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It’s official: Grid batteries broke another record.
More than 13 gigawatts of energy storage was installed across the U.S. last year, per a new report from the Business Council for Sustainable Energy and BloombergNEF. That’s up from the roughly 12 GW installed in 2024.
It’s the latest reminder of the meteoric rise of battery storage, a quick-to-deploy technology that’s key to cutting emissions from the electricity system. Storage enables the grid to bank electricity when it’s cheap and abundant — like when surplus solar is generated in the middle of a sunny day — and deploy it when prices are high and electrons are scarce.
Less than a decade ago, the sector was little more than an intriguing possibility. Energy storage in America mostly meant massive, decades-old pumped-hydro storage projects and a handful of small lithium-ion battery plants.
In 2017, only 500 megawatts of grid battery capacity was online in the U.S.; now, there are individual battery installations larger than 500 MW. Still, the sector had big expectations for itself back then: In 2017, the Energy Storage Association set a goal of reaching 35 GW of storage capacity by 2025.
Last year, the sector smashed that goal, hitting it in July and ending the year with nearly 45 GW of installed capacity.
Increasingly abundant solar power, rising energy demand, and declining battery costs have combined to propel the storage sector to these lofty heights. To date, most utility-scale batteries have been plugged into the grids of Texas and California, two solar-soaked states with radically different approaches to encouraging storage growth.
In the coming years, the storage sector has a smoother path to continued growth than do renewables.
Yes, it faces some challenges. Federal tax incentives are now contingent on compliance with strict but vague anti-China supply-chain rules. Developers also have to deal with tariffs and increasing local opposition.
But, unlike for solar and wind, tax credits for storage were spared in the One Big Beautiful Bill Act that President Donald Trump signed into law in July. Also unlike solar and wind, the battery industry has not yet attracted much explicit trash-talking from either Trump administration officials or Trump himself. Storage is also increasingly cheap and fast to build.
These facts, plus the urgent need for new sources of affordable energy as utility bills rise, have the storage industry poised for continued growth in the years to come.
Last Friday, U.S. Energy Secretary Chris Wright held a press conference to talk about how the power grid didn’t collapse during late January’s Winter Storm Fern.
Some of the things he said were true. Others weren’t. It’s important to know the difference — especially as the Trump administration routinely uses misleading statements to justify decisions that make the power system dirtier, more expensive, and ultimately less reliable.
Wright, a former fossil gas–industry executive who has overseen the administration’s hard turn against clean energy, praised the efforts of utility workers who rallied from across the country and worked around the clock to restore power to more than 1 million people after ice and falling trees took out grid lines. That’s true, and good.
But the centerpiece of Wright’s nearly hourlong presentation was a series of charts, propped up on an easel, that served as a launchpad for the same kind of half-truths and obfuscations that have typified his approach to the job.
His pie charts showed the mix of electricity generation at the peak of wintertime demand across the eastern U.S. and in New England. There was a lot of fossil gas, a big slice of coal and of nuclear, and, in New England, a lot of oil — a key source of emergency generation in wintertime. Meanwhile, wind and solar power, the resources Wright called the “darlings” of the climate movement, were represented by very small slices.
In Wright’s view, these charts tell a story of waste and excess. People had to pay for the construction of all that renewable energy, and the poles and wires required to carry it, only for that power to disappear when the grid needed it most.
Here’s how he put it: “If you can add reliable power at peak demand time, you’re additive to the grid. If you can’t, you’re just … a cost center. You’re not actually helpful for the grid.”
This is a gross oversimplification of the complex ways that different types of power add value to the grid. As Wright well knows, people don’t need electricity on just the hottest or coldest days. They need it every day, all 8,760 hours of the year. And how that power is generated on a daily basis matters just as much as how it gets produced in extreme circumstances — for people’s wallets, their health, and the planet.
The vast majority of the time, wind and solar — and energy storage — reliably provide electricity to the grid. During the first 10 months of 2025, the U.S. got nearly one-fifth of its electricity from these sources.
Why is that? Because the electricity that renewables provide is cheap and plentiful. Nowadays, it is often less expensive than gas-fired power. And renewables are certainly much cheaper than coal power, even as Wright’s Department of Energy has spent the last year propping up the dirty fossil fuel at great cost to consumers.
For the past two years, solar, wind, and storage have made up more than 90% of the new electricity capacity being added in the U.S. — and around the world. And we will need to keep up that pace for the U.S. to meet growing power demand from data centers and electrification without causing already rising electricity costs to soar further.
But Wright casts cheap, clean power as mere empty calories that steal market share from coal, gas, and nuclear power. Energy supplied only when “the weather is mild, when the sun shines or the wind blows, doesn’t add anything to the capacity of our electricity grid,” he said. “It just means we send subsidy checks to those generators, and we tell the other generators, ‘Turn down.’”
Here, Wright mischaracterizes how utilities and grid operators dispatch power plants. Wind and solar often “turn down” when they’re generating more power than the grid needs. But fossil-fueled power plants stop generating when their power is too expensive to compete with what wind and solar generators are offering — market forces in action.
It’s worth mentioning, too, that utilities and grid operators are well aware that wind and solar are weather-dependent and don’t produce all the time. These experts constantly assess the availability of all resources — not just renewables — and plan accordingly.
Wright also neglected to say that fossil fuels themselves can fail during winter storms — and often in less predictable and more harmful ways than when the sun sets or the wind dies down.
That’s what happened during Winter Storm Uri in 2021. That storm swept over the U.S. Southeast — and in particular, Texas — bringing subzero temperatures that froze wellheads and restricted the flow of gas to power plants, which were experiencing their own weather-related failures. The result was catastrophic: More than 200 people died and roughly 4.5 million homes and businesses lost power. Similar gas-system freeze-ups drove winter blackouts across the Southeast in 2022 and during the 2014 “polar vortex” in the Northeast.
During Winter Storm Fern, it was a different story: Generator failures did not force utilities and grid operators to shut off power. One likely reason is that, in the years since Uri, regulators have imposed winterization requirements on owners of gas power plants in Texas and other parts of the country, though just how effective those interventions were is not yet clear.
Another probable factor contributing to the grid’s resilience this time around was having a better overall mix of resources. Energy experts agree that portfolios of mutually reinforcing resources are the key to grid reliability. In the Lone Star State, solar and battery storage have surged in recent years. Texas’ grid weathered this January’s cold snap, experts say, because it had an array of fuel sources on hand.
But of course, Wright didn’t acknowledge any of that. He simply railed against renewables, painting them as leeches on the power system.
Fossil-fueled power plants remain vital to the U.S. grid, whether they’re designed to run around the clock or only during emergencies, as is the case for New England’s oil-burning generators — one of the grid’s costliest resources, precisely because they run so infrequently. But renewables are vital, too. In New England, the gigawatts of offshore wind being built from Connecticut to Maine that have been under attack since the first day of the second Trump administration are also one of the most valuable winter resources for the region.
The DOE’s job is not to take a snapshot of the worst 15 minutes of the year and use it to justify policies that freeze in place that exact mix of grid resources. Instead, it’s to assess and manage the grid’s evolving technical, economic, environmental, and climatic realities, and to foster newer, better resources to replace those that aren’t keeping up.
The more Wright pretends otherwise, and uses half-truths to force fossil fuels onto a system that would be better served by cheaper and cleaner alternatives, the worse off we’ll all be.
Startup NineDot Energy just raised $431 million to build batteries in New York City’s vacant nooks and crannies — an endeavor that will help the metropolis fend off looming electricity shortages.
The debt financing announced Monday will support the Brooklyn firm’s plan to develop 28 battery projects totaling 494 megawatt-hours of energy storage capacity over the next two years. NineDot estimates that’s enough storage to meet the peak energy needs of about 100,000 households.
NineDot is one of several companies deploying “community battery systems” — grid-tied energy storage installations that can fit into roughly an acre of land or less — in New York City. These systems sop up excess energy from the grid when power is abundant and send it back when demand is high, like on hot summer afternoons when millions of air conditioners crank up. Bigger batteries may be able to store more energy, but community-scale systems can be more realistic to quickly deploy in über-dense places.
The decade-old startup’s latest round of construction finance, led by Natixis Corporate & Investment Banking, brings its total funding to just over $1 billion, said David Arfin, NineDot’s CEO and co-founder.
NineDot already has seven projects operating — including a 12-megawatt-hour battery and solar installation at a former parking lot in the Bronx and a 20-megawatt-hour battery system in Staten Island — or in advanced stages of construction in New York City, he said. By 2028, it plans to have 37 community storage systems with a combined capacity of 1.6 gigawatt-hours up and running across the five boroughs, he said.
It isn’t easy to find spots to build batteries in New York City, said Adam Cohen, NineDot’s chief technology officer and co-founder. It can be even harder to find space on Con Edison’s power grid to connect them, he said.
But the utility is under mounting pressure to expand its energy storage capacity — and that’s driving companies like NineDot to seek out vacant or underused lots in the country’s densest urban environment.
New York law sets a statewide goal of 70% renewable electricity by 2030, and state policy calls for building 6 gigawatts of energy storage by 2030. Upstate New York has plenty of land for utility-scale wind, solar, and battery farms. But downstate New York and New York City are where power demand is greatest and the generation mix is the dirtiest — and there’s not yet enough transmission grid capacity to solve those problems with clean power from the north, Cohen said.
Meanwhile, the New York City area faces an energy crunch as power demand surges and aging fossil-fueled plants in the boroughs prepare to shutter. In October, the state’s grid operator warned that New York City and Long Island might face “reliability violations” as soon as this summer.
Late last year, state regulators ordered Con Edison to seek out “a broad array of potential non-emitting solutions” that could quickly bolster reliability.
“You could solve that with new transmission,” Cohen said — except that’s hard to build. The Champlain Hudson Power Express, a major transmission line from Canada to New York City, is nearing completion and scheduled to start delivering hydropower and wind power in May. But another major transmission line being planned to carry power into the city was canceled in 2024.
Another option is “keeping dirty peaker plants online,” Cohen said. But the fossil-fueled plants that New York City relies on to serve its peak loads are expensive to operate and emit health-harming air pollutants, largely in low-income communities and communities of color.
That’s why state regulators’ order to Con Edison calls for “non-emitting solutions, prioritizing cost-effectiveness and ease of deployment, and minimizing impacts to disadvantaged communities.”
Batteries fit that bill, say proponents of the tech. William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, noted that the utility’s initial report to regulators in January identified a roughly 125-megawatt shortfall for about three hours during peak summer demand starting in 2032. This is “well within the range of the energy storage we expect to be deployed,” he said.
“That’s changing how the state is looking at energy storage deployment in New York City,” Acker said. “It’s one of the most cost-effective ways to address this reliability challenge.”
New York state has struggled to meet its targets for utility-scale clean energy, with supply chain disruptions and rising interest rates undermining the financial prospects for big wind and solar farms. It’s also faced challenges in getting large-scale battery projects up and running, largely because of problematic contract structures that crimped project financing.
But smaller community battery projects, like NineDot’s, have an advantage on that front: They can access the state’s incentives designed to encourage distributed energy resources that deliver power when and where the grid needs it the most. These incentives offer far steadier and more predictable revenue streams than those set up for the state’s larger-scale utility programs, Arfin said.
Community battery projects are also eligible to feed into New York’s Statewide Solar for All program, which provides a portion of revenues from community solar and storage projects to utility customers in disadvantaged communities who are enrolled in energy-affordability programs. NineDot forecasts that the projects it has committed to Statewide Solar for All will deliver more than $60 million in energy credits over the coming decade.
NineDot’s strategy of putting batteries on vacant or underutilized lots is one of several approaches being taken to add energy storage to the New York City grid. For example, Con Edison has deployed batteries at its substations and worked with companies installing them at EV charging stations and electric school bus depots. And some New York City businesses are using small plug-in batteries to cushion their draw on grid power during hours of peak demand.
Meanwhile, larger-scale projects like 174 Power Global’s 400-megawatt-hour battery in Queens are starting to get built, and energy developers, including Summit Ridge Energy and Convergent Energy and Power, have community battery projects underway.
But batteries in the Big Apple aren’t always getting a warm reception from their neighbors. Public opposition, spurred by a spate of grid battery fires, has quashed several projects in Staten Island and has led to an ongoing moratorium on their construction in the Long Island town of Oyster Bay. New York City mayoral candidate Curtis Sliwa railed against battery projects in the waning days of his campaign last year, calling them “mini-Chernobyls.”
But Cohen noted that the Fire Department of New York has spent years developing grid-battery safety rules that may be the most comprehensive in the country. “The FDNY is the global gold standard for approving battery storage technology and sites,” he said. “It’s cumbersome — but it’s trusted and thorough.”
A decade ago, North Carolina boasted more solar power than any other state in the country but California — a distinction owed to scores of large projects built under a suite of clean energy–friendly policies that the Tar Heel State has since repealed or amended.
Now, many of those solar farms are staring down the end of their initial agreements with Duke Energy, the state’s predominant utility. But under a new proposal before North Carolina regulators, project owners could lock in favorable long-term renewals pending one main condition: They have to add batteries.
The scheme was proffered by Duke and is backed by clean energy businesses and advocates. If it’s green-lit by the North Carolina Utilities Commission, it would represent the first systematic move toward “repowering” large-scale solar facilities in the state. The potential is enormous: Contracts expiring in the next five years total 1.9 gigawatts — an amount equal to more than a quarter of North Carolina’s entire utility-scale solar fleet.
Since battery storage will benefit from federal tax credits with few strings attached for at least another six years, and Duke faces daunting power demands from coming data centers and other large electricity users, this form of repowering could support reliability and affordability. In large swaths of rural North Carolina, extending the life of these older projects also makes more sense than decommissioning them.
“Adding batteries to a system that’s already out there makes it immensely more valuable to the grid,” said Steve Kalland, executive director of the North Carolina Clean Energy Technology Center. “In North Carolina, that’s going to be significant.”
More so than its ample sunshine or abundant open space, state policy propelled North Carolina to become a national solar leader back in 2016.
A decades-old state tax credit supplemented federal incentives, and in 2007, lawmakers adopted a modest but meaningful renewable energy requirement. But perhaps most important was the state’s implementation of a federal law designed to encourage small power producers independent of utility monopolies. North Carolina’s rules under the Public Utility Regulatory Policy Act, or PURPA, were among the most favorable in the country, with standard offer, 15-year contracts available for projects with up to 5 megawatts of capacity.
This cocktail of rules and mandates caused PURPA-qualified solar projects to soar, with over 450 large-scale developments coming online in the state from 2010 to 2017, according to the nonprofit North Carolina Sustainable Energy Association, with a capacity of over 3.3 gigawatts.
But by 2017, Duke was on pace to easily meet the clean energy mandate, and Republican state lawmakers had repealed the tax incentive. What’s more, the utility said the surge in solar was creating interconnection bottlenecks and the need for expensive grid upgrades.
So the company helped draft a new state law that year meant to clear the backlog and move most new solar into a competitive procurement process. The standard offer contracts under PURPA survived but were reduced to 10 years for projects with up to 1 megawatt.
In part due to the PURPA changes, annual solar installations in the state have slowed, dropping from a peak of 985 megawatts in 2017 to an average of just under 500 megawatts in the years that followed.
How much should data centers pay for the massive amounts of new power infrastructure they require? Wisconsin’s largest utility, We Energies, has offered its answer to that question in what is the first major proposal before state regulators on the issue.
Under the proposal, currently open for public comment, data centers would pay most or all of the price to construct new power plants or renewables needed to serve them, and the utility says the benefits that other customers receive would outweigh any costs they shoulder for building and running this new generation.
But environmental and consumer advocates fear the utility’s plan will actually saddle customers with payments for generation, including polluting natural gas plants, that wouldn’t otherwise be needed.
States nationwide face similar dilemmas around data centers’ energy use. But who pays for the new power plants and transmission is an especially controversial question in Wisconsin and other “vertically integrated” energy markets, where utilities charge their customers for the investments they make in such infrastructure — with a profit, called “rate of return,” baked in. In states with competitive energy markets, like Illinois, by contrast, utilities buy power on the open market and don’t make a rate of return on building generation.
Although seven big data-center projects are underway in Wisconsin, the state has no laws governing how the computing facilities get their power. Lawmakers in the Republican-controlled state Legislature are debating two bills this session. The Assembly passed the GOP-backed proposal on Jan. 20, which, even if it makes it through the Senate, is unlikely to get Democratic Gov. Tony Evers’ signature. According to the Milwaukee Journal Sentinel, a spokesperson for Evers said on Jan. 14 that “the one thing environmentalists, labor, utilities, and data center companies can all agree on right now is how bad Republican lawmakers’ data center bill is.” Until a measure is passed, individual decisions by the state Public Service Commission will determine how utilities supply energy to data centers.
The We Energies case is high stakes because two data centers proposed in the utility’s southeast Wisconsin territory promise to double its total demand. One of those facilities is a Microsoft complex that the tech giant says will be “the world’s most powerful AI datacenter.”
The utility’s proposal could also be precedent-setting as other Wisconsin utilities plan for data centers, said Bryan Rogers, environmental justice director for the Milwaukee community organization Walnut Way Conservation Corp.
“As goes We Energies,” Rogers said, “so goes the rest of the state.”
We Energies’ proposal — first filed last spring — would let data centers choose between two options for paying for new generation infrastructure to ensure the utility has enough capacity to meet grid operator requirements that the added electricity demand doesn’t interfere with reliability.
In both cases, the utility will acquire that capacity through “bespoke resources” built specifically for the data center. The computing facilities technically would not get their energy directly from these power plants or renewables but rather from We Energies at market prices.
Under the first option, called “full benefits,” data centers would pay the full price of constructing, maintaining, and operating the new generation, and would cover the profit guaranteed to We Energies. The data centers would also get revenue from the sale of the electricity on the market as well as from renewable energy credits for solar and wind arrays; renewable energy credits are basically certificates that can be sold to other entities looking to meet sustainability goals.
The second option, called “capacity only,” would have data centers paying 75% of the cost of building the generation. Other customers would pick up the tab for the remaining 25% of the construction and pay for fuel and other costs. In this case, both data centers and other customers would pay for the profit guaranteed to We Energies as part of the project, though the data centers would pay a different — and possibly lower — rate than other customers.
Developers of both data centers being built in We Energies’ territory support the utility’s proposal, saying in testimony that it will help them get online faster and sufficiently protect other customers from unfair costs.
Consumer and environmental advocacy groups, however, are pushing back on the capacity-only option, arguing that it is unfair to make regular customers pay a quarter of the price for building new generation that might not have been necessary without data centers in the picture.
“Nobody asked for this,” said Rogers of Walnut Way. The Sierra Club told regulators to scrap the capacity-only option. The advocacy group Clean Wisconsin similarly opposes that option, as noted in testimony to regulators.
But We Energies says everyone will benefit from building more power sources.
“These capacity-only plants will serve all of our customers, especially on the hottest and coldest days of the year,” We Energies spokesperson Brendan Conway wrote in an email. “We expect that customers will receive benefits from these plants that exceed the costs that are proposed to be allocated to them.”
We Energies has offered no proof of this promise, according to testimony filed by the Wisconsin Industrial Energy Group, which represents factories and other large operations. The trade association’s energy adviser, Jeffry Pollock, told regulators that the utility’s own modeling of the capacity-only approach showed scenarios in which the costs borne by customers outweigh the benefits to them.
Clean energy is another sticking point. Clean Wisconsin and the Environmental Law and Policy Center want the utility’s plan to more explicitly encourage data centers to meet capacity requirements in part through their own on-site renewables, and to participate in demand-response programs. Customers enrolled in such programs agree to dial down energy use during moments of peak demand, reducing the need for as many new power plants.
“It’s really important to make sure that this tariff contemplates as much clean energy and avoids using as much energy as possible, so we can avoid that incremental fossil fuel build-out that would otherwise potentially be needed to meet this demand,” said Clean Wisconsin staff attorney Brett Korte.
And advocates want the utility to include smaller data centers in its proposal, which in its current form would apply only to data centers requiring 500 megawatts of power or more.
We Energies’ response to stakeholder testimony is due on Jan. 28, and the utility and regulators will also consider public comments that are being submitted. After that, the regulatory commission may hold hearings, and advocates can file additional briefs. Eventually, the utility will reach an agreement with commissioners on how to charge data centers.
Looming large over this debate is the mounting concern that the artificial-intelligence boom is a bubble. If that bubble pops, it could mean far less power demand from data centers than utilities currently expect.
In November, We Energies announced plans to build almost 3 gigawatts of natural gas plants, renewables, and battery storage. Conway said much of this new construction will be paid for by data centers as their bespoke resources.
But some worry that utility customers could be left paying too much for these investments if data centers don’t materialize or don’t use as much energy as predicted. Wisconsin consumers are already on the hook for almost $1 billion for “stranded assets,” mostly expensive coal plants that closed earlier than originally planned, as Wisconsin Watch recently tabulated.
“The reason we bring up the worst-case scenario is it’s not just theoretical,” said Tom Content, executive director of the Citizens Utility Board of Wisconsin, the state’s primary consumer advocacy organization. “There’s been so many headlines about the AI bubble. Will business plans change? Will new AI chips require data centers to use a lot less energy?”
We Energies’ proposal has data centers paying promised costs even if they go out of business or otherwise prematurely curtail their demand. But developers do not have to put up collateral for this purpose if they have a positive credit rating. That means if such data center companies went bankrupt or otherwise couldn’t meet their financial obligations, utility customers may end up paying the bill.
Steven Kihm, the Citizens Utility Board’s regulatory strategist and chief economist, gave examples of companies that had stellar credit until they didn’t, in testimony to regulators. The company that made BlackBerry handheld devices saw its stock skyrocket in the mid-2000s, only to lose most of its value with the rise of smartphones, he noted. Energy company Enron, meanwhile, had a top credit rating until a month before its 2001 collapse, Kihm warned. He advised regulators that data center developers should have to put up adequate collateral regardless of their credit rating.
The Wisconsin Industrial Energy Group echoed concerns about risk if data centers struggle financially.
“The unprecedented growth in capital spending will subject [We Energies] to elevated financial and credit risks,” Pollock told regulators. “Customers will ultimately provide the financial backstop if [the utility] is unable to fully enforce the terms” of its tariff.
Jeremy Fisher, Sierra Club’s principal adviser on climate and energy, equated the risk to co-signing “a loan on a mansion next door, with just the vague assurance that the neighbors will almost certainly be able to cover their loan.”
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Back in 2021, Winter Storm Uri resulted in more than 240 deaths in Texas as freezing temperatures shut down gas power plants and pushed the state’s independent electricity grid to the brink of collapse.
It was an example of a worst-case wintertime scenario for the power sector — and of how fossil fuel resources, often touted for their reliability, can falter when they’re needed most.
So when the massive Winter Storm Fern was bearing down on more than half of the U.S. last week, including Texas and much of the Southeast, onlookers braced for a repeat. And while the grid was indeed pushed to its limit, it weathered the storm.
In Texas, efforts to winterize power plants following Uri paid off, and the state avoided forced shutoffs this time around. Texas also has added a tremendous amount of wind, solar, and battery storage over the past few years, helping its grid keep pace amid the blistering cold. It’s true that Fern wasn’t as intense of a storm as Uri, but University of Texas energy professor Michael Webber told KXAN that the current grid likely would’ve avoided much of 2021’s devastation.
In New England, which was hammered with snow and intense cold, the power grid was stable but dirtier than usual: It had to rely heavily on oil, a reserve fuel that is especially polluting.
One big reason? Canadian hydropower, usually a key source, was hard to come by as that nation dealt with its own cold spell, and gas was in short supply, too, as New England homes burned more of it for heating. For what it’s worth, Vineyard Wind — the nearly complete offshore wind farm that just this week defeated a Trump administration stop-work order — provided a notable boost to the grid even in its partially finished state.
But it wasn’t all good news. More than one million people lost power during the storm, particularly in the Southeast, and thousands are still in the dark as of this morning. Power plant shutoffs aren’t to blame, but rather challenges with the grid itself are, including toppled utility poles, iced-over substations, and downed transmission lines.
PJM Interconnection — the nation’s largest grid operator, which spans the mid-Atlantic — suffered the most intense impact. Data analyzed by think tank Energy Innovation suggests that frozen pipelines and other infrastructure curbed fossil-fueled power plants’ output by tens of gigawatts in the region.
This reduced power generation luckily didn’t force PJM to institute rolling blackouts. But it did, as Energy Innovation put it, underscore a clear point: It’s not viable to rely on fossil fuels alone to get through intense winter weather — and the Trump administration’s efforts to block solar and wind while propping up fossil fuels could prove dangerous if taken to their extreme.
Outside the U.S., offshore wind sails ahead
As the Trump administration turns its back on offshore wind, the rest of the world is going full speed ahead. Ten European countries formed a coalition this week to build out 100 GW of offshore wind power, Alexander C. Kaufman reports. It’s all part of an effort to turn the North Sea into“the world’s largest clean energy reservoir,” German Chancellor Friedrich Merz said.
The announcement follows China’s insistence last week that it will continue to build its offshore wind dominance, even after a dig from Trump.
Back in the U.S., there’s at least a smidgen of good news on offshore wind. On Tuesday, a federal judge ruled that Vineyard Wind can resume construction. It’s one of five offshore wind farms that the Trump administration ordered to stop work in December; judges allowed three other projects to continue building last week. Developer GE Vernova says it could face a $250 million loss this year due to Vineyard Wind’s installation delays.
Tribes press on with clean energy construction
Tribes from coast to coast have long suffered inequities in energy access and affordability. Funding issued under the Biden administration was meant to change that by financing solar farm construction, microgrid development, and other projects to help tribes take advantage of their enormous wind and solar energy potential.
That all got a lot harder when the Trump administration canceled billions of dollars in clean energy funding, Canary Media’s Jeff St. John reports. But tribes are still finding ways to push their projects forward, including with help from the Alliance for Tribal Clean Energy, which brings together tribes, charitable foundations, and clean energy financiers.
“The scale of this disruption is undeniable,” Chéri Smith, president and CEO of the alliance, told Jeff. “But we have to do something. We can’t just sit there.”
Chargers keep cruising: The U.S. built more than 18,000 new public EV-charging stations last year despite the Trump administration’s freeze on EV-charging grants and other efforts to derail the EV transition. (Canary Media)
Tesla’s solar pivot: Tesla announces plans to build its own solar panel at its Buffalo, New York, factory, marking a recommitment to home energy as it moves away from EVs. (Canary Media)
Funding climate resilience: Maine lawmakers advance a “climate superfund” bill that would require fossil fuel companies to pay for damages caused by climate change, and Illinois and Connecticut move toward introducing similar measures. (Maine Morning Star, Hartford Courant, Inside Climate News)
Solar coexistence: A new study debunks the myth that solar panels are destroying huge swaths of North Carolina farmland, finding that arrays take up just 0.28% of land that’s classified as agricultural. (Canary Media)
Data centers’ concrete impacts: Building a data center with traditional concrete can result in tons of additional carbon emissions — a fact that’s driving tech companies to start buying low-emissions versions of the material. (Bloomberg)
Nuclear changes: Internal documents show the DOE is quietly overhauling nuclear safety regulations and sharing the changes with affected companies in an attempt to speed development of next-generation reactors. (NPR)
Preserving plants: The Gemini Solar Project outside Las Vegas shows that careful planning can preserve delicate plants and other species when solar farms are built, and even help them thrive. (Grist)
First it got cold. Across New England, temperatures have been almost constantly below 20 degrees Fahrenheit since last Friday night.
Then it snowed. Winter Storm Fern swept through the region on Sunday and Monday, leaving more than two feet of white stuff in its wake in many places.
But despite the extreme weather, the lights stayed on in the Northeast, for the most part.
At a moment when there is copious debate over how, and how much, to strengthen and expand the New England electric grid, this past weekend functioned as a sort of stress test for the system, highlighting both its strengths and its shortcomings. A closer look at how the grid managed to keep us watching football games and charging our phones offers a few key lessons.
The climate challenges posed by Winter Storm Fern cropped up just a week after the long-awaited New England Clean Energy Connect transmission line started sending hydropower from Quebec into the Northeast U.S. Its purpose: to supply more than 1 gigawatt of power to customers in Massachusetts, providing clean energy and cost savings to the state, which has struck a long-term procurement deal with Canadian energy giant Hydro-Québec.
Last Friday and early Saturday, power flowed as expected. But from Saturday afternoon until Monday afternoon, the exports stopped for all but a few hours on Sunday. Quebec, also experiencing bitter cold, needed the power for its own heating systems. In fact, demand in the province was so high that New England began sending it electricity via a transmission line usually used to bring Canadian power into the U.S.
“There was an expectation that there was a higher quantity and more consistent flows than what happened in practice,” said Dan Dolan, president of the trade group New England Power Generators Association. “The timing of this is certainly drawing a lot of attention, just a week into the commissioning of the project.”
Hydro-Québec didn’t do anything illegal or unethical, Dolan said, and its CEO has indicated the company is prepared to pay the penalties outlined in its contract with Massachusetts for not sending power as obligated. Still, this weekend makes clear that the much-vaunted new transmission line might not do as much to alleviate the region’s energy concerns as had been hoped.
As Canadian hydropower stopped coming, New England also had to cope with constrained natural gas supplies. People throughout the region needed the fossil fuel to warm their houses, limiting the supply that was available to power plants and spiking prices. As a result, usually expensive oil generation became the more economical option. Rarely used oil-burning power plants were called into action, producing more than a third of the power flowing onto the grid for some periods. For a sense of scale: Oil-fired generation provided roughly 1% of the region’s power in 2025.
The sudden dependence on one of the dirtiest forms of power supply makes it clear that the region needs to generate more electricity from a wider range of resources, grid experts say. The grid will be more reliable and more economical if it doesn’t have to put so many of its eggs in an expensive, high-emissions basket like oil.
“The cold temperatures and the storm really, really highlight the importance of a portfolio approach,” said Valessa Souter-Kline, managing director of the industry association Advanced Energy United.
Planning for a future of more abundant power supply is all well and good, but the cost and high emissions of burning oil for electricity highlight the need to do more with the grid we have now, said Phelps Turner, director of clean grid for environmental advocacy group the Conservation Law Foundation.
The region needs to expand demand-response programs, he said. These initiatives compensate consumers for scaling back their energy use at times of particularly high demand, freeing up electrons for other customers. Commercial operations might power down some machines or use an on-site generator for a time, while residential customers might hold off on running their dishwashers for a couple of hours or charge their EVs overnight rather than in the early evening.
“We have to be more proactive about managing demand for electricity,” Phelps said. “Those programs aren’t going to solve all of our problems, but they are a tool that needs to be used in situations like this.”
Much of the conversation about the weekend’s grid performance has focused on the lack of power along the new transmission line and the spike in oil-fired generation. However, wind also made solid contributions to the stability of the system. Overnight Friday, into Saturday, more than 1.5 gigawatts of wind power — roughly 10% of New England’s total load — was flowing onto the grid.
Data from grid operator ISO New England does not break out the contributions of onshore and offshore wind. Energy insiders, however, are confident that Vineyard Wind — the nearly completed development off the coast of Massachusetts that’s already sending some power to the grid — played a significant role in wind’s strong performance.
The numbers suggest that offshore wind could live up to its promise of providing a robust power supply, particularly in the winter. That could go a long way in addressing the region’s energy affordability woes: An analysis released in 2025 concludes that Massachusetts utility customers would’ve saved as much as $212 million during the winter of 2024–25 if the region had had 3.5 GW of offshore wind capacity online.
Of course, this potential only matters if offshore wind developments can actually get built. Federal judges have allowed work to resume on four of the five under-construction projects stopped last month by the Trump administration, but federal policies and challenging economic conditions have stalled or scuttled at least three others in development.
This past weekend, however, made a strong case for the value that offshore wind can bring, experts said.
“Here in New England, low temperatures and strong winds tend to travel together,” Turner said. “Offshore wind can be an incredibly important and valuable resource during cold snaps like this one.”
As Massachusetts faces an energy-affordability crisis, one of the state’s biggest utilities is trying a new approach to satisfy growing power demand without blowing out its grid budget and further spiking residents’ bills.
Late last year, National Grid launched a marketplace in Massachusetts that, put simply, lets the utility shop for the best customer-owned solar and batteries, smart EV chargers and appliances, and other distributed energy resources to reduce strain on the grid in specific locations.
The idea is that National Grid can strategically deploy this existing, scattered energy equipment during periods of high demand — for example, drawing power from a home battery, dialing down a business’s air conditioning, or deferring EV charging.
This relief on the grid lets the utility defer or even fully avoid upgrading the wires, transformers, and other infrastructure that deliver power to households. Such costly upgrades are the single biggest driver of rising electricity bills in the U.S.
That’s why National Grid calls it a “non-wires alternative” program — it’s finding things that can defer and reduce the costs of those grid investments.
Unlike the non-wires alternative projects that utilities have been doing for at least the past decade, this one is designed to move much more quickly and cast a much wider net for resources that can stand in for grid upgrades.
“The 2010s version is, you’ve got big players, a single project for the entire need. It’s an old-school utility procurement,” said Josh Tom, National Grid’s director of energy transition solutions. “It’s a closed system, not accessible to everyone. And it can take a long time.”
These slow, burdensome, and costly approaches have yielded only a handful of successful projects over the years. National Grid’s new program, by contrast, is built around a marketplace platform into which companies can bid resources ranging from big batteries to lots of smart thermostats.
From there, National Grid can assess how they could be combined to solve particular grid challenges at different sites on the utility’s distribution network. That should allow it to move much more quickly to find, test, and potentially pay for resources that meet its grid needs, said Nick Watson, National Grid’s director of flexible resource engineering. “We see it as more of a dynamic process,” he said.
The utility’s bidding opportunity will be open through mid-February and target providing grid relief during the summer and winter seasons from 2026 to 2030, Watson said. “We’ll assess those bids, figure out the procurements that meet our needs, using tools we’re trying out for the first time.” Contracts with winning bidders will follow, and tests of the resources are expected to begin this spring, ahead of eligible assets being dispatched in the summer, he said.
The company running National Grid’s new marketplace is the U.K.-based startup Piclo. It does similar work in its home country with National Grid Electricity Distribution, a subsidiary of the same firm that owns National Grid in Massachusetts.
Piclo is a major provider of flexibility-marketplace services in the U.K., a country that analysts say is far ahead of the U.S. on this front, and the company has expanded to mainland Europe and Australia in recent years. It’s also making inroads in the U.S. via its partnerships with Connecticut utilities and with National Grid, which has already used Piclo’s marketplace as part of its “dynamic load management” programs in New York for several years.
“We’ve done this for years in the U.K. and beyond,” said James Johnston, Piclo’s CEO. “But in a lot of the U.S., this hasn’t happened before.”
The potential could be huge, Johnston said. In September, Piclo announced that it had registered across the U.S. a combined 1 gigawatt of distributed energy resources — a term that includes batteries, EV fleets, grid-responsive appliances, and commercial and industrial buildings that can dial down energy use on demand. Companies registering with Piclo include major residential solar and battery installer Sunrun, demand-response provider Enel X, and energy-efficiency startup Budderfly.
Owners and managers of these distributed energy resources can share data on Piclo’s platform about how much power their devices can inject into the grid, store for later use, or put off consuming, Johnston said. The platform will connect those offers to entities — utilities, grid operators, and large customers like data centers that are looking for ways to mitigate their impact on the system — interested in tapping them to solve energy or grid challenges.
Unlike companies that aggregate distributed energy resources and manage them as virtual power plants, “we don’t take a position in the market,” Johnston said. “We’re that party that partners trust to share data with. We’re that matchmaker — we share the right data sets, end to end, across that entire journey. And we’re the adjudicator — whether you’re matched or not, whether you win a contract or not.”
Piclo has proved its bona fides in the U.K., where it has more than 60,000 registered distributed energy resources and has procured more than 2.6 gigawatts of flexible capacity to date.
For National Grid, Piclo’s marketplace opens up a world of possibilities, Tom said.
“They’re helping us communicate our needs to the market,” he said. “Their open marketplace is a new procurement approach.”
The current program round is looking to secure about 25 megawatts of flexibility, he said. That’s less than half the 52 megawatts secured by the largest non-wires alternative program in the country — the Brooklyn-Queens Demand Management program, launched in 2014 by utility Con Edison to relieve a congested New York City substation.
But National Grid is seeking to solve grid problems at 23 locations, each with a distinct set of needs, Tom said. Some sites require only a small amount of overload relief on a substation or circuit during a handful of hours in the summer or winter. Others may require non-wires alternatives that can be dispatched more frequently or that expand over time as new customers increase peak demands on a specific part of the grid.
One key benefit of working with Piclo’s marketplace is that it helps National Grid mix and match the capabilities of a number of different bidders, rather than forcing a single bidder to meet them all, Tom said. “What we’re really trying to do in this approach is open up the possibility for portfolios of bids that work alongside each other to meet the need in a couple of ways,” he said.
“Let’s say you have a 3-megawatt need for a summer season, a four-hour window or eight-hour window on certain days,” he said. “We want to open the possibility, even if you don’t have 3 megawatts, to bid in your 1 megawatt,” which the company will combine with megawatts from other providers to make up the difference. “That opens opportunities for those who can’t enter the market otherwise.”
Portfolios can be built across time as well as across scale, he added. “Let’s say it’s a four-hour window. If you can only provide 3 megawatts for the first two hours, someone else could provide the megawatt for hours three and four — and we have a complete portfolio.”
Once National Grid selects the distributed energy resources it wants to procure from the Piclo marketplace, the utility will have to run them through a gauntlet of tests to ensure they’re reliable enough to relieve grid stresses.
“There are a bunch of test dispatch requirements before we run a real event or renumerate a party for services provided,” Tom said. This spring and summer will be dedicated to running those tests and to fine-tuning the “contractual structures with the right characteristics to ensure we’re comfortable in the future.”
Regulator support has been critical in setting this up, he added. Massachusetts’ three major investor-owned utilities are required to develop grid-modernization plans under a 2022 energy and climate law that sets the state on a course to net-zero carbon emissions by 2050. In approving those plans, the state let utilities create grid services compensation funds that can pay for non-wires alternative programs, he explained.
Launching Piclo’s marketplace isn’t National Grid’s only attempt at a non-wires alternative program in Massachusetts. The utility is also expanding a 7-year-old program called ConnectionSolutions, which regulators required all the state’s investor-owned utilities to deploy. This program is designed not to relieve local grid constraints but rather to reduce overall peak demands on power plants and transmission grids. In that role, it has delivered hundreds of megawatts of grid relief during summer heat waves and become a national model for virtual power plants.
Now, National Grid wants to see if the program can also help defer or avoid upgrades at specific grid substations and circuits. The expanded version, ConnectedSolutions+, offers customers incremental incentives to install and sign up resources in areas with local grid needs.
What distinguishes ConnectedSolutions+ from National Grid’s work with Piclo is that the latter program targets not just customers with smart thermostats, EV chargers, grid-responsive appliances, and battery storage but also larger grid-connected energy assets like community solar arrays and batteries, Tom noted. Massachusetts has a lot of community solar that’s been challenging to connect to the grid, and the state has been working for years to find a way to use those solar and battery systems to relieve grid stresses.
Importantly, National Grid’s first round of non-wires alternatives is targeting spots that aren’t in dire need of grid upgrades, Tom said. “We’re not putting at risk the safety and reliability of the network by doing this.”
Another key target for National Grid is for “bridge-to-wires” needs, Watson said — spots where new customers that use a lot of power want to plug into the grid and “you can’t build the infrastructure quickly enough” to accommodate them, he said. Distributed energy resources can bridge the grid overloads until the necessary upgrades take place.
One big question that utilities must grapple with is when a non-wires alternative makes financial sense. After all, a utility must pay the customers handing over the reins to their distributed energy resources. Utilities also can’t avoid upgrading their grids forever — and changing circumstances can wreak havoc on the assumptions that inform how much a non-wires alternative is worth.
Utilities must account for a ton of variables to determine the value of deferring grid investments versus biting the bullet and investing in must-have upgrades or expansions, Watson said. “We’ve been developing methodologies to help us do that over the course of this year,” he said. “It depends on what the use case is.”
Although non-wires alternatives are catching on, they face an uphill battle. Regulated utilities in the U.S. earn guaranteed profits on every dollar they invest in their grid infrastructure — an inherent disincentive for them to seek out alternatives to grid investment, even if they could save customers money over time.
But from Watson’s perspective, utilities will have to find better ways to manage their grids in the long run, as power demand grows, distributed solar and batteries proliferate, and electric vehicles and buildings add both new strains and new sources of flexibility to the system.
“Traditionally, it isn’t the business model of the investor-owned utility to leverage flexibility,” he said. But to meet state goals around electrification and emissions reductions, “we’re going to have to change the way we manage our network. We can’t just continue to build out the network in the traditional ways we have in the past.”
A leading data center developer and a pioneering Texas battery owner have formed a mutually beneficial partnership that models a new way for energy storage to accelerate the AI infrastructure build-out.
Storage firm Eolian completed the Chisholm Grid battery in 2021, placing 100 megawatts/125 megawatt-hours of capacity next to a substation 7 miles northwest of downtown Fort Worth. The site was able to discharge its full capacity for just over an hour — a design that worked well for the first wave of big Texas grid battery projects, which could make good money by providing rapid-response ancillary services.
Another 15 gigawatts of storage have piled into Texas since then, and revenues from those once-lucrative ancillary services have plummeted given the glut of batteries. Meanwhile, the market managed by the Electric Reliability Council of Texas, or ERCOT, is changing in other ways that reward longer-duration batteries.
So Eolian CEO Aaron Zubaty came up with a plan to meet the moment. “We’ve already taken the battery storage site offline so that we can upgrade the facilities and ultimately expand the usable duration,” Zubaty said. But he added, “Even though the battery is offline, the site is proving that well-placed infrastructure can create ongoing value across multiple use cases.”
That’s right, Zubaty found a way to get paid for not using a battery: by temporarily lending the site’s grid connection to data center developer CyrusOne. The Dallas-based company runs 55 data centers around the world and is currently building 10 more, including one next door to Chisholm. That data center, dubbed DFW7, could come online later this year.
“Getting a new connection to the grid at the scale of this site, more than 100 megawatts, that’s generally a multiyear process,” CyrusOne CEO Eric Schwartz told Canary Media.
But in this case, he noted, CyrusOne will activate its data center campus one to two years earlier by using Eolian’s grid interconnection while that firm renovates its battery plant.
“Time to market matters, but also certainty,” Schwartz said. At Chisholm, “the grid infrastructure is there and ready to go.”
The power sector has become consumed with the question of how to meet the AI industry’s rapidly ballooning electricity needs. One common assumption is that new gas plants will pave the way for the AI revolution, but gas turbines face yearslong backlogs that defy the “speed to power” desired by AI companies. Ask any battery developer today and they’ll tell you they have booming business prospects with data center customers, but hardly any of these have been made public, aside from a deal between energy storage specialist Calibrant and Aligned Data Centers in Oregon, and now the new Eolian–CyrusOne agreement.
This arrangement emerged from discussions in 2023, and CyrusOne broke ground last April. If construction goes to plan, the rebuild of the battery will wrap up around the time that wires utility Oncor finishes its grid upgrades for CyrusOne to get its own hookup. Then Eolian can get back to bidding into ERCOT, with a duration long enough to qualify for the forthcoming Dispatch Reliability Reserve Service, which requires power plants to discharge for at least four hours.
Chisholm runs on Samsung battery cells with the nickel-manganese-cobalt chemistry, and they have sustained very little degradation over five years of service, Zubaty said. The initial plan is to keep those original cells but restructure them: By dropping the capacity to 25 megawatts, Eolian can lengthen the discharge duration to the five-hour mark. Then it can add in new batteries to fill up the remaining space; the site can hold up to 250 megawatts, based on its grid-connection agreement.
It’s not yet clear if this deal will start a new trend or constitute a fruitful anomaly. There are only so many batteries in need of repowering in places eyed by data center developers. If storage developers get too comfortable leasing out their grid connections, they’ll reduce themselves to glorified landlords. But it says something about the interplay between data center development and battery storage, and how the two could work together to make the electricity network more nimble.
Texas generates tens of gigawatts of solar and wind power far from its cities, then has to send that electricity to consumers, which can cause congestion on transmission wires. Years before the Texas storage boom or the recent AI phenomenon, Eolian looked for areas where batteries could improve utilization of the transmission grid by arbitraging electricity between times of plenty and times of scarcity.
“Our primary strategy for developing battery storage sites in 2016 and 2017 was to start ringing every major city we could with queue positions in locations that were likely future transmission constraints or that were a bridge between load growth and far-flung generating resources,” Zubaty said.
CyrusOne also wanted to be near the population center. Some of its customers benefit from running their computation closer to users. And CyrusOne itself sees a major benefit in building near Fort Worth’s population of skilled technicians, both for construction and ongoing operations, Schwartz said. The city’s authorities have also been supportive of data center construction, as has Texas more broadly.
On top of that, CyrusOne was attracted to the same high-capacity power infrastructure that lured Eolian to that node on the grid years ago. Those heavy-duty wires, and what Zubaty called “an epic substation,” make this a good place to charge a battery or power a huge data center without having to do too much upgrading.
“Five to 10 years ago, we would’ve located the site based on other criteria … and worked with the utility to bring power to the site,” Schwartz said. “Now, we’re bringing data centers to the power rather than trying to bring the power to the data centers.”
Other early entrants into the ERCOT battery market face the same pressures that Eolian responded to, and if they decide to repower their batteries, more data center developers could pursue similar opportunities to come online faster. Admittedly, the geography and timing for such a solution have to line up just right, but these partnerships could prove a critical stepping stone in the headlong rush to build computing infrastructure.
Nearly 10 years after Massachusetts announced plans to buy 1.2 gigawatts of carbon-free hydropower from Canada, the clean electrons are finally set to start flowing into the state.
As soon as this Friday, the New England Clean Energy Connect transmission line could begin commercial operations.
The 145-mile project, extending from the Canadian border to the southern Maine city of Lewiston, will function as something like an enormous extension cord, plugging the New England grid into a supply of electricity generated by energy giant Hydro-Québec. The new supply is expected to save the average residential customer in Massachusetts $18 to $20 per year and move the state closer to its goal of net-zero emissions by 2050.
“This is a significant moment for clean energy in New England,” said Phelps Turner, director of clean grid for the Conservation Law Foundation.
Avangrid, the developer of the transmission line, told Maine utility regulators earlier this month that operations are scheduled to begin on Jan. 16. Work is underway to meet that target.
“Teams are busy on both sides of the U.S.-Canada border,” said Hydro-Québec spokesperson Lynn St-Laurent. “We have been actively testing the equipment for the past several weeks.”
Following a tumultuous year for clean energy projects, the completion of the controversial transmission line is both a rare triumph and a case study in the challenges of balancing decarbonization and the preservation of wild lands. It’s also an uncommon example of transmission getting built in the U.S., where it has proven difficult to construct the massive power lines needed to deliver new electricity supply to population centers.
The project has its roots in a 2016 Massachusetts law that called for the state to procure 1.2 gigawatts of Canadian hydropower, or other renewables, and 1.6 gigawatts of offshore wind energy. The first idea for importing power from the north involved working with a planned 192-mile transmission line through New Hampshire. However, the project was scuttled in 2019 by public outcry against the prospect of chopping a path through some of the state’s treasured forests.
Massachusetts then looked east, to Maine, to find a route for the transmission line. Similar objections quickly arose, with opponents in the state filing a series of legal challenges. In 2021, Maine voters approved a ballot referendum effectively blocking the project. Work froze until August 2023, a few months after a jury unanimously ruled the project could move forward.
The delays spiked the project’s price tag. Before the line could start providing power, the developer, state regulators, and utilities had to come to an agreement about how those costs would be covered. In early 2025, they settled on terms that increased the price utilities would pay by a total of about $521 million, but ensured consumers would still see savings.
“The project faced many challenges over many years, and it survived all of them,” Turner said.
In addition to the modest monthly savings expected for Massachusetts utility customers, the influx of hydropower should keep rates down for consumers throughout New England by pouring lower-cost electricity into the market that will put downward pressure on prices, right at a time when rising energy bills have become a major issue, Turner said.
Questions remain, however, about how much new power the project will actually bring to the New England grid.
Hydro-Québec already sends power into the region on a separate transmission line, though these exports have decreased in recent years, even stopping almost entirely for a period in 2025. It’s possible that meeting its commitment to deliver along the New England Clean Energy Connect line will mean Hydro-Québec chooses to send less power along other pathways, said Dan Dolan, president of regional trade group the New England Power Generators Association. The net increase in clean power may be lower than anticipated.
“The change in flows over the last several years, particularly in 2025, do not leave me optimistic that Canadian hydro is here to save the day,” Dolan said.
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