a church just outside New York City could pave the way for similar projects in dense urban areas. (Inside Climate News)
Solar soars: A federal report shows rooftop solar now accounts for 20% of Puerto Rico’s energy production, surpassing natural gas to become the island’s second-largest generation source, behind petroleum liquids. (Utility Dive)
Renewables reign: In March, renewables generated more power than gas across a whole month, marking a first for the U.S. grid. (Canary Media)
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.
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