Back
Firms that enlist homes to reduce energy demand — and costs — have long complained that utility data rules prevent them from helping in PJM. FERC agrees.
A recent ruling from federal regulators will let virtual power plants help meet surging energy demand in the county’s biggest energy market.
Late last month, the Federal Energy Regulatory Commission ordered PJM Interconnection to accept statistical sampling as a valid method for measuring the reliability of programs tapping into demand-response and virtual-power-plant programs, which pay customers to turn down energy use as needed. The decision requires the grid operator to reconsider strict data rules that had prevented providers of this carbon-free resource from participating in PJM’s constrained energy-capacity market.
In its decision, FERC ruled in favor of Voltus, which runs demand-response and virtual-power-plant programs, and the Mission:data Coalition, a nonprofit advocacy group, and against PJM’s desire to preserve its status quo.
FERC agreed with Voltus and Mission:data that, under its current rules, PJM is losing out on at least 4.9 gigawatts of capacity — the equivalent of several large power plants — “at a time when PJM is experiencing unprecedented load growth driven in part by hyperscale data center development, threatening reliability.”
Booming power demand from data centers and bottlenecks in power plant construction are not just threatening reliability in PJM but also driving up energy costs for the 67 million people it serves across 13 states. FERC found it would be “unjust and unreasonable” to allow the current rules to stand.
Last month’s ruling caps a yearslong fight from providers of demand-response and virtual-power-plant services.
“This is a huge win, and we’re really optimistic that it will unlock hundreds of megawatts of residential load over the next several years,” said Marissa Galizia, Voltus’ senior director of partnerships. FERC’s order makes clear that “PJM has the power to change the rules even while utilities aren’t providing the data,” she said.
At issue was PJM’s concern about relying on third-party demand-response aggregators to reduce household electricity demand when needed. PJM insisted that Voltus and other demand-response firms must furnish detailed evidence that participating households actually cut power when prompted to do so. Specifically, PJM required smart-meter data, which is collected in the service territories of most utilities PJM covers.
If firms could not produce that data, PJM would not count on — or pay for — that demand-response capacity to show up during times of peak demand.
But for the most part, demand-response firms could not get their hands on that data. That’s because, as Voltus and Mission:data argued to FERC, most of the major utilities in PJM territory have failed to make that data from their digital smart meters readily available.
It’s a catch-22. And as a result, PJM has missed out on gigawatts of demand-response capacity that could have helped alleviate the reliability and cost crunch it faces — and aggregator firms have been essentially locked out of the lucrative capacity market.
Utilities blame states’ data privacy regulations for their conservative management of smart-meter data. FERC doesn’t get to tell states how to manage those data privacy and data access rules, but it can compel PJM, which it has jurisdiction over, to accept alternative forms of data.
That’s what FERC did in the July decision.
Given the “significant barriers to obtaining interval meter data,” FERC told PJM to allow aggregators to use a statistical sampling method that the grid operator had relied on before smart meters existed. PJM also still allows this method for customers that don’t have smart meters. In light of those facts, FERC found that “statistical sampling is a valid method to approximate load reductions when interval meter data is not reasonably available.”
Both PJM staff and Monitoring Analytics, its independent market monitor, protested that letting demand-response companies use statistical methods could undermine reliability.
Monitoring Analytics argued that allowing statistical sampling would “degrade PJM’s ability to maintain resource adequacy and to correctly determine efficient capacity market prices through supply and demand.”
FERC disagreed, citing evidence presented by Mission:data and Voltus showing that statistical sampling can be as or more accurate than methods that use metered data when applied to large numbers of homes, as opposed to single large customers like factories.
The order won’t take effect immediately. FERC directed PJM to launch a proceeding to work with stakeholders to find a method that parties could agree on, with initial plans due within 45 days of FERC’s order.
“We’re going to be working with our partners to submit answers to the questions and propose what we’d like to see,” Voltus’ Galizia said. “Generally, we’d like to make it as easy as we can while guaranteeing that that process is as accurate as possible.”
FERC’s ruling comes at a tense time for PJM. Over the past year, the Trump administration and state governors have attacked the grid operator for failing to mitigate the huge increase in capacity market prices that are driving up utility rates and driving public anger against utilities and data center developers.
“I hope the decision sends a message to PJM and its stakeholders,” said Ken Schisler, chief legal and regulatory officer at CPower, a demand-response company that brought a similar complaint that FERC rejected in 2024 for lack of evidence. “The message is to stop the nonsense and to remove barriers that are keeping demand response from growing in the market.”
Michael Murray, president of Mission:data, hopes the ruling will also add fuel to his decade-long effort to make utilities and state regulators unblock smart-meter data that technically belongs to customers.
FERC’s order doesn’t address the underlying state-by-state data-access barriers that Mission:data is working on — the agency doesn’t have the jurisdiction to do so even if it wanted to.
Still, Murray hopes it will push state regulators to revisit their data-access policies, since “states may not like the remedies that FERC comes up with in this case or in other cases.”
And more broadly, he said, it’s the first time the agency has acknowledged just how critical this issue is.
“FERC has finally recognized that what I’ll call data blocking is not just an artifact of state privacy laws, and it’s not something to just ignore and say, ‘Oh this is just a state matter,’” he said. “They definitely said that it rises to a Federal Power Act matter.”
The Department of Energy has canceled or stalled funding for thousands of projects that would improve the country’s stressed grid — and not just in blue states.
In Wisconsin, utility Alliant Energy has called off a project meant to reduce power outages in disadvantaged and tribal communities, after the Trump administration terminated a federal grant that would have supported it.
In California, the Sacramento Municipal Utility District, which has deployed and upgraded hundreds of thousands of advanced smart meters, has not received any reimbursement from the U.S. Department of Energy for the work since October, when the Trump administration declared it was killing grants that it described as fueling “the Left’s climate agenda.”
And in the upper Midwest, a consortium of regional grid operators, utilities, and state agencies is still waiting for $464 million in DOE funds meant to help build high-voltage transmission lines to reduce grid congestion — although the agency in charge of the project says the funding will soon be restored.
Across the country, hundreds of such projects to improve grid reliability and make electricity more affordable face a highly uncertain future — the result of Trump administration actions that have slowed the outflow of billions of dollars of DOE funds to a trickle.
Some of those projects in “blue states” were targeted as political retribution, as recent reporting from The New York Times has made clear. A handful of grant awardees in this category have won favorable court rulings, and more are seeking legal redress.
But many others are suffering from the DOE’s broader failure to carry out work that Congress has tasked it to do, according to groups that have been monitoring the agency since the start of last year. In red and blue states alike, the DOE is forcing thousands of grantees to undergo a laborious review process, so even projects that have not been officially terminated are stuck, unable to determine when or if they’ll start getting the money they’re owed.
According to an April report from the DOE Alumni Network, a group of former agency employees, the DOE has announced the termination of 356 awards totaling $12.5 billion since January 2025, and has threatened to terminate 303 additional awards worth $12.2 billion.
But the DOE has also stalled projects for “a large number of awardees who have never appeared on any list,” the report found. “This means the agency is not moving forward to resolve disputes, finalize conditional awards, or respond to continuation applications, leaving projects in administrative limbo and functionally freezing promised funds.”
“DOE both overtly canceled a set of projects, then had this pattern of behavior where for 15 months they stopped actively managing projects,” said one former DOE official. “Projects can’t proceed to the next stages and get their next tranche of funding.”
The former official, who asked not to be named, described a pattern of stalling, stonewalling, and “ghosting” utilities, state governments, energy companies, and nonprofit groups awarded grants under the Biden administration.
Many of those projects have been caught up in a process the DOE announced in May 2025 to review all financial assistance “on a case-by-case basis to identity [sic] waste of taxpayer dollars, protect America’s national security and advance President Trump’s commitment to unleash affordable, reliable and secure energy for the American people.”
Then, in October, the DOE announced the “termination of 321 financial awards supporting 223 projects” — all of them tied to states that voted for Kamala Harris in the 2024 election. The DOE’s termination announcement came right after Russ Vought, director of the White House Office of Management and Budget, declared in a social media post that the administration would cancel “nearly $8 billion in Green New Scam funding.”
Canary Media reached out to a subset of DOE grantees that had won funding from the Grid Resilience and Innovation Partnerships (GRIP) program created by the 2021 bipartisan infrastructure law. The DOE issued a total of more than 100 GRIP grants — in October 2023, August 2024, and October 2024 — for projects to enlarge the grid, harden it against extreme weather, build microgrids to protect vulnerable communities, and deploy technologies to integrate solar, wind, EVs, and batteries.
Some of the GRIP projects involve expanding clean energy and serving disadvantaged communities, two bugbears of the Trump administration. But many more are straightforward grid improvement projects that need federal dollars to reduce the costs borne by utilities and regional or state agencies.
The largest of these is in California. In 2024, the DOE awarded a $630.6 million grant aimed at upgrading more than 100 miles of high-voltage power lines in the state with advanced power cables capable of carrying more electricity along existing transmission corridors, a project estimated to be capable of delivering about $200 million in savings from improved energy efficiency. That project appeared on the termination list in October, and the DOE has not disbursed money for it, according to federal records, though negotiations for resuming funding are underway.
This uncertainty appears to apply to the majority of GRIP projects, according to Emlyn Bottomley, founder of the consultancy High Road Analytics, which focuses on workforce development, and a former Department of Labor deputy policy director in the Biden administration.
According to his tracking of federal spending, of the roughly $11.4 billion in DOE funds obligated to grid infrastructure and resilience — a category that includes GRIP program funds — $9.1 billion remains “at risk,” with funding stalled or timelines for completion shortened. That’s compared with $400 million in grants that have been canceled outright and $1.3 billion not yet disbursed but showing no signs of being stalled.
“It’s a shame these projects are being held up or canceled, especially since the case for them is fairly bipartisan — spanning national security, economic competitiveness, and cost and affordability,” Bottomley said.
All of the GRIP projects required partners to provide matching funds at an amount at least equal to the money DOE is providing, the former DOE official added. “You’re talking about folks putting hundreds of millions of dollars on the line. People have skin in the game for these awards.”
Many of the GRIP grantees contacted by Canary Media declined to comment, citing ongoing discussions with DOE. Others reported that they are no longer pursuing the projects as described in their grant applications, at least not with the help of DOE money.
The latter is the case for Alliant Energy’s Smart Power Automation in Rural Communities (SPARC) project, which won a $50 million grant in late 2024 to add grid visibility and control devices to 140 grid circuits in disadvantaged and tribal communities served by subsidiary Wisconsin Power & Light — a utility in a blue state.
Those devices could allow the utility to quickly find and isolate faults on its grid, cutting power outages in targeted communities by up to 50%. They could also support grid-management software to help integrate more renewable and distributed energy, and potentially expand wireless communications access to these remote areas.
Alliant “voluntarily withdrew” from the grant award process in April, six months after its grant was terminated by the DOE, Alliant spokesperson Melissa McCarville told Canary Media. The agency has disbursed no funds to the project, according to federal records.
Alliant is “actively pursuing many of the goals that were outlined in the SPARC project,” McCarville wrote in a May email, but as part of a 10-year strategic plan with no set timeline. “While the grant did provide valuable funding, it also required a significant investment, and we want to ensure our contributions are properly prioritized,” she wrote.
Still, at least one grant-funded project in a blue state is proceeding despite the absence of DOE funds.
That’s the case for the Sacramento Municipal Utility District, which serves the state’s capitol and environs. In 2023, SMUD won a $50 million grant to support a project to deploy 200,000 smart meters and grid devices and underlying software controls to “improve grid reliability, resilience, visibility and efficiency,” utility spokesperson Gamaliel Ortiz told Canary Media in an email.
SMUD has carried out much of that work, which includes close to $100 million in utility spending, and has received almost $33 million in reimbursements from DOE, according to federal records. However, SMUD “has not received reimbursement for any costs incurred after the grant was cancelled on October 10, 2025,” Ortiz wrote. “We remain committed to this critical work and stay flexible as we evaluate how the loss of grant funding may impact the project timeline.”
In other blue states, some grants have been canceled and others are still under negotiation. In Oregon, utility Portland General Electric has recently learned that the DOE may reinstate a previously terminated $50 million grant to support next-generation “grid edge computing” devices, utility spokesperson John Farmer told Canary Media in an August email. That project had received only $1.2 million in DOE funding, according to federal records.
The purpose of the project was to integrate batteries, EVs, and community solar into its grid to “improve resilience, enable the integration of distributed energy resources, and maximize customer investments in home energy solutions.”
“PGE is evaluating the benefits and risks of reinstating the grant,” Farmer told Canary Media. The utility “recognizes that there are inherent risks of additional and changing demands by the DOE as the administration’s priorities change.”
At the same time, PGE remains in discussion with the DOE on a $250 million grant to build a high-voltage transmission line with the Confederated Tribes of Warm Springs, Farmer wrote. “Without this funding, we would lose the opportunity to offset those costs with external dollars, which could limit how efficiently we can advance needed grid improvements.”
Red state projects are also being held up because the grantee is located in a blue state. Such is the case of the aforementioned $464 million DOE grant for the Joint Targeted Interconnection Queue project to build new transmission lines between the Midcontinent Independent System Operator and Southwest Power Pool, two grid operators spanning nearly a dozen Midwestern states.
The $464 million GRIP grant was meant to bolster $1.3 billion in matching funds from utilities in the region to enable nearly 30 gigawatts of new generation to be built in Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, and South Dakota. All but one of those states voted for Donald Trump in the 2024 election — but the Minnesota Department of Commerce, the entity awarded the grant, is in a blue state.
In May, the Minnesota Department of Commerce announced that the DOE “will honor its $464 million grant,” which will “unlock more than $1 billion in additional private investment and provide communities across the region with economic and infrastructure benefits.”
A DOE spokesperson told Canary Media in a July email that the DOE has conducted its review of GRIP projects based on a “number of criteria,” including whether it has “achieved the milestones set forth in the terms of the award,” whether it “remains technically and economically feasible,” and whether it “continues to effectuate the purpose of the program or the Department’s priorities.”
The spokesperson added that “none of the termination decisions were based on political considerations.” That statement is belied by court testimony reported by The New York Times last month, in which a DOE lawyer stated that none of the October grant terminations were “based on any programmatic, statutory, cost-reduction or performance-based factor,” and that all but one of them “had a recipient location and/or at least one place of performance in a state that awarded its electoral votes to Kamala Harris in the 2024 election and has two Democratic-caucusing senators.”
During a series of congressional hearings in April, Energy Secretary Chris Wright stated that the DOE’s review of more than 20,000 grants was almost complete, and that more than 80% of grantees had received notice that their awards could proceed as is or with modifications.
But an Alumni Network analysis of DOE data shared with Congress showed that the DOE’s review both failed to restore the vast majority of projects caught up in the “blue state” termination action in October and failed to address the hundreds of projects that have never been officially terminated but remain unable to secure funds.
The revelation of the DOE’s explicit targeting of blue states for grant termination spurred 39 Senate Democrats to sign a letter to Wright and Vought demanding the immediate restoration of funding for DOE projects terminated in October.
“Once an Administration begins punishing Americans for how they vote,” the senators wrote, “the threat extends far beyond these projects: no state, community, business, or worker can trust that the federal government will apply the law fairly.”
A correction was made on Aug. 12, 2026. The story initially stated that a DOE grant to the California Energy Commission was terminated. That grant appeared on a list of grants targeted for termination, but was not officially terminated, according to the CEC.
The startup, newly valued at $13 billion, is now manufacturing batteries in Texas. It offers an affordable way for homeowners to get backup power and it helps the grid too.
Home battery startup Base Power seems constitutionally incapable of standing still. After raising $1 billion last October, the Texas company has raised another $1 billion, and upped its valuation from $4 billion to $13 billion.
The latest investment, led by Ribbit, Addition, Valor Equity Partners, and JPMorganChase’s Strategic Investment Group, amounts to one of the largest validations so far for the theory that small-scale energy devices can play a role in meeting the nation’s ravenous demand for new power.
Households could easily spend more than $10,000 to buy their own batteries, but Base Power installs unusually powerful batteries at customers’ homes for an up-front fee ($95 to $695, depending on location) plus an ongoing electricity supply subscription. This model lets more homes access emergency backup power when the grid goes down, and cheaper power on normal days. In exchange, Base Power uses those energy storage systems to provide power to the grid when it’s most stressed — a service that makes money for the company.
Clean energy advocates have called for this kind of distributed energy model for years, saying that generating and storing power in homes and businesses can make more sense than relying on an increasingly expensive centralized grid, if only someone would compensate the systems properly. The market has been slow to heed their calls. But now AI companies are paying top dollar for energy wherever they can find it, and the idea of controlling thousands of dispatchable home batteries lights up investors like never before.
“There’s a real need on the grid for capacity in Illinois and Texas and frankly everywhere else in the U.S. now,” said Base Power co-founder and Chief Operating Officer Justin Lopas. “Distributed batteries are a way that we can add meaningful capacity to the grid.”
In less than three years of operating, Base Power has installed batteries at 17,000 homes, mostly in Texas but recently in Illinois as well. With the ability to provide more than 500 megawatt-hours of power, that aggregated fleet stores as much energy as one of the large utility-scale batteries you could find in the Texas countryside or the California desert. But those projects take years of development and permitting before they can enter construction, while Base Power installers add multiple batteries in a day.
The new funding will equip Base Power to expand its team and increase the rate of installs, Lopas said. But the company has also been working to speed deployments another way: by taking over its own supply chain.
Base Power has been installing batteries that were manufactured to its specifications by a “non-China” overseas supplier, Lopas said. Now, the company has multiple production lines up and running in the former Austin American-Statesman newspaper building in Austin, Texas. This means products can come off the line and go right on a truck for delivery, instead of getting shipped in from overseas.
Base Power’s engineers finessed their design to make life easier for the company’s in-house installers. Many home batteries are mounted on walls, but Base Power has decided to go a different route.
“Ours are installed on the ground, not the wall,” Lopas said. “That simplifies the install, and you don’t have to carry different screws for brick and stone and siding and all this other stuff.”
Base Power has a contract to begin sourcing domestic battery cells by the end of the year, and already buys all the data-processing “smart” components for the battery systems from the U.S., to improve cybersecurity. That also sets up the company to avoid bureaucratic snarls around electronics from China; the White House recently banned new foreign inverters on national security grounds.
The new Base Core model coming off the line in Austin also packs more of a punch in terms of energy. It can push 20 kilowatts of instantaneous power, and stores nearly 40 kilowatt-hours. That’s far beyond the conventional format popularized by the Tesla Powerwall, which discharges 5 kilowatts and stores 14 kilowatt-hours. Customers can stack more than one Base Core for even more storage.
“Our financial model is very aligned with our customers,” Lopas said. “They want as long a duration of backup as they can get, and we want to put as much energy as we can on the home.”
Now the company has a vast war chest to hire more installers, who will each install more energy capacity per visit. Different states are working on mechanisms to nudge AI hyperscalers to pay for distributed energy to meet some of their capacity needs. Those policies are in their infancy, but Base Power sees plenty of runway to grow using the current market rules in Texas and Illinois, Lopas said. The startup also works with utilities to set up home battery networks to solve grid problems, a model that could scale in the states that lack a Texas-style competitive power market.
The 1-GWh battery project in Ohio will help suppress power prices and reduce grid strain from a nearby data center hub. The region could use a lot more systems like it.
Just northeast of Columbus, Ohio, the leafy Main Street of New Albany gives way to lush green fields and agrarian ponds — but soon the countryside transitions into mile after mile of enormous white boxes that emit a low hum. This patch of former farmland has become one of the densest clusters of AI computing in the nation, recently joined by Intel, which is constructing a $28 billion computer-chip factory at the northern end of the industrial bloc.
All of this requires a tremendous amount of electricity, but the area falls within the multistate market managed by PJM Interconnection, which has consistently struggled to bring new power plants online even as demand booms. The resulting power price spike has drawn the ire of both Republican and Democratic governors, who are demanding that PJM and tech giants figure out how to stop data centers from driving up costs for everybody around them. No less than the White House is pushing AI companies to “build, bring, or buy new power supply.”
A huge battery that just began construction in the heart of the New Albany computing cluster could model a way to accomplish that task.
Developer Eolian announced on Wednesday that it’s broken ground on its Flint Grid battery project. The first phase is due online by June of 2027, and will be able to inject 200 megawatts for up to five hours straight into an electrical substation that serves the computing hub. With 1 gigawatt-hour of storage capacity, this battery won’t just be the biggest on the 13-state PJM market; it’ll be the biggest battery east of the Mississippi.
The system will help lower electricity prices by charging up when energy is cheap and abundant and dispatching that stored power onto the grid at times of peak demand — exactly what big batteries have been doing for years in places like California and Texas.
“There are things that have been in progress for a long time, designed to solve these very problems,” said Eolian CEO Aaron Zubaty, in response to the “snowballing narrative” that the grid can’t keep up with demand.
Batteries have set new installation records in the U.S. year after year, swiftly becoming the nation’s top pick for on-demand capacity and beating out new gas plant construction. But construction has clustered in the West, and developers have struggled to make inroads in the Midwest or the densely populated Eastern Seaboard. However, now that those areas face tremendous AI data center growth, they could use the instantaneous power that massive batteries provide.
Eolian can deliver that in New Albany because the firm got started a decade ago, taking calculated risks that seem to have paid off.
“This isn’t just some random 200 megawatts,” Zubaty said. “This is 200 megawatts at the epicenter of one of the largest industrial buildouts ever seen in our country, and by putting it at this spot, it will actually allow more stuff to get built.”
Zubaty didn’t originally have Ohio top of mind for his clean energy ambitions. By the early 2010s, northern Virginia led the nation in data center density, and Zubaty wanted to develop solar farms near those major energy consumers. But he ran into obstacles finding enough land. Solar development had to contend with northern Virginia’s horse farms and suburban subdivisions, and further west from Dulles airport, you hit the Appalachian Mountains.
“Where do the mountains end? A little bit east of Columbus,” Zubaty said.
Central Ohio was already growing in population and economic vitality, Zubaty noted, anchored by a skilled workforce and The Ohio State University. And it had a lot of open space that could accommodate new growth if the titans of the internet wanted to branch out from northern Virginia.
“We started doing land research, looking at where we could build solar in proximity to the Columbus metro area,” Zubaty recalled. “Lo and behold, we stumbled upon a couple obscurely named LLCs that were buying up a bunch of land at substations, and it was Amazon.”
Amazon Web Services opened its first data center outside New Albany in 2016. That kicked off a frenzy of tech companies buying the larger parcels of land nearby. One smaller tract — with an old house, lots of foliage, and a small pond — got left behind in the land race as data center companies bought all the property around it. The owners agreed to sell to Eolian, which considered the acreage well suited for a battery plant.
Today, that house is gone, and the once-peaceful parcel is fully surrounded by looming warehouses filled with servers. Crucially, it abuts a substation owned by utility AEP that receives power from a high-voltage transmission line and feeds it to a lower-voltage line that loops through the data center region. That potent grid backbone is what makes it possible for the area to host so much computing — and gives the battery a means of charging up.
After securing the land, Eolian got to work on permits, interconnection to the grid, and approval from the Ohio Power Siting Board. At the time, PJM’s power prices were quite low, offering little incentive for companies to build new power plants, even as “we were watching this massive amount of data center development unfold at a really epic scale,” Zubaty said.
By 2025, Eolian was ordering transformers and other long-lead-time equipment, even though it lacked a deal to sell power to one of the many corporate customers operating nearby. In December, Zubaty had sufficient confidence in the project to bid it into PJM’s capacity auction, which would award contracts for power delivered for one year starting on June 1, 2027. The auction hit the maximum possible price, signalling that long-simmering demand had unquestionably outstripped supply in PJM.
That win started a clock ticking to build out the site, because “there’s a massive financial penalty to bidding and then not showing up,” Zubaty said. (Eolian also plans to add a second phase of the same size by 2029.)
Typically, power plant investors want to see decades of revenue commitments in order to finance construction. PJM, though, only offers one year of certainty for that capacity payment.
Eolian took the risk of building in the hopes that further contracts will materialize.
Now, it looks increasingly likely that one of the many hyperscalers in the area could sign a deal that lets it take credit for the battery project’s contributions to PJM capacity. This could offset that customer’s need to buy power at sky-high market rates, but it also may become necessary to operate at all.
Tech giants are under tremendous political pressure to figure out how to meet their electricity needs without burdening the power system overall, especially in PJM territory. The White House’s Ratepayer Protection Pledge has pushed leading AI companies to say they will cover their own energy costs. New York state recently froze data center construction for a year, giving itself time to make rules to prevent the development from driving up electricity costs, and other liberal states are considering similar measures.
Should hyperscalers look for a well-situated battery to help meet their needs, they won’t find many. PJM can’t wind back the clock and ask for more developers to have applied for grid connection and secured land near future AI hubs eight years ago. Nor is there any indication PJM will soon refine its rules to allow the kind of flourishing of batteries seen in Texas’ competitive wholesale market.
But once one developer shows it’s both possible and valuable to build big batteries in the region, the sheer pressure to meet the AI moment may carry more batteries through the impasse.
A just-issued national security ban appears to exclude existing inverters for solar and battery projects — but future models could face restrictions, experts say.
Citing national security concerns, the Trump administration has banned the import and domestic use of new power inverters made outside the United States. The move could throw sand in the gears of gigawatts’ worth of planned solar, wind, and battery installations — projects that make up the vast majority of new electricity being built in the country.
On Tuesday, the Federal Communications Commission announced it had updated its “Covered List” to include “connected power inverters produced in foreign countries.” The list includes equipment and services considered to pose a threat to national security, meaning that these inverters “are generally prohibited from receiving FCC authorization to be imported, marketed, or sold in the U.S.,” the agency stated.
However, the ban currently applies only to future new models of inverters, not those already available in the market or being installed today — a distinction that could limit the immediate impact on the clean energy industry.
The FCC stated that its action was prompted by a “White House-convened Executive Branch interagency body with appropriate national security expertise,” which determined that foreign-made inverters, “regardless of the nationality of origin, “‘pose unacceptable risks to the national security of the United States or the safety and security of United States persons.’”
Inverters — devices that convert direct current electricity into alternating current suitable for transmission over power grids — are an irreplaceable component of utility-scale solar, battery, and wind power projects, home solar and battery systems, electric vehicles chargers, heat pumps, and other electricity systems.
The vast majority of inverters in use today are connected to communications networks, which puts them under FCC regulatory purview. And most inverters used in large-scale solar projects are built outside the U.S. — many of them in China, which has been the primary target of national security concerns.
The FCC’s new restrictions do come with that important caveat, though: They only “apply to new device models.” That qualification appears to exclude foreign inverter models that have previously won FCC approval.
The FCC also specified that the new restriction “does not impact a consumer’s continued use of devices they previously acquired,” or “prevent retailers from continuing to sell, import, or market relevant models approved previously through the FCC’s equipment authorization process.”
Those two statements have tempered some of the more drastic interpretations of the potential impact of the FCC’s announcement among energy industry market participants.
“In our world, investors are currently seeing this as kind of a non-event” due to this interpretation, John Miller, a managing director and energy transition policy analyst at investment bank TD Cowen, told Canary Media in a Wednesday morning email. “If either of those conditions were to change, this becomes a much bigger issue.”
This point was echoed by Julien Dumoulin-Smith, head of equity research for power, utilities, and clean energy at investment firm Jefferies, in a Wednesday morning statement. “[T]his has a minimal impact today. There seems latitude to continue to purchase existing inverter models on the market,” he wrote.
On the other hand, Dumoulin-Smith pointed out that any Trump administration steps to restrict new models of foreign-made inverters could create a “long, gradual shift in market share.”
Threats of the Trump administration targeting foreign inverters were first reported in late June by Reuters, which cited unnamed sources stating that a ban on Chinese-made inverters was in the works.
Last year, Reuters reported that technology experts investigating Chinese inverters had discovered communications devices that could be a security risk, citing anonymous sources. Later in 2025, Republicans in the House of Representatives wrote a letter to Commerce Secretary Howard Lutnick asking him to use the Commerce Department’s authority to “block future imports of Chinese equipment used in critical infrastructure nationwide.”
Chinese companies such as Sungrow and Chint Power Systems provide the majority of inverters for utility-scale clean energy and battery projects in the U.S., while U.S.-based Enphase Energy and Israel-based SolarEdge provide the majority of inverters for residential rooftop solar systems.
The FCC’s update targets any new inverters not made in the U.S., including those that U.S.-based companies produce in other countries. That could encompass inverters from other major providers to the solar market, such as Germany-based SMA Solar Technology and Austria-based Fronius International, as tracked by clean energy consultancy Wood Mackenzie.
If the FCC’s ban were to be expanded to include inverters currently being manufactured and sold for use in the U.S., the impact could be drastic. The U.S. built 50 gigawatts of new wind, solar, and battery capacity in 2025, more than any year prior, making up roughly 92% of new generating capacity. And the U.S. Energy Information Administration forecasts these trends will continue in 2026, with solar set to provide 51% of the new utility-scale electricity capacity, batteries 28%, and wind 14%.
In the immediate future, projects likely won’t have to abandon the inverters they’ve already purchased or plan to install, said Joe Shangraw, a solar research analyst at Wood Mackenzie. But he also cautioned that, as with any other industry, “eventually, currently approved products will become obsolete.”
That means inverter manufacturers will ultimately have to bring new products to market and submit them for FCC approval, at which time they’ll have to contend with the agency’s new rules. At that point, any inverters made outside the U.S. will be barred from sale and use unless they undergo a distinct conditional approval or waiver process, he said.
Shangraw also noted that the need to bring new products to the market could be accelerated if the federal government sets new requirements on cybersecurity, grid functionality, or other inverter capabilities.
“If that would require a significant hardware or software update, that would be something where you’d have to request some permissive change from the FCC, or ask for a totally new FCC ID” designating a new model of device for the agency’s review, he said. “So it’s certainly relevant and impactful — probably not in the next couple of months but in the next year or so.”
This growing uncertainty over the federal government’s classification of foreign-made inverters could increase industry interest in securing domestic inverter supplies, he said. On that front, “the storage space looks a lot healthier,” with companies such as U.S.-based EPC Power and Tesla operating significant domestic manufacturing capacity, and others such as Spain-based Power Electronics scaling up U.S. manufacturing.
Residential solar inverters are “in a good place,” Shangraw said, with SolarEdge, Enphase, and Tesla providing about 80% of the U.S. market needs. But the domestic manufacturing capacity for solar inverters for utility-, commercial-, and industrial-scale projects is less clear, he said, given that Chinese inverter makers hold about 60% of U.S. market share in that sector.
Large-scale solar developers could hope to earn waivers from the FCC on foreign-made inverters from non-Chinese companies such as SMA and Power Electronics, he noted. They could also anticipate expanded domestic manufacturing from U.S.-based Nextpower, which is acquiring the inverter and power conversion business of Spain-based Zigor and its U.S. subsidiary Apex Power; or from GE Vernova, which has opened an inverter factory in Pittsburgh and could expand capacity there, he said.
“The main thing is, we don’t know how impactful this is until we learn a bit more about the timeline for when these actual changes to the requirements” for existing inverters might occur that would “force companies to release new products,” he said. “I’d say if this was a hard deadline, and if there were no new imports allowed, we’d be in trouble.”
As tech firms look to build their own gas generators, a new report reveals that likely won’t be enough to avoid a hefty power shortfall in the coming years.
It’s no secret that data centers are slated to bring stunning levels of new power demand to the grid in the coming years.
Report after report has tried to put a number on just how much electricity these facilities will actually use, and BloombergNEF joined the chorus this week. Its report projects that U.S. data centers will consume 20% of the country’s power in 2035, up from 5.9% today.
In all, data centers will consume as much as 194 gigawatts of power in 2035, the report estimates. That’s nearly double the amount BloombergNEF forecast back in December, and it’s more than the firm’s analysts expect the power grid to be able to accommodate.
So what’s a data center developer to do? Well, if you’re Elon Musk, you buy a company that’s operating tons of mobile gas and diesel generators that can provide your data centers with power that’s not connected to the grid.
Federal records unearthed last week by Electrek show that in May, the xAI founder bought APR Energy, a Florida company that runs more than a gigawatt of these portable fossil-fueled turbines. These generators can be installed in just a few days, as opposed to a traditional gas plant, which may take years to build.
This isn’t a new avenue for xAI. Since last August, the company has been using diesel generators propped on truck beds to power its Colossus 2 data center project outside Memphis. A lawsuit from the NAACP and its allies alleges the turbines are running without required permits and releasing tons of pollution that harms nearby, majority-Black communities.
Other data center projects are turning to gas, too, or hope to do so in the future. In Ohio, Meta uses modular gas turbines to power servers that, as of June, are stacked up in temporary tents. Some developers want to construct more permanent fossil-fuel solutions: Google, for example, has proposed building its very own utility-scale gas plant alongside a data center in Nebraska.
But experts are casting doubt on just how much off-grid gas power that tech firms will actually be able to build. Among the challenges: Gas turbines are in short supply, and so is the workforce needed to maintain them, as the clean energy industry veteran Jigar Shah noted in an episode of Latitude Media’s Open Circuit podcast.
BloombergNEF projects that even if the grid can accommodate 7 GW of new data center demand each year — the all-time record — and if many hyperscalers install their own gas turbines, the sector will still face a 19-GW shortfall by 2035. For perspective, a standard large-scale nuclear power plant produces about 1 GW of power, and it’s going to be a gigantic undertaking to fulfill the Trump administration’s goal to build 10 of those in the coming years.
Of course, no one knows for sure just how much power data centers will actually end up needing. Data centers could get way more efficient as their processors improve. The AI boom could peter out. Or maybe, just maybe, we’ll unlock the miracle clean power source that is commercial nuclear fusion and use it to meet all our massive electricity needs — but I wouldn’t hold my breath.
Trump’s ill-timed efficiency rollbacks
America’s war with Iran isn’t letting up, and neither is the energy shortage the conflict has brought upon much of the world.
Energy-efficiency measures could provide one salve to the crisis, but in the U.S., they’re getting ever harder to access. Over the past few months, the Trump administration has scaled back a bevy of programs that make home weatherization and other utility-bill-cutting improvements more affordable. Incentives that helped people trade fossil fuel appliances for electric alternatives are dead, for one.
Even free advice hasn’t survived. The Department of Energy’s website used to be full of tips for lowering your power bills, like how to find and plug drafts in your home. But as Grist reports, those guides disappeared by early July — just in time for a grid-straining heat wave to set in across the country.
State legislatures go easier on renewables
Last year, state legislatures had clean energy in their crosshairs. Lawmakers throughout the country introduced more than 300 bills related to renewable energy siting in 2025, and nearly half of them would have made it harder to build solar, wind, and battery storage projects.
Luckily for renewables, just 10 of those restrictive measures actually became law. But this year is shaping up to be brighter, according to the Siting Solutions Project. While lawmakers introduced 86 measures to rein in solar, wind, and battery permitting in 2026, just one has become law. That record is likely to stick, as most state legislative sessions have already concluded for the year.
Meanwhile, a handful of pro-renewables permitting and siting policies made it into law this year in both Democratic- and Republican-run state legislatures, reports Canary Media’s Jeff St. John. That includes measures that aim to curb local bans on renewables, speed review processes, and set best practices for cleaning up retired solar and battery projects.
Where to buy balcony solar: A few companies are finding their footing in America’s emerging balcony solar market, with some German firms expanding sales to the States, and U.S. solar manufacturers potentially getting involved soon. (Canary Media)
Iran war strain continues: The world has found ways to adapt without oil from the Strait of Hormuz, but experts predict that fallout from a continued closure could be more severe as countries’ emergency stockpiles near depletion. (Grist)
International nuclear deal: The Trump administration signs a deal with Saudi Arabia that paves the way for nuclear power construction in the country — an arrangement that’s likely to benefit U.S. nuclear developer Westinghouse. (Washington Post, New York Times)
Pumping up iron: Mesabi Metallics sees green steel as a path to revitalize Minnesota’s Iron Range, and it’s rolling out a $2.5 billion plan to mine and produce iron that’s key to lower-emissions steelmaking. (Canary Media)
Coal’s climbing costs: Pushback to the Trump administration’s coal-plant stay-open orders grows, with Wisconsin’s governor saying the costs to utility customers could hit $117 million in coming years, and a Colorado analysis estimating costs over $87 million. (Wisconsin Public Radio, Colorado Sun)
Wind allies unite: A coalition of 18 states and Washington, D.C., looks to join a wind industry lawsuit fighting the Department of Defense’s blockade on onshore wind permitting. (Canary Media)
Digging deeper: Geothermal veteran Ormat Technologies is venturing into the industry’s next generation with projects that can unlock energy where natural geothermal resources don’t exist. (Canary Media)
Getting data centers to pay for new generation and batteries could be the best hope for the nation’s biggest power market to finally get a handle on costs.
With the conclusion of its latest capacity auction, PJM Interconnection has once again shown that its process for securing new energy is unable to keep up with the wave of electricity demand from data centers.
But PJM, the grid operator for the country’s biggest energy market, is poised to adopt a new process that could help fix these problems: by pushing data centers to pay directly for the new clean energy, batteries, and fossil-fueled power plants needed to meet their huge electricity demand.
Late last month, PJM stakeholders achieved a rare level of consensus in voting to approve the plan for a new auction, called a reliability backstop procurement.
The measure, which still needs final approval from both PJM and the federal government, represents the grid operator’s most significant step to repair an auction process that has left consumers paying more money for a less reliable grid. PJM’s board of directors is expected to submit the proposal to federal regulators in the coming weeks.
The results of PJM’s Tuesday capacity auction underscore how critical it is for the grid operator to find a solution.
PJM’s capacity auctions, held once or twice each year, are the key process through which it ensures there’s enough capacity to keep its grid up and running during summer heat waves and winter cold snaps. It’s a high-stakes task: 67 million people from Virginia to Illinois depend on PJM for electricity.
For the third time in a row, the capacity auction hit the market’s price cap, in this case, $325 per megawatt-day. Similar caps have been in place since last year, after state governors demanded a limit to the massive cost increases being pushed onto utility customers across the PJM region.
These latest capacity costs reached $16.4 billion, matching the record set last December, and are more than eight times as much as PJM has paid for capacity in prior years. Customers in some PJM states — including Illinois, New Jersey, and Pennsylvania — are already seeing their bills rise by more than 10%, in part because of these soaring costs.
And yet, these maxed-out prices are still not high enough to get energy developers and utilities to build the power plants PJM needs to hit its reliability targets. This week’s auction fell short of PJM’s reliability requirement by over 6.8 gigawatts — the second time in a row that sky-high prices have failed to bring sufficient capacity resources into play.
The upshot is that customers in PJM Interconnection are paying some of the highest rates in the U.S. for grid reliability — even as the grid operator says the system isn’t reliable.
At the root of the problem is an explosion of demand from data centers that utilities and project developers can’t keep up with.
The grid operator forecasts that 30 to 34 gigawatts of data centers will be online in states across its region by the early 2030s. Utilities and developers would struggle to meet that pace under favorable conditions, but PJM’s infamously sluggish interconnection process makes it an impossible task.
While power demand has soared, the capacity being brought online in PJM has stagnated.
Of the 138.3 gigawatts of resources secured in this week’s auction, only 525 megawatts came from new capacity. All told, just under 4 gigawatts of newly built and “uprated” capacity from existing projects have been included in the capacity auctions since 2024, well below the roughly 20 gigawatts of new capacity added in the five prior auctions.
“We’ve got two problems,” said Julia Hoos, who leads coverage of Eastern U.S. power markets for Aurora Energy Research. “One, new capacity is just more expensive than we’re willing to pay for; and two, we haven’t resolved the physical barriers to build. Now, we’re paying for both issues.”
And those problems aren’t going away. Monitoring Analytics, PJM’s independent market monitor, has cited forecasted growth in data center power demand as being responsible for more than $29 billion in additional capacity costs to customers in PJM since 2024. In a May report, the monitor warned that these costs will “continue to grow until the issues associated with the addition of large data center loads are addressed.”
It hasn’t been easy to land on a path forward.
Environmental groups, consumer advocates, and state politicians have been haggling with data center trade groups, utilities, and power plant owners for more than a year over how to manage electricity costs related to data centers.
Some argue that new data centers should be forced to drop offline during grid emergencies, to avoid burdening all other customers with the cost of building power plants to ensure service at those times. Others say data centers should be required to pay directly for the capacity resources needed to mitigate their burdens on overstressed grids.
The plan approved by PJM stakeholders in late June, which was put forward by utilities and the trade group Data Center Coalition, would enable that latter option.
Unlike PJM’s standard capacity auctions, which are aimed at meeting the needs of all the utilities and customers served by its grid, this reliability backstop procurement, or RBP, is meant to be a “one-time process to purchase new supply resources to serve new data centers and other large loads,” PJM explained in announcing the outcome of its stakeholder process.
The proposed backstop procurement auction would come with a price cap of $555 per megawatt-day, much higher than the limit now set on PJM’s broader capacity market. In fact, the amount is pretty close to Aurora Energy Research’s calculation that about $500 to $600 per megawatt-day is what’s needed to finance new capacity resources trying to get built and interconnected to the grid, Hoos said.
This new auction would also structure deals between data centers and project developers under 15-year contracts, which “makes it cheaper to build, because developers have more security,” she said. “In the short term, it may be the only way to build new capacity, because generators need certainty.”
PJM has also showed some signs of life in moving projects through its snarled interconnection queue.
This year, the grid operator finally cleared roughly 53 gigawatts of solar, batteries, wind, and fossil gas power projects to connect to its system. If the RBP is approved by the Federal Energy Regulatory Commission in its current form, it could be “potentially a way to funnel a lot of money to projects that are already in the works,” said Tom Rutigliano, senior advocate for climate and energy at the Natural Resources Defense Council.
But that’s not the only way for new data centers to pay for the resources they need to come online, Rutigliano and Hoos noted. An even bigger channel could emerge in the form of bilateral contracts — agreements between individual data centers and developers of generation, battery storage, and demand-side resources like virtual power plants.
Such bilateral contracting has always been an option for large power customers, Hoos noted. In fact, major corporations have been signing power-purchase agreements with solar and wind projects for more than a decade. But those contracts have been focused on securing clean energy, and not so much on projects that can provide capacity during hours when the grid is under the greatest stress.
That’s a more complicated type of deal to structure, and tech giants like Amazon, Google, Meta, and Microsoft are only in the early stages of combining clean energy, batteries, generators, and demand-side resources or flexible computing that can meet PJM’s capacity needs.
But with states served by PJM demanding that large loads bring their own capacity, these kinds of deals are increasingly seen as necessary to get new data centers built. As part of the same effort, PJM last month also started work on facilitating “bilateral, long-term agreements between large load customers and generation providers” as a way to help these processes along, it also announced.
In fact, the RBP could become a last-resort choice for large loads that can’t strike their own deals, Hoos said. “There’s a lot of value to these bilateral contracting models that move that risk to investors and to the large loads,” she said — not to utility customers at large.
What remains uncertain is whether the RBP and these bilateral deals can enable data centers and new grid resources to come online “without raising rates on everyone else,” Rutigliano said.
PJM was meant to tackle the cost considerations by adopting a “connect and manage” plan, a structure that would require data centers to either bring their own capacity or face being cut off from grid power during emergencies. But PJM stakeholders failed to approve any of the 11 connect-and-manage proposals on hand.
So PJM proposed that state regulators take the lead in setting the rules for how utilities bundle up all the capacity needs of the large loads seeking to come online and submit them to the RBP, Rutigliano said.
This creates a risk that utilities could claim to be representing large loads in future auctions without securing durable commitments from those customers to actually pay for the capacity they commit to buying. If that happens, utility customers would be left holding the bag.
All this is unfolding on a compressed timeframe. Under pressure from the Federal Energy Regulatory Commission and state governors, PJM has agreed to hold its backstop procurement auction in September. That’s not a lot of time to prepare — but Rutigliano thinks PJM needs to work closely with states to ensure that regular customers don’t end up paying for resources that utilities secure for data centers.
“The stakeholder-approved version is that only utilities that affirmatively step up and say ‘we want more capacity’ get put in as buyers,” he said. “States have to make sure that doesn’t get passed on to ordinary ratepayers. They have to make damn sure there’s a data center that pays for it, or [utility] shareholders pay for it.”
The subscription-based approach aims to make it easier and more affordable to get a backup battery in your home. And it might be catching on.
Haven Energy is the newest company offering home battery service in Massachusetts for a low monthly payment, a model supporters say could accelerate adoption of residential storage.
Starting in four counties in the southeastern part of the state, the company will provide customers with a 15-kilowatt-hour home battery, installed and ready to go, starting at $29 a month, with a 10-year contract. These terms make obtaining a battery significantly more affordable in a market where a home system can easily top $15,000.
“Think of Haven as a low-cost battery backup subscription,” said co-founder and CEO Vinnie Campo.
Haven joins Tesla, which last month launched its own lower-cost monthly payment offering in both Massachusetts and Connecticut, a discounted version of its existing battery-leasing program. The Tesla option saves Massachusetts customers about $30 a month, which could shave nearly a third off the price of a standard monthly lease.
How does the pricing model work? Massachusetts utilities operate a demand-response program called ConnectedSolutions, which pays battery owners to discharge energy to the grid during times of peak demand, like those hot summer days when everyone turns on their air conditioners at once. With lots of batteries working in concert, these actions can reduce the need for the utilities to buy pricey, dirty electricity from peaker power plants. In the long term, the strategy can help delay costly grid upgrades paid for by consumers.
A typical battery could earn $1,375 per year participating in ConnectedSolutions. A new expansion of the program, ConnectedSolutions+, pays even more to battery owners in certain geographical areas where the grid is particularly congested, making the availability of local stored power even more valuable.
Haven and Tesla both retain ownership of the batteries in their programs, and thus earn these and any other available incentives. This revenue stream allows the companies to keep the monthly price low for customers. The model has the added advantage of making it easier for homeowners to get started with battery storage, eliminating the complication of sorting out and applying for incentives, Campo said.
“We take a complicated stack of rebates and incentives, and dramatically simplify that so it’s an easy-to-understand product,” he said.
Customers with solar panels will be able to save even more by charging up their batteries during sunny but low-demand times of day to use in the darker hours, rather than drawing from the grid.
When ConnectedSolutions calls on participating batteries — generally 30 to 60 times a year, always in the summer — Haven will leave at least 20% of the stored power available for its customers. If a major storm that could trigger an outage seems likely, the company puts its batteries in “safety mode,” preventing them from discharging to the grid.
“We are always prioritizing backup power for the customer,” Campo said.
The monthly payment model is not a completely new approach to driving battery adoption. Haven debuted in 2023, in California (a state that also has a robust incentive program for residential batteries), and evolved its business model in 2025 when the One Big Beautiful Bill Act changed the way the federal tax credits work. Vermont’s major utility, Green Mountain Power, has offered leases on two-battery systems for $55 a month since 2017. Today, some 4,600 households are enrolled, and the program continues to grow.
Battery boosters hope the trend continues. As of earlier this year, 26 states and Puerto Rico had programs paying residential battery owners to share their power with the grid, and more will join the list soon, said Todd Olinsky-Paul, senior project director for the nonprofit Clean Energy Group. These initiatives could pave the way for more monthly payment models that will make getting a battery as easy as signing up for any other home service.
“It’s like subscribing to cable or garbage pickup,” Olinsky-Paul said. “I think it’s going to be quite popular.”
In a first, the state could speed up data centers’ grid connection if they bankroll energy-saving residential tech like heat pumps and batteries.
New Jersey is offering data centers an unorthodox way to get the power they need: by bankrolling home energy upgrades.
Last week, Gov. Mikie Sherrill (D) signed a bill that will create a first-of-its-kind program to incentivize data centers to secure clean capacity by reducing demand elsewhere on the grid. Data centers will be able to pay for households to replace their energy-hogging electric-resistance space and water heaters with much more efficient electric heat pump appliances — or to install rooftop solar and batteries.
The scheme could lower electricity bills for potentially millions of households statewide by hundreds to thousands of dollars annually. In return, the data centers would get priority in the interconnection queue.
“New Jersey just set a national precedent,” said Ari Matusiak, CEO and co-founder of nonprofit Rewiring America, who served on Sherrill’s transition team. The law, called the Data Center Fair Share Act, “is a blueprint for how policymakers can start to think about households as energy infrastructure.”
Nationwide, utilities propose to spend at least $1.4 trillion on capital expenditures through 2030, according to consumer advocacy nonprofit PowerLines. “A meaningful percentage of that could be directed to households,” Matusiak said.
Rewiring America first championed the approach last September, when it released a report finding that installing heat pumps, solar, and batteries in homes could offset more than 93 gigawatts of anticipated AI-driven demand nationwide. The nonprofit provided input on New Jersey’s bill, but it “very much had its own momentum,” according to spokesperson Alex Amend.
Using what’s known as “voluntary demand-reduction trade programs” established at the utility-level, data centers will be able to hire companies that can aggregate households and other utility customers into a virtual power plant. The utility would then likely work with the aggregator to verify the resulting capacity will be there when the data center is built, according to Amend.
Power-hungry data centers have been pushing up electricity prices in the PJM Interconnection grid region, which includes New Jersey as well as a large swath of the Midwest and mid-Atlantic. And utility customers have been left footing the bill.
New Jersey’s law aims to put the kibosh on that. In addition to the household program, the measure will create a new rate class for data centers, following the lead of Minnesota, Oregon, and Virginia. The move is meant to ensure data centers pay for their own energy use and associated grid infrastructure.
Other states are looking to push data center dollars into home energy upgrades. California, Colorado, Illinois, Pennsylvania, “and likely many others” are considering legislation, said McKenna Beck, policy analyst at the nonprofit Natural Resources Defense Council, which helped create the New Jersey bill’s framework. On Tuesday, New York joined the list: Gov. Kathy Hochul signed an executive order that halts data center development for up to a year and directs regulators to consider requiring data centers to fund distributed energy resources and battery storage.
Hyperscalers are staying mum on New Jersey’s initiative. Microsoft declined to comment, Google did not respond in time, and Amazon told Canary Media that it had no stance.
Still, Big Tech companies are increasingly keen to leverage households as energy assets.
Last month, Google announced a pioneering agreement with the virtual power plant provider Voltus for up to 100 megawatts. Also in June, Tesla, Sunrun, and Renew Home broadcast that they would provide a whopping 16 gigawatts of power across data center hot spots in the U.S. using distributed energy resources. The power will be “ready in months, not years,” according to their website.
In New Jersey, Rewiring America estimates that of about 2 million single-family homes, roughly 85,000 have electric-resistance heating systems and 422,000 have electric-resistance water heaters. “But all households could benefit from home batteries and, in most cases, rooftop solar as well,” Amend said. “So the potential is enormous.”
New Jersey’s public utilities regulator has one year to flesh out the standards of the state initiative for utilities. Utilities then have 180 days to submit proposals for their individual programs.
Enrolled households could start getting data center–funded heat pumps, solar panels, and batteries as soon as mid-2028, Beck noted.
“These resources will directly lower bills for households and communities in which the data centers are built,” Beck said. “It’s incredibly exciting.”
A new program from startup Every Electric and utility Con Edison lets New Yorkers power their window ACs with home batteries to take stress off the grid.
Earlier this month, as a historic heat dome smothered the U.S. Midwest and Atlantic Coast, New York City Mayor Zohran Mamdani asked residents to set their air conditioners to 78 degrees Fahrenheit to protect the city’s severely strained grid. “Let’s ease demand — and get through the heat — together,” he posted on X ahead of the sweltering July 4 weekend.
Previous NYC leaders and elected officials nationwide have given the same advice ahead of extreme weather events. But Mamdani’s suggestion that everyone pitch in sparked backlash from conservative figures and prompted the Trump administration to remove its thermostat-level recommendations from the Department of Energy’s website.
All the while, in apartments across New York City, hundreds of residents were supporting the electric grid without needing to adjust their AC at all.
The local startup Every Electric launched a novel pilot program earlier this year with the utility Con Edison that allows participants to plug their window air-conditioning units into a battery pack, which itself is plugged into the wall. The Wi-Fi–connected batteries draw electricity from the grid when conditions are calm, then power ACs with the stored-up energy when demand on the grid is highest.
“The air conditioner can stay on, but we can still reduce load on the grid,” Andrew Wang, the company’s CEO, told me a few days after the heat wave and a subsequent major storm passed over the metropolis.
“And the big thing is, you don’t impact someone’s preferred settings,” he said. In an outage, the batteries can power a typical window unit for about four hours, he added.
Millions of New Yorkers live in older apartment buildings without central air conditioning. Many residents instead use two or more window AC units to keep their homes cool. On blistering, humid days — like July 2, when temperatures hit 104℉ — these appliances can represent about 20% of the entire city’s electricity demand, Wang said. On a household level, it’s more like 75% of total peak energy use.
Every Electric, which ran a small internal pilot last year, has so far delivered over 1,000 batteries to roughly 600 apartments, including mine. It’s free to participate, though I had to pay a $50 refundable deposit for the power bank, which is now shoved against the wall between the window and my bed. (Every Electric’s lithium-iron phosphate devices are different from the beat-up lithium-ion batteries linked to e-bike fires in my Brooklyn neighborhood and citywide.)
Wang said that heading into the heat wave, New York’s grid operator forecasted a 45% jump in NYC-wide peak demand for July 2. The window ACs in Every Electric’s program used 130% more electricity at their peak that day than they do in a typical week. Yet the company’s batteries met much of that demand, mitigating a source of grid stress and allowing renters to keep cool, even as Con Edison reduced voltages in certain areas to prevent widespread outages.
Collectively, Every Electric’s battery fleet can provide about 2.5 megawatt-hours of distributed energy storage. That’s a teeny sliver of the total power draw from window ACs. But experts say that such programs, when scaled, can play a crucial role in boosting grid reliability, reducing utility costs — and making the overall system more resilient to climate change.
On brutally hot days, utilities often fire up expensive, old fossil-fuel-burning peaker plants to meet the extra demand. Then there are the added maintenance costs and infrastructure upgrades. In May, Con Edison said it was investing a record $3.9 billion to lay more cables and build new transformers and substations to maintain reliable service “as extreme heat becomes more frequent and severe.”
“Distributed energy storage is a resource that [utilities] can leverage to avoid these peak demand spikes, and there’s a clear benefit for them, in terms of deferring their capacity investments,” said Bryan Bollinger, a professor of marketing and economic policy at the Tuck School of Business at Dartmouth, who studies how consumers make energy decisions.
A growing number of states, led by California, are increasingly adopting programs that call upon networks of customer-owned energy devices — like Tesla Powerwalls charged by rooftop solar panels — to support the grid when needed. But these initiatives, also called virtual power plants, primarily serve homeowners who are able to outfit their homes with clean technologies.
Every Electric’s renter-friendly approach “targets a different population completely,” Bollinger said. “You’re getting a bunch of consumers who also want to feel like they’re doing their part, but who don’t have the ability to do things like install solar panels.”
The company’s program also skirts the challenges facing large-scale battery storage systems in New York City. Big batteries can provide even greater relief to the grid, but local developers are ensnared in a regulatory battle with Con Edison related to the cost and effort of connecting to the system. Every Electric’s microwave-sized batteries face no such issues: As the utility sees it, the power bank in my bedroom is no different from a computer or TV.
Participants will be rewarded for our goodwill to the grid, with a payment that reflects each household’s peak summer monthly utility bill, up to $150 per power bank pairing.
The money comes from Con Edison’s Smart Usage Rewards program, under which the utility pays its customers to actively reduce energy use during specific blocks of time, in specific neighborhoods, on the hottest days of the year. Every Electric is enrolled as an “aggregator” that virtually manages all the power banks in its network. Wang’s team distributes a portion of the rewards it receives to its own participants, while keeping the rest to cover its costs and expand the program.
The ability to earn money while staying cool has an obvious appeal: The owners of some 10,000 window ACs units have requested batteries. Every Electric said it’s working to fulfill as many of those orders as possible over the summer.
Con Edison, which serves 3.7 million customers, said over 50,000 electricity users representing 500 megawatts in capacity are enrolled in the utility’s demand-response initiatives. During the past heat wave, the company called on customers to curb energy use 27 times across its networks in NYC and neighboring Westchester County.
A spokesperson said Con Edison doesn’t yet have specific data on how Every Electric’s pilot and other programs performed during the record-breaking heat. But in general, such efforts, combined with infrastructure investments and technological upgrades, have helped limit strain on the grid when it’s needed the most.
Beyond the Con Edison program, Wang declined to get specific about Every Electric’s financials, though he said the six-person startup is supported by a blend of sources. That includes private investors, debt financing from social-impact funds, and grants from the New York State Research and Development Authority.
“We’re excited by how scalable this can be,” Wang said, adding that the utility and state regulators “are telling everyone to look under every rock to find ways to make the grid run a little bit cheaper and more reliable.”
Bollinger, who until recently was a New York City renter himself, said he hopes that programs like Every Electric’s can catch on nationwide — because they can both bolster the grid and benefit more consumers. “It provides access to this kind of technology to non-homeowners as well, which we just haven’t seen with a lot of renewable energy technologies,” he said.
.svg)
