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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.
Sodium-ion batteries promise cheaper, more durable energy storage. Peak Energy seeks to kick-start the next-gen battery market by building the first big U.S. plant.
Startup Peak Energy launched in 2023 with a promise to bring the up-and-coming sodium-ion battery chemistry to American shores. Now, it’s building a gigafactory in Sacramento, California, that will be the country’s first to produce sodium-ion battery storage plants for the grid.
If Peak Energy succeeds in its broader mission, it will introduce a new generation of batteries better suited for grid storage than the dominant lithium-ion chemistries, which are effectively hand-me-downs from electric vehicles. These sodium-ion batteries can run safely at a broad range of temperatures, company leaders say, meaning they can operate more cheaply and durably than the lithium-ion phosphate (LFP) cells that have become the go-to for stationary storage.
“We’ve gone from proving the technology out and having really great interest to having contracted business with customers that we have to go deliver on,” said Peak’s CEO and co-founder Landon Mossburg. Chinese battery companies have begun scaling sodium-ion production in recent years, but the technology hasn’t broken into the Western power sector yet. Peak is at the forefront of startups trying to make that happen.
Peak assembled a cohort of interested developers to observe the design and piloting of its storage technology, which it installed at a Colorado testing facility last year. Several power producers signed up for small pilot installations this year, with much bigger orders teed up for 2027. So far, the company has worked with manufacturers in China to supply cells to its specifications and then assembled them into containers at its existing facility in Burlingame, California. That site can produce only 100 megawatt-hours per year — roughly 32 units at 3.1 megawatt-hours each — as a function of its size and reliance on some manual work rather than full automation.
That output won’t suffice in an era when a single battery project may need several times the Burlingame site’s annual production. The Sacramento factory will produce 40 times more, 4 gigawatt-hours per year, when it starts its highly automated production, planned for the first quarter of 2027. Once assembled, the 100,000-pound containers can slip right onto the highway for shipment to customers.
It’s a quick turnaround as far as factory buildouts go, made possible because Peak found a newly built shell to lease in an industrial park near the Sacramento airport, said Mossburg. The site already had power supply from the Sacramento Municipal Utility District, so Peak can drop in its manufacturing equipment with only minor upgrades to the structure and electrical service, he added. It also helps that the factory won’t be doing the highly technical cell fabrication, which takes longer to install.
Peak chose Sacramento after a competitive search around the country, and ended up bucking the conventional wisdom that you can’t build things in California anymore. Mossburg said he wanted to prioritize access to talent, rather than chase the richest state and local incentives or the lowest cost of labor or energy. Operating in California involves spending more in taxes and electricity costs than, say, in Texas, but Sacramento is accessible to the Bay Area and all the electrical engineering expertise of Silicon Valley and the Tesla diaspora. It’s also close to the Burlingame site where Peak has built its first enclosures.
Peak also won $10.5 million in tax credits from the California Competes program, which are tied to hiring milestones, Mossburg said.
Down the road, Peak leadership hopes to find onshore sources for its battery cells, and formed a partnership in June with GM to co-develop that product with the automaker’s Michigan battery labs.
All told, Peak’s strategy could allow for a relatively low-cost and rapid path to large-scale manufacturing. That would be a welcome contrast to the billion-dollar factory expansion pursued by Swedish startup Northvolt, which tried to forge a European battery empire before collapsing into bankruptcy. (Mossburg worked there for a time as president for North America.) But Peak still needs to prove there’s a market for a chemistry that has never been widely deployed in the U.S. grid storage market, which has been notoriously unwelcoming to anything that isn’t lithium-ion.
Peak’s chief strategy officer, Geoff Brown, got in early on the current LFP trend about a decade ago, when he was running pioneering grid-battery firm Powin Energy. His company scoured the Chinese market for the best cells to put into grid storage enclosures, and ultimately picked a form factor that had been designed for electric buses, he recalled. At that point, sodium-ion cells hadn’t made the jump to mass production.
Unlike the chemistries that ruled the grid storage market thus far, sodium-ion was “the first battery really purposely designed” for stationary storage, Brown said.
“You sacrifice some energy density for massive improvements in safety but also very significant economic benefits,” he noted.
A vast global factory base now produces LFP cells, but sodium-ion is already within striking distance of the per-cell manufacturing cost given its cheaper bill of materials, Mossburg said. Peak is pricing its enclosures to match Tesla’s LFP-fueled Megapack, but argues that they cost less on a lifetime basis because the cells are so durable and don’t need energy-sucking temperature-control and fire-suppression equipment.
Still, scale matters, and the Sacramento site is a necessary step for taking on the U.S. storage market with this new battery.
Last week’s high temperatures pushed the U.S. grid to its limits, and showcased how new wind and solar additions are essential to keeping the lights on.
Last week brought soaring temperatures to much of the U.S., forcing Americans to switch on their air conditioners — or, in many cases, flex their heat pumps’ cooling capabilities. And to cope with it all, the U.S. power grid delivered more electricity than ever — a feat that wouldn’t have been possible without clean energy’s massive growth over the past few years.
Temperatures in the triple digits prompted grid operators across the U.S. to prepare for potential emergencies. PJM Interconnection, which covers parts of the Midwest and East Coast, was granted federal authorization to direct data centers and other large power users to tap diesel generators and battery backup systems as a “last resort” to prevent power shutoffs. But the grid region didn’t end up needing those emergency resources, even as its power demand reached its highest level on record.
Texas, meanwhile, set a record for peak demand in any July — 83 gigawatts on the evening of July 6. Solar power, which Texas has recently added in spades, covered more than 30% of that demand, Texas energy expert Doug Lewin noted. Solar also helped Texas’ grid operator avoid the need to push customers to conserve power.
In New England, it was wind power that proved to be a hero as temperatures soared. The region burned less oil this time around than it did during a similar heat wave last year, per Grid Status, thanks in large part to offshore wind farms that have recently come online. The New England Clean Energy Connect power line, which started delivering electricity earlier this year, also brought in tons of hydropower from Canada.
Wind similarly played a strong role in keeping the lights on in the Southwest Power Pool, which spans the central U.S. from North Dakota down to northern Texas.
New York City’s sparkling new transmission line, which was supposed to bolster the city’s grid during heat waves like this one, was unfortunately a letdown. The Champlain Hudson Power Express, or CHPE (pronounced “chippy”), has been bringing clean hydropower from Canada into the city for the last month, but an issue in Quebec forced the line to shut down on July Fourth. The heat wave was luckily on its last legs by that time, and CHPE isn’t essential to New York grid operations just yet. But it’s set to become a vital power source as aging natural gas plants begin to retire.
Aside from a few short-lived outages scattered across the eastern half of the U.S., the grid weathered its first test of the summer pretty darn well. Still, with climate change making summer heat more extreme, and with more and more data centers and other large power users coming online, we’re far from out of the woods yet.
Hawaiʻi is retreating from its clean energy ambitions
Back in 2015, Hawaiʻi set the first statewide clean electricity goal in the country, aiming for a system run completely on renewable electricity by 2045. But as that deadline creeps closer, the state is considering retreating toward fossil fuels, reports Canary Media’s Julian Spector in partnership with Savannah Harriman-Pote of Hawaiʻi Public Radio.
As it stands, Hawaiʻi relies heavily on imported oil to generate electricity, and its residents pay the highest power prices in the nation as a result. But the state’s ambitious plans to build out tons of solar power and battery storage to replace its oil imports have been slowed down by the COVID-19 pandemic, the war in Ukraine, and a catastrophic fire on Maui.
Now, Gov. Josh Green (D) is pursuing a different solution: a natural gas terminal that would again depend on an imported fossil fuel. Julian and Savannah have all the details and explore what Hawaiʻi’s clean energy challenges can teach other states.
Another step forward for nuclear power
America’s nuclear renaissance just keeps getting more credible. Last week, Holtec International — a company usually known for shutting down nuclear plants — announced a big milestone in its quest to reopen Michigan’s Palisades reactor. All major renovations to the plant are done, and the company’s next and final steps are essentially what would be done to restart the plant after a routine outage, reports Alexander C. Kaufman.
The Palisades restart — and the nation’s atomic ambitions — are just one small piece of the world’s nuclear power redux. A BloombergNEF study out this week predicts global nuclear capacity will climb 44% over the next decade. That means as much as 535 gigawatts of nuclear capacity could be on the grid by 2036, up from 372 GW as of last year.
Glass half full: A new MIT report predicts the Inflation Reduction Act’s clean energy legacy will continue despite President Donald Trump and Congress repealing many of its incentives, as tons of renewable power is still on track to get built through 2035. (report, Heatmap)
Demolishing clean jobs: More than 200 clean energy generation and manufacturing projects have been canceled or downsized since Trump took office last year, costing the U.S. hundreds of thousands of jobs, a new report finds. (Canary Media)
Union blowback: Union workers and leaders call out the Trump administration’s buyouts of offshore wind leases, saying the deals are destroying good-paying union jobs. (The Guardian)
Cuba in crisis: Cuba suffered an island-wide blackout early this week amid a U.S.-led blockade on oil imports to the country. (Associated Press)
Cooking up batteries: Brooklyn startup Electra Research is building induction stoves equipped with small backup batteries that can also be leveraged as a grid resource. (Canary Media)
RGGI, set, go: The 11 East Coast states participating in the Regional Greenhouse Gas Initiative will share a massive $1.3 billion for climate programs raised so far this year in auctions of allowances for carbon pollution. (E&E News)
Last year, nearly 40% of all power demand from global data centers came from facilities based in America, per a new report.
Data centers use more electricity in the U.S. than in any other country — China included.
In 2025, nearly 40% of all power demand from data centers came from facilities based in the U.S., according to this year’s Statistical Review of World Energy from the Energy Institute. It’s the first year the sweeping annual report has tracked data center demand, a sign of how central the question of powering these massive facilities has become.
To put that electricity use in perspective: American data centers alone consumed nearly 313 terawatt-hours last year, per the report — more than Australia, Italy, Spain, or the United Kingdom generated to power their entire economies.
This electricity demand has been driven by deep-pocketed Silicon Valley firms racing to build out data centers that can give them an edge in the AI race. Between 2022, when OpenAI shook the world with its release of the ChatGPT 3.5 model, and 2025, global data center power demand grew by 59%.
And it’s only expected to keep climbing. Demand in the U.S. could nearly triple by 2030, according to S&P Global — though estimates vary widely, and some analysts caution that a meaningful share of planned projects may be delayed or never get built.
Still, even conservative estimates find that data center power demand will remain high — and the prospect of yet more growth has spurred urgent conversations across the U.S.
Consumer advocates fear that without stronger regulation, ordinary Americans will be left covering the cost of the strain that data centers put on the grid. And climate advocates worry that, despite the climate goals of Big Tech firms, some new demand will be met with natural gas — a trend that would drive up carbon emissions and local air pollution.
After insisting it wasn’t needed, Duke pitched a “large load tariff” for big energy users — a concession to critics before a hearing on its proposed rate hike.
For months, clean energy and consumer advocates in North Carolina have pressed Duke Energy to follow the national trend and create special rules and prices for data centers. The state’s predominant utility insisted such rules were unnecessary, rejecting claims that the power-hungry facilities could overwhelm the grid or burden households with unfair costs.
But now, the company is changing its tune.
In testimony submitted to the North Carolina Utilities Commission in late June, Duke proposed what it calls a “large load tariff” — a scheme by which data centers and other big electricity customers would pay a minimum bill amount for at least a decade, no matter their actual power use.
The transparent setup would replace the confidential, one-off service agreements that Duke makes with large energy users now. The system would result in a “measured set of customer protections” as data centers flock to the state, the company said.
Duke recently raised its 2035 forecast of electricity demand from large customers to 8 gigawatts in the Carolinas — an increase of 2 gigawatts since its projection from last year — with most of the new growth expected in the form of the gigantic computer warehouses. The company is using that prediction to help justify building a whopping 9.7 gigawatts of new gas plants over the next decade.
Around the nation, large load tariffs are gaining steam as states scramble to prevent the AI boom from exacting an enormous cost on consumers and the climate. At least 75 such tariffs have been proposed or approved in some 35 states, according to data tracked by the Smart Electric Power Alliance and the North Carolina Clean Energy Technology Center.
Duke’s about-face on large load tariffs comes as it prepares to defend its deeply unpopular bid to raise electricity prices at commission hearings that begin July 7. The company has lowered its original rate request but still seeks an increase of 11.6% over two years for residential customers.
The reversal on data centers follows advocacy from the state’s attorney general, state-sanctioned consumer advocate Public Staff, and clean energy groups — all of which have argued for large load tariffs.
“This is a welcome development,” said Munashe Magarira, senior attorney with the Southern Environmental Law Center, which is representing the Southern Alliance for Clean Energy, the North Carolina Housing Coalition, and other nonprofits at the commission as it weighs Duke’s rate-hike request.
“It builds on hard work that’s been done to push the commission to address these issues head on because of the impact large customers will have for the utility, the grid, and society as a whole in North Carolina,” he said.
Still, Magarira said, Duke’s proposal falls short in a few ways. The company recommends that large electricity users pay at least 75% of their maximum potential energy use, instead of the 85% proffered by advocates. The tariff would make minimum contract terms of 10 or 15 years — less than the 20 years proposed by the nonprofit coalition. And it would only apply to customers with loads of at least 50 megawatts, as opposed to the 25-megawatt floor that the nonprofits pushed for.
Advocates say these details matter because it’s vital to minimize risk as much as possible: If Duke builds expensive gas-burning power plants and other infrastructure in anticipation of data centers that don’t materialize as planned — a distinct possibility, according to some analysts — households could be left holding the bag.
Even more concerning for Magarira: Duke doesn’t appear to propose that data centers become a new class of customers. Instead, it offers to standardize the bilateral service agreements it already signs with tech companies.
The distinction is more than semantic, he said. A separate customer class would better enable regulators to design rates tailor-made for data centers and their immense energy needs.
“If the projections are right, we’re facing a pretty unique moment with regards to electricity growth,” Magarira said. “We think there’s a real need to create a separate customer class for these customers — just given how different they are.”
A final overarching concern: Duke’s most recent filing fails to mention a “clean transition tariff.” Such programs are vital in vertically integrated electricity markets like North Carolina’s, where entities that want 24/7 carbon-free energy can’t independently contract for it. Only Duke can sell them electricity, so if Big Tech firms want to pay for clean electrons for their data centers — as many say they do — they need a program like a clean transition tariff that lets the utility serve as a go-between.
A handful of other states have enacted clean transition tariffs. In North Carolina, the idea has been bandied about for years, and Duke has publicly agreed to consider it. But the utility has never formally proposed such a tariff to regulators.
“Let large customers who want to be good corporate citizens, who care about the environment, have the opportunity to purchase incremental clean energy to meet their power consumption,” Magarira said. “That feels like a win-win for everyone involved.”
Duke declined to comment for this story, pointing instead to its testimony. The five-member Utilities Commission could open a separate docket on the large load tariff proposal. Otherwise, its decision on that and other matters in the rate case is expected this fall.
The unicorn startup launched its first move outside its home state of Texas, pitching low-cost energy and backup power in northern Illinois.
PJM Interconnection, which serves 67 million people across 13 states from the mid-Atlantic to the Midwest, has become a poster child for how not to keep up with soaring energy demand. Startup Base Power is taking a whack at that problem by installing a network of unusually large home batteries in one corner of that regional grid.
Starting today, the first 2,000 customers in Illinois utility ComEd’s territory who sign up with Base Power can get a 40-kilowatt-hour home backup battery for just $95 up front. Subsequent customers will pay $295, still a mere sliver of the $10,000 or more that a backup-capable home battery normally costs. All these customers will then buy retail electricity from Base Power at a 25% discount to the prevailing ComEd rate, which was 10.4 cents per kilowatt-hour this summer. Customers sign a 12-year battery agreement, but can pay a $500 deinstallation fee if they want out early.
This business model gives customers in Chicagoland more options for cheap and resilient power while also giving Base Power the rights to operate the battery fleet in response to broader market dynamics. Base Power will be adding capacity in the northwesternmost territory of the constrained regional grid, but its unique model allows it to avoid PJM’s ossified procedures for expanding large-scale grid production.
“We are deploying capacity behind the meter at the residential home, where an interconnection already exists, so we don’t wait in the interconnection queue,” said Base Power’s founder and CEO Zach Dell. “There’s some work around that, but it’s certainly less onerous and much faster than the large-load interconnection queue.”
PJM famously hosts the densest corridor of data centers, in northern Virginia, but the AI buildout has taken off in Indiana, Ohio, and Pennsylvania as well. While hyperscalers stare down yearslong waitlists for new gas turbines to meet their colossal power needs, Base Power can install miniature power plants every day, which add up over time.
The Illinois offering is even cheaper than Base Power’s prices in its home state of Texas, where it has installed more than 500 megawatt-hours of storage since it launched in 2024. Base Power operates most of that in the Texas’ freewheeling, competitive energy market, but it also is working with a cooperative utility to install 100 megawatts of instant discharge capacity at customer homes over the next two years.
Base Power’s two-part pitch of customer benefit and aggregated grid resource has made it arguably the most effective fundraiser in the residential battery space — it netted a billion-dollar raise last fall from mainstream VCs like Andreessen Horowitz and Valor Equity Partners, an early backer of Tesla and SpaceX. Base Power needs that cash to fuel its vertically integrated model: It designs, manufactures, markets, installs, owns, and operates all the batteries in-house.
After a few years of tremendous growth, though, the question had remained whether this model would work outside the particularities of the Texas market. Now, Base Power is staking a claim on a new state that provides access to the country’s biggest regional power market.
Several layers of policy and regulation made Illinois the right entry point for Base Power in PJM. The state allows retail competition, so Base Power can sell power directly to customers. However, it still has to get permission from a wires utility to hook up the batteries to the distribution grid, and ComEd stood out as a partner.
“ComEd, they’re an innovative utility,” said Travis Kavulla, Base Power’s head of policy, who on Monday was tapped to run the Bonneville Power Authority, a New Deal–era federal power agency. “They’ve done things that other utilities have not done.”
In particular, ComEd has rules that compensate homes at market rates for discharging power to offset high capacity prices in PJM. These rules emerged from a recent revision to the long-standing net-metering policy, which originally paid homes for shipping excess rooftop solar to the grid; now, the policy also allows stand-alone batteries to export power and participate in the market.
Base Power will also tap into a new Illinois policy to encourage virtual power plants that was created by the Clean and Reliable Grid Affordability Act, which became law in January. Starting this summer, battery customers can receive a rebate if they install a battery and agree to discharge it to the grid for multiple hours during the evening peak on a certain number of summer nights. It’s a simple way to ensure that the batteries make themselves useful, and Base Power will apply that rebate to support its very low pricing.
All this means that Base Power will not rely on specific PJM programs to make money in Illinois. The grid operator is working on a new mechanism for distributed energy resources to play a broader role in capacity markets, in response to the Federal Energy Regulatory Commission’s Order 2222. That process will have its first auction next month, to pay for capacity in 2028 and 2029, Kavulla noted.
“Our approach is not something that has to wait on that. It’s more ready to go to market if you’re configuring it on the retail side through a competitive retailer, in the way we’re doing it,” he said.
Down the road, the startup could tap another source of revenue by selling aggregated capacity to hyperscalers that need power for new data centers. Google signed a bilateral deal with demand-response provider Voltus to do just that in PJM. Sunrun, Tesla, and Renew Home just announced a national strategy to tap existing home batteries and smart thermostats to sell capacity to data center customers. Dell confirmed that Base Power is in talks with data center clients, but said his Illinois strategy does not depend on that kind of deal.
Whether or not Base Power deals directly with data centers, the households in Illinois are feeling upward pressure on their energy bills as the region struggles to supply the AI arms race. Some governors have threatened to exit PJM if the capacity costs keep rising, though that would take years of thorny wrangling to execute. If other PJM states want to do something to help customers short of the nuclear option, they could look to the ComEd policy that rewards households for peak exports.
“One of our takeaways here is that if you’re a state in PJM, this is something that you can kind of cause your utilities to do,” Kavulla said.
The clean energy giants are uniting their home batteries and smart thermostats to help tech giants power booming, AI-driven data centers without crushing the grid.
The leading U.S. providers of rooftop solar, home batteries, and grid-responsive smart thermostats have combined forces to create what could be the country’s biggest virtual power plant — or, more precisely, a lot of VPPs in data center hot spots.
On Wednesday, Sunrun, Tesla, and Renew Home announced an agreement to “deliver more than 16 gigawatts of flexible energy capacity” to tech giants and utilities around the United States. Those gigawatts will be produced by hundreds of thousands of home battery systems managed by Sunrun and Tesla, as well as more than 8 million smart thermostats and devices managed by Renew Home.
These batteries and smart thermostats are already installed in homes and businesses across the country, Paul Dickson, Sunrun’s president and chief revenue officer, told Canary Media. Some are enrolled in utility or grid programs that call on batteries to discharge, or thermostats to turn down energy use, during the handful of hours per year when grid demand is at its peak, he said.
But he noted, “Most of the constructs for these distributed power plants are tapping into the resources a fraction of the time they could be realized.” This new partnership is meant to “further legitimize these devices as core dispatchable, capable resources.”
Wednesday’s announcement is just the latest — and biggest — proposal for solving the country’s rising energy costs and grid congestion challenges through the power of distributed energy.
The aggregated energy-injecting and load-shifting capacity of batteries, smart thermostats, electric vehicle chargers, and remote-controllable appliances such as water heaters could add 80 gigawatts to 160 gigawatts by 2030, or roughly three to five times what’s now available across the country, according to analysis from the U.S. Department of Energy. VPP deployment at that scale could save U.S. utility customers about $10 billion in annual grid costs, the DOE estimated.
To make that happen, VPP companies need to coordinate with — and convince — utilities, regional grid operators, and state and federal regulators that distributed energy resources can do the work of traditional power plants. That’s easier said than done. The grid has been designed to deliver electricity from central power plants, not to rely on thousands of customer-owned devices turning on and off in unison to keep supply and demand in balance.
But traditional ways of managing the grid are falling short in the face of booming demand from the massive data centers that tech giants like Amazon, Google, Meta, Microsoft, and Oracle are building to fulfill their artificial intelligence ambitions. Some states are already seeing big spikes in energy costs due to data center growth. Across the country, lawmakers and regulators are demanding that developers of these facilities find ways to finance their own energy resources to avoid pushing more costs onto everyday consumers.
That’s putting pressure on tech giants to pursue novel approaches, from shifting when they use power, in order to avoid stressing the grid during times of peak demand, to investing in VPPs that can do the same work.
Home batteries and thermostats obviously can’t power data centers around the clock, Dickson said. But they can “solve elegantly for your peak-capacity needs, which is the bottleneck for data centers getting connected,” he said. “We want to provide for getting more data centers online in a way that doesn’t strain the grid or cause costs for customers to rise.”
Sunrun, Tesla, and Renew Home have a lot of existing customers to work with. Sunrun and Tesla already operate hundreds of megawatts of battery-based VPP capacity, including large-scale aggregations in California, New England, Texas, and Puerto Rico. And Renew Home — a spinoff of Google Nest’s smart-thermostat energy-shifting service Nest Renew and California startup OhmConnect — has partnered with major energy retailer NRG Energy to aggregate a gigawatt of flexible capacity in Texas, and is working with utilities in Arizona and other states.
Lots of companies are promising similar solutions. Voltus, a major U.S. demand-response and VPP aggregator, launched its “bring-your-own-capacity plan” last year, targeting tech giants struggling to interconnect to overburdened power grids. Earlier this month, Voltus and Google announced plans to develop 100 megawatts of this distributed capacity as part of the tech giant’s broader efforts to finance new energy resources for its expanding data center footprint.
Data centers want to “lock in that capacity, which is important to them,” Voltus’ CEO Dana Guernsey told Canary Media in early June. “They’re giving us the right signals to build, which we can take to our customers to save them money. And it’s not putting the cost on the ratepayers.”
The more data centers are willing to pay for VPP capacity, the more companies can offer customers to participate in them, Dickson said. Sunrun and Renew Home have paid out nearly $70 million to customers participating in existing grid-services programs, he added.
Low-income households could particularly stand to benefit if these programs prioritize these customers, according to a recent study by consultancy Brattle Group for the Natural Resources Defense Council. It found that if programs directed energy efficiency and VPP investments from data centers to lower-income customers in four cities — Atlanta; Memphis, Tennessee; Kansas City, Missouri; and Columbus, Ohio — participating households could save from $50 to more than $1,000 per year on their utility bills.
It’s not yet clear how Sunrun, Tesla, and Renew Home might deliver additional savings to customers at large. The companies didn’t disclose which existing or in-development VPP programs or data center opportunities they’re jointly pursuing.
But they are staking claims in key markets, including northern Virginia’s “Data Center Alley,” where massive data center expansions are pushing the grid to its limit, driving lawmakers and regulators to explore policies to limit cost and environmental impacts. Sunrun, Tesla, and Renew Home claimed they collectively have “more than 300 megawatts of capacity readily available for immediate deployment” in the region, which they expect will grow to at least 500 megawatts by 2030.
Sunrun, Tesla, and Renew Home also intend to provide VPP capacity to PJM Interconnection, the country’s biggest energy market, where power costs are spiking because of new data centers and PJM’s inability to bring new generation resources online. Specifically, the companies plan to commit capacity to PJM’s upcoming reliability backstop procurement, which is being designed to encourage data center developers to pay for new resources to match their grid impacts.
Renew Home has a lot of smart thermostat–equipped customers in the 13 states and Washington, D.C., region who are served by PJM but aren’t yet enlisted in VPP programs, CEO Ben Brown told Canary Media. “We have over a gigawatt of capacity in the ground, installed, flexing every day, providing savings for customers every day,” he said.
Last year, Renew Home ran tests of the potential grid relief those thermostats could provide, and found that customers were able to reduce summertime peak demand by about 380 megawatts over three consecutive afternoons, he said. That represented a little less than half its available “fleet” of customers, he added.
Dickson highlighted other parts of the country where the three companies have capacity to spare. According to the partners’ calculations, they can collectively relieve grid stresses for roughly two hours at a time by about 4.7 gigawatts in California, about 1.7 gigawatts in Texas, and about 1 gigawatt across Illinois and Ohio.
The number of home batteries and smart thermostats available for future service could expand if data centers are willing to pay more for these services, Dickson said. “Unlike a traditional power plant, this number grows every single day.”
The flow has been stop and go for the first few months, but the line shows plenty of potential to boost Massachusetts’ renewable energy supply.
When the New England Clean Energy Connect transmission line started carrying electricity from Canada into Maine in January, supporters hailed the project as a triumph for renewable power. Now, after nearly six months of operations, the early numbers raise questions about whether the project will be able to advance the region’s energy transition as much as advertised.
Energy flow into New England is up just marginally, and there have been roughly 27 days when no power at all traveled along the new line, commonly called NECEC. If current trends hold, New England will receive less hydropower this year over two transmission lines than it did over just one line in 2023 and previous years.
“What we’ve seen so far is not what some people expected to see,” said Joseph LaRusso, manager of the Clean Grid Program at climate nonprofit Acadia Center.
Potentially putting further strain on the supply of Canadian hydropower is the Champlain Hudson Power Express, a transmission line that started sending electricity from Quebec into New York City this month.
NECEC has its origins in a 2016 Massachusetts law that required the state to procure 1.6 gigawatts of offshore wind power and another 1.2 gigawatts of additional renewable energy. The plan was to contract with state-owned Canadian power supplier Hydro-Québec to tap into the region’s abundant hydropower resources and build a new transmission line to carry the electricity south.
The first proposal — a 192-mile project through New Hampshire — was abandoned in 2019 after public outcry about the impact on the state’s forests. The transmission line through Maine faced similar controversy. In 2021, a statewide referendum vote put the project on hold until 2023, when a jury ruled that the development could be restarted.
Two and a half years later, NECEC came online and started carrying the first electrons into New England. It’s certainly a notable achievement in a time when the Trump administration has been doing all it can to stop progress on clean energy, including offshore wind — the cornerstone of the Northeast’s decarbonization plans. And although the results so far have been mixed, some see potential for the line to make a sizable impact on New England’s clean energy future.
When NECEC came online earlier this year, Massachusetts Gov. Maura Healey, a Democrat, and climate advocates touted it as a major win for the state’s renewable energy goals and a way to save residents money on their utility bills. Massachusetts contracted with Hydro-Québec for 9.55 terawatt-hours of hydropower per year, roughly 20% of the state’s annual electricity demand.
The operations have not had the smoothest start. NECEC was completely inactive for several spans — from a half day on April 28 to nearly two weeks at the end of May and beginning of June. The most recent outage was due to “technical difficulties,” Hydro-Québec spokesperson Lynn St-Laurent said in a written statement.
“Once repairs were completed, deliveries resumed,” she said. “With any new transmission infrastructure, a period of optimization and fine-tuning is to be expected.”
Still, most of the time, hydropower has flowed steadily on the new infrastructure. Through the end of April, Hydro-Québec exported about 2.4 terawatt-hours of power on the transmission line.
If the power is (mostly) moving as planned, why are some people still skeptical that the project will deliver the promised benefits? Because so far, it hasn’t done much to add to the total supply of renewable energy in New England.
Before NECEC, New England already imported significant amounts of hydropower on a transmission line known as Phase 2, which runs from Quebec into central Massachusetts. In 2019, the year the Massachusetts regulators approved the contracts between utilities and Hydro-Québec, more than 12 terawatt-hours traveled onto the New England grid over the line.
But starting in 2023, Hydro-Québec started selling less and less energy to New England over Phase 2. For nearly three weeks in early 2025, exports ceased entirely. Through the end of April this year, just over half a terawatt-hour has come south over that line. On paper, it can look a lot like NECEC isn’t allowing more energy into New England but is instead just giving it a new road to travel along.
“We’re not seeing much net new flows coming from our neighbors,” said Dan Dolan, president of the New England Power Generators Association. “We are running pretty close to the net energy flows we had in 2025, which were the lowest amount of imports that New England has ever gotten from Quebec.”
At the same time, Quebec has started importing power over the Phase 2 line, a rare occurrence before 2025. In the first four months of this year, more than 500 gigawatt-hours traveled into Canada on the line. Because New England’s electricity supply relies heavily on natural gas generation, the region is still burning fossil fuels to ship energy north even though it is receiving hydropower for its own use.
“We’re seeing a heavier natural gas burn on the rest of the generation fleet than I think many of those states had assumed going into this year,” Dolan said.
The main driver behind slowing exports seems to be the drought conditions that have lingered in Quebec for the past few years. During wetter periods, the hydropower industry uses large reservoirs to store water to help it ride out these drier times, said Gilbert Bennett, a senior adviser for WaterPower Canada, a hydropower trade group.
As generators wait for rainier days, their first obligation is to supply domestic customers, he said. That means there will likely be times when Hydro-Québec needs to import electricity over the Phase 2 line to offset some of the hydropower it is contractually obliged to send to Massachusetts over NECEC.
“Electricity flows between Québec and New England are dynamic and vary continuously based on market conditions and system needs on both sides of the border,” St-Laurent said.
Financially, New England customers should not be at risk from these ongoing shifts, LaRusso said. Massachusetts’ contract with Hydro-Québec includes provisions that require the Canadian company to pay financial penalties if it fails to deliver according to its contract.
“To the extent that imports are curtailed, Hydro-Québec is liable to make the electric utilities whole for the cost of replacement power,” LaRusso said.
It is less clear whether NECEC will boost Massachusetts’ renewable energy supply in the long run.
Still, the new transmission line has at times demonstrated its potential to help New England achieve a cleaner energy supply, LaRusso said. He pointed to May 16, a sunny day when solar power reduced demand on the grid and NECEC was going full tilt. Natural gas plants were running at low levels, and most of the power was heading to New York. For a short time, all the region’s power needs could be met by nonfossil fuel resources.
“Hypothetically, [grid operator] ISO New England could’ve turned off its gas generators,” LaRusso said. “It really gets you thinking of the resources available and how they could be managed and shared in the future.”
Bennett is also confident in the long-term outlook. In general, he said, climate change is forecast to create wetter conditions in Quebec. And the region is investing heavily in additional hydropower facilities as well as onshore wind. The years to come, he said, will bring plenty of renewable resources to share with Canada’s southern neighbors.
“Over the long term, we see a bright future,” Bennett said.
Most U.S. grid operators already use OATI’s software. Now the firm wants to tap AI and data to boost transmission capacity — and it’s asking the DOE for funding.
A major grid-tech company is asking the Trump administration to fund a project it says could significantly boost the nation’s ability to move power around — without building a single new transmission tower or line.
Open Access Technology International (OATI) is a Minneapolis-based firm whose software is used by nearly every North American transmission grid operator to manage the flow of electrons. Now, it envisions developing new features for that software. Huge amounts of data, parsed by artificial intelligence, would be used to more accurately calculate how much power can run along power lines — providing both real-time estimates and forecasts days and weeks into the future. That intel would be automatically shared among neighboring grid operators, allowing them to make better decisions about how to run their networks.
If all goes to plan, OATI says the facelift could accomplish a 10% to 20% increase in capacity across participating systems by 2030.
OATI unveiled its scheme in a May proposal for an undisclosed amount of money from the Department of Energy’s $1.9 billion SPARK grant program. The program uses money from the 2021 bipartisan infrastructure law, in a somewhat rare example of Biden-era energy funding spared from the Trump administration’s clawbacks.
The company’s proposal is a kind of “grid-enhancing technology,” a family of hardware and software that could squeeze more capacity out of the nation’s increasingly congested grid. These solutions have the potential to save the nation billions of dollars in excess power costs by unclogging transmission bottlenecks that prevent cheap electricity, much of it from wind and solar farms, from reaching places that need it. That could help curb skyrocketing utility bills for households and businesses.
The problem in the U.S. today is that these tools are almost exclusively deployed as pilot projects on one power line at a time. To achieve the big savings, multiple utilities and grid operators will need to use this tech in a coordinated way across the country’s region-spanning transmission networks.
OATI — with its decades of data and vast existing connections across the power industry — thinks it can catalyze that sort of large-scale deployment. It’s already enlisted a sizable group of partner organizations that have agreed to implement the new software add-ons, among them the grid operators California Independent System Operator, New York Independent System Operator, and Southwest Power Pool; the utilities Dominion Energy, Duke Energy, NextEra’s Florida Power & Light, PacifiCorp, and Portland General Electric; and the electricity cooperatives Great River Energy and Lakeland Electric.
John Engel, OATI’s associate vice president of strategic marketing, noted the company would bring significant matching funds to the table to deploy its software.
“What we can do is across 95% of North America,” Engel said. “There’s a speed and scale there that’s unique — and the [Trump] administration has said they want fast, durable, and cost-effective solutions.”
One of the key goals of OATI’s proposal is to deploy a version of a technology called dynamic line rating, or DLR. Over the past 20 years, DLR has evolved from devices that clip onto power lines, to sensors on transmission towers that monitor lines via optics and electromagnetics, to software-only approaches — like OATI’s — that use weather and grid data.
All these different methods have a common purpose: to determine the constantly changing true capacity of high-voltage power lines.
Quite often, that true capacity is greater than the traditional “static” ratings assigned to power lines, which don’t take weather and wind speed into account. For example, breezy conditions can cool lines, allowing them to safely carry more electrons at the same time that wind farms are generating the most energy.
Armed with this knowledge, operators can dispatch higher levels of power flows across parts of the grid they’d otherwise have to curtail. In a 2024 report, the DOE estimated that widely deployed DLR could increase existing grid capacity by roughly 80 gigawatts, saving billions of dollars in transmission infrastructure costs.
DLR in the U.S. has been hindered by a fractured regulatory landscape and the fact that transmission-owning utilities earn money by investing in new infrastructure, not by installing technology that makes their existing grids operate more efficiently. But players in Europe have been using the tech in a systematic way for more than a decade. Belgian grid operator Elia has achieved an average 30% increase on its transmission grid using DLR.
OATI, for its part, already has some experience tweaking line ratings based on weather, said Kevin Sarkinen, the company’s chief operations officer.
Back in 2021, federal regulators ordered all transmission operators to start using ambient adjusted ratings — essentially, hourly ratings based on daily temperature forecasts — by July 2025. OATI’s platform has already integrated those ratings into its transmission capacity calculations. “Now we’re adding in the capability for the DLRs,” Sarkinen said. That will bring in additional real-time data, like cloud cover, heating from the sun, and, most importantly, wind speed and direction, which have a huge impact on power line capacity.
The U.S. hasn’t been standing still on DLR. Deployments in Indiana, Minnesota, New York, Ohio, Pennsylvania, Texas, Virginia, and other states have shown the technology can significantly increase capacity on individual power lines.
But getting more headroom on one line only gets you so far on a networked grid that must operate as a unified whole. As a 2019 DOE report put it, “DLR has the potential to expand the Nation’s power highway system, but the exits and intersections must be capable of using that new capability for it to be worthwhile.”
OATI wants to leverage its broad customer base to make such an integration possible, Sarkinen noted. It will work the real-time DLR data into its software suite, which 95% of North American transmission operators use to share information about their available capacity and to manage the flow of power across networks.
The firm also plans to leverage its AI-informed Genie platform to boost the usefulness of all these figures. It’s been deploying that tech with California’s grid operator over the past two years, Engel said, processing large amounts of data to quickly decide how to safely reconfigure systems when power plants go offline or individual transmission lines are overloaded.
In this new use case, OATI’s Genie platform “looks at the modeling and coordination of these grid operators, and applies some AI technology to these coordination processes to increase the accuracy of the grid,” Sarkinen said. The AI applications allow for “constant assessment of how accurate your calculations were” as well as forecasting “if you want to make capacity available tomorrow or next week.”
OATI and its partners hope to start turning these technology deployments into real-world grid capacity improvements by the third and fourth years of their joint project, Sarkinen said. That’s practically light speed in the world of transmission, where construction of a single line can sometimes take decades.
All this is easier said than done.
OATI may not get the DOE funding, although company executives said they plan to move forward with the initiative regardless.
And the project could face unforeseen technical hurdles and delays. The new features are still works in progress, and even though they are based on lots of data, dynamic line ratings are still just estimates. Utilities and grid operators will need to learn to trust the data for both real-time decisions and forecasts, since these organizations make commitments to transport energy hours, days, or even weeks in advance.
“We can’t perfectly predict the weather, and we have to integrate that uncertainty into how we operate the grid,” said Aidan Tuohy, director of R&D for transmission operations and planning at the Electric Power Research Institute, a nonprofit utility research organization that’s working on a range of grid-enhancing technology projects with partners including OATI. But the latest advances in AI are increasingly useful in “using past data to predict what’s going to happen,” he said, by cross-checking ongoing forecasts against historical data from grids operating under similar conditions.
A lack of confidence in these weather-based predictions is one of the main barriers to making the most out of DLR, said Georg Rute, CEO of Gridraven, a startup that’s deployed its technology across Finland’s national grid and relocated to Texas last year to support plans to expand in the U.S.
“What I hear from the engineers, who have a veto right at transmission companies to turn on DLR, is that they don’t have the confidence that the forecasts work,” he said. “That is the real blocker. It’s not so much the incentives or the regulation.”
But although sticking with the status quo may be simpler, all U.S. utilities and grid operators are under federal mandate to integrate grid-enhancing technologies into how they bring new power generation online and make long-term plans for expanding their grids — and to find near-term ways to manage strains caused by power demand from data centers.
Meanwhile, utilities are struggling to manage a “more complex grid, with more exchanges between regions, more data centers, more variable and distributed resources,” Tuohy said. “Having the data to make decisions is going to become increasingly important.”
A correction was made on June 10, 2026: This story originally misstated that OATI executives declined to comment on whether they would move forward with their grid-enhancing tech project without DOE funding. Executives have clarified they plan to move forward with the initiative regardless of whether it secures the federal funding.
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