In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.

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Lightshift Energy is constructing a second battery project for the city of Danville, Virginia. (Sanjay Suchak)

In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.

Virginia — the world’s data center capital — is starting to catch on to the big-battery trend. But a new project by local electric providers in the state underscores that much smaller storage projects have value, too: They’re designed to fill specific community needs and — due to their size — relatively quick and low-cost to build.

The Blue Ridge Power Agency, which serves a string of nonprofit utilities in central and western Virginia, is set to go live this summer with a collection of five batteries of about 5 megawatts each. The systems will help two rural electric co-ops and the city of Salem’s utility save money by storing power when it is cheap and abundant. They can then rely on that saved-up power when high demand on the grid spikes prices.

All in all, the projects are predicted to save the member utilities $100 million over the batteries’ 20-year lifespan, addressing long-held local concerns over rising costs.

Lightshift Energy, the storage developer building the five batteries, has formed a bit of a niche working with small, member-owned utilities, said Rob Greskowiak, the company’s chief commercial officer.

These nonprofit utilities are rooted in their communities and intimately familiar with their customers and grids, Greskowiak explained. ​“These municipalities are like, ​‘Listen, I know the 50,000 people that live here, and I know that this distribution circuit is not reliable and that our energy costs are going up,’” he said. At Lightshift, ​“we can find a very acute problem and solve it with 5- to 30-megawatt-sized batteries.”

Small cooperatives’ investment in storage extends well beyond Virginia. As of the first quarter of 2025, 136 battery storage projects sponsored by co-ops were underway or operational in 27 states, according to an analysis by the National Rural Electric Cooperative Association. It predicts that storage deployed by co-ops will more than triple, from 439 megawatts of capacity to 1.5 gigawatts, in the next three years.

The smaller batteries these co-ops tend to favor are cost-competitive because they avoid the need for expensive network upgrades, don’t require expensive long-lead equipment, and are sited on very small footprints, Greskowiak said.

Their minimal impact means they’re often quicker to permit and gain community acceptance than larger versions, he added. ​“If you’re putting in a battery that isn’t that big in a spot that already has that infrastructure, people aren’t really batting an eye on that.” The company can typically go from initial discussions with a utility to operations in 18 to 24 months, he said, significantly faster than transmission-scale assets.

The rapid setup is particularly meaningful in Virginia as data center plans flood the state and send power-demand forecasts ballooning, said Nikhil Kumar, program director at GridLab, a nonprofit that provides technical support on the clean energy transition in a range of settings. ​“Speed to power,” he said, ​“it’s in the zeitgeist right now.”

While reining in power prices is the main motivation behind the Blue Ridge Power Agency’s midsize-battery buildout, Greskowiak emphasized other advantages as well. ​“Battery storage is best when it acts like the Swiss army knife that everybody talks about,” he said.

A key benefit includes storing electrons from solar and wind and dispatching them when the sun fades or the breeze dies down, enabling even more renewable energy deployment. ​“Local homeowners, local businesses, local community solar gardens can add to that grid more sustainable energy,” he said, ​“because we’ve released and unlocked more capability at those substations to host more solar.”

Batteries are also getting cheaper and cheaper, with the average price of a lithium-ion battery pack dropping by nearly 80% over the last decade. And even though President Donald Trump and congressional Republicans slashed incentives for wind and solar last year, they retained the 30% credit for storage well into the next decade. ​“That’s another big advantage,” Kumar said.

Lightshift Energy’s Danville II project (Sanjay Suchak)

The Blue Ridge Power Agency project is just the latest example of a small Virginia utility quickly deploying batteries. Lightshift has partnered with the city of Danville on two systems that total over 20 megawatts and are expected to save customers $70 million; the first went online in 2022, and the second is under construction. Last year, developers announced two similar-sized projects for a co-op on the state’s Eastern Shore.

Co-ops’ increased interest in storage comes as the state directs its two investor-owned utilities to ramp up investments, too: A law recently enacted by Gov. Abigail Spanberger, a Democrat, requires Dominion Energy and Appalachian Power to build nearly 17 gigawatts of battery storage by 2045; their former target was 3 gigawatts by 2035.

All these planned storage investments will be necessary to ease grid strain and bring down costs, Kumar said. ​“Especially in Virginia, with the large loads and the data center growth, we’ll need a lot of these projects to help the grid.”

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The United States has taken one of its biggest steps yet to encourage the construction of commercial microreactors — the latest move in its broader push to overhaul the country’s nuclear regulatory processes.

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U.S. Nuclear Regulatory Commission Chair Ho Nieh speaks at the annual Regulatory Information Conference in March. (U.S. Nuclear Regulatory Commission)

The United States has taken one of its biggest steps yet to encourage the construction of commercial microreactors — the latest move in its broader push to overhaul the country’s nuclear regulatory processes.

In late April, the U.S. Nuclear Regulatory Commission released its draft rule for a proposed new licensing pathway for commercial reactors. Known as Part 57, the regulation tailors the application process to account for the fundamental differences between a so-called microreactor, designed to generate 20 megawatts of electricity or less, and a behemoth traditional reactor such as a Westinghouse AP1000, which pumps out 60 times as much power. The rule, which would allow eligible projects to obtain dual permits to both construct and operate a reactor, is meant to encourage fleet-scale deployment of the technology.

While no commercial microreactors are in operation anywhere in the world today, some corners of the U.S. industry see them as a way to slash the time and money it takes to build a nuclear plant by harnessing the benefits of assembly-line production.

The proposal comes after a string of actions by the NRC to speed up the regulatory process for nuclear reactors that use different designs or technology than the country’s existing fleet of 94 large-scale light-water reactors. The regulatory changes, spurred by a Biden-era law and encouraged by the Trump administration, have been widely celebrated by the industry — but they have rankled some who fear the NRC is jeopardizing safety by moving too fast.

In March, the NRC shook up its licensing pathways for the first time in decades. Dubbed Part 53, the final rule was the first new set of regulations to address initial reactor licensing since 1989 — and the first major update to reactor licensing standards since 1956.

Part 53 is an optional alternative to two existing frameworks, Part 50 and Part 52. The former has long been developers’ preferred pathway for new reactors, but it grants only construction permits — not operating licenses. Part 52 was created to speed things up by allowing a dual construction and operating license to be obtained in one shot, but that pathway carried risks if the developer deviated even slightly from the approved design.

Neither option made much sense for the wave of advanced nuclear reactor firms that have attracted enormous amounts of funding and industry hype over the last decade. Part 53 was specifically designed to accommodate these technologies, including small modular reactors, microreactors, and those that use coolants other than water.

“With all these new and advanced technologies coming, we needed something more flexible,” said Mike King, the NRC’s executive director of operations. ​“That’s what Part 53 does. It provides us a framework that’s not so focused on large light-water reactors.”

Last week’s proposed Part 57, he said, ​“takes what we’ve done with Part 53 and scopes it appropriately for these microreactors that have a much lower risk profile for the public and could be licensed in a more streamlined fashion.”

Part 57, set to be added in the coming days to the Federal Register, won’t be operational until the rule is finalized in the next few months. But already, several microreactor developers have put out statements indicating they plan to apply for NRC licenses through the new pathway.

Central to the rule is the ​“risk-informed” change that Part 53 pioneered.

Rather than require the same safety protocols and infrastructure that the NRC mandates for traditional light-water reactors, Part 57 sets a target that developers are free to meet in a variety of ways.

Like Part 53 before it, the rule also limits the radiation emitted from an accident to 1 rem — the same amount of radiation from a CT scan. But while Part 53 institutes those limits for 96 hours after an accident occurs, Part 57 mandates that operators stay under that limit only throughout the duration of the accident. For some companies, meeting that standard could mean building the concrete containment vessels that house traditional light-water reactors. While certain microreactor designs — either those that are extremely small or those made of or fueled with material that cannot melt down — might be able to avoid having to build such containment domes.

Traditional reactors regulated by Part 50 are required to keep radiation emitted from an accident to 25 rems — which is the maximum recommended lifetime dose of radiation.

In that way, Part 57 is narrower than the original pathway, said Adam Stein, the director of nuclear energy innovation at the Breakthrough Institute, because ​“to even get into Part 57, you’d have to stay under 1 rem for the entire duration of the accident, not just 96 hours. So it’s inherently more restrictive.”

Many of the changes now underway at the NRC stem from the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy (ADVANCE) Act, which President Joe Biden signed into law in 2024 after the Senate, in a rare show of bipartisan zeal, almost unanimously approved the bill. The statute overhauled the NRC’s mission statement for the first time, directing the agency to consider the threat of holding back nuclear power in the U.S. in addition to the risks associated with radiation. Work on Part 57 began under the previous administration.

Last May, President Donald Trump supercharged those efforts with a series of executive orders designed to defibrillate the flatlining nuclear sector as China’s industry runs laps around the U.S., and Russia dominates exports to newcomer countries seeking to build their first atomic power stations.

Among those orders was one to restructure the NRC, requiring the agency to do more, faster, with fewer staff and more direct oversight from the president. Presidents have always been able to appoint commissioners but have historically had little influence over the agency’s day-to-day workings. The White House directive raised alarms, particularly as Trump sought to bring previously independent agencies like the NRC and Federal Communications Commission under direct control. His decision to fire a Democratic NRC commissioner a month later only deepened fears.

Career staffers at the NRC have blown the whistle over concerns that the Department of Government Efficiency, which billionaire Elon Musk established shortly after Trump’s inauguration, was wielding too much internal influence and slashing necessary parts of the regulatory apparatus.

“It’s hard to know if they are getting rid of unnecessary processes or if it’s actually reducing public safety,” one official working on reactor licensing told ProPublica last month. ​“And that’s just the problem with going so fast — everything just kind of gets lost in a mush.”

But Caroline DeWitte, the co-founder of Oklo, a nuclear developer favored by Silicon Valley, said skeptics of overhauling the NRC fail to recognize the extent to which the agency in its previous form was ill suited to oversee construction of new types of reactors.

The NRC official who rejected Oklo’s application in 2022 told Bloomberg last year that the company’s submission was one of the worst ever reviewed. But DeWitte, who leads the company as chief operating officer alongside her chief executive officer husband, Jake DeWitte, said the NRC couldn’t understand that Oklo’s reactor and similar designs have ​“inherent safety features.”

“Literally, the physics of the metal made it safe,” Caroline DeWitte told Canary Media. ​“So, how do you account for that? Even with passively safe features, the NRC forces you to assume that it can fail. But, like, is it reasonable to assume metal is not metal anymore? Those are the types of questions we were asking — how do we put that in a risk analysis?”

Among the more controversial regulatory changes proposed at the NRC is the move to overhaul the way radiation safety is measured altogether.

For years, the dominant rule has been for any radiation exposure to be kept as low as reasonably achievable, called ALARA. It’s based on the assumption that the more exposure someone faces, the higher the risk of cancer or other disease.

That assumption stems from the highly contested ​“linear no-threshold model” from the 1950s, which assumes that exposure to radiation at any level causes harm. Still, no one has yet determined a better alternative on which the country — and, more broadly, the world, which has long followed the U.S. lead on nuclear regulation — can agree.

The NRC has been treading lightly so far: Its proposed rule has been pushed back seven times already and is now due out on June 24.

Paul Dickman, who served as chief of staff to the NRC’s chair from 2006 to 2010, said he is not concerned that his former agency will approve anything that doesn’t stand up to rigorous testing.

“The NRC staff is being creative, and that’s a good thing,” he said. ​“Some people may worry. But I have high confidence in them. At the end of the day, you still have to prove your point on safety. That’s the bottom line.”

The strategy appears to be bearing fruit. In what NRC Chair Ho Nieh called a ​“milestone” that ​“proves we can deliver results quickly without compromising safety,” the agency just approved Duke Energy’s application to run its Robinson nuclear plant in South Carolina for 80 years. It was the fastest license renewal in the NRC’s history.

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When it comes to electric vehicles, old is gold.

In the U.S., sales of new EVs are slumping — but more used EVs are being driven off the lot than ever, per Cox Automotive data. With hundreds of thousands of battery-powered vehicles coming off leases soon, the used EV market is set to accelerate even further in the years to come.

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Although Americans still buy a lot more new EVs than used ones, the Cox data shows the gap beginning to close: Used EV sales jumped by 34% in 2025, compared with the prior year, as new EV sales shrank a bit. Overall, electric models made up nearly a tenth of new vehicle sales in the U.S. in 2025, and about 2% of used car sales.

A combination of factors explains why used EVs are on the upswing while new ones are stagnant.

For one, a lot more used EVs are on the market these days than in the past. About 300,000 EVs will come off of leases this year, up from 123,000 last year, and Cox expects another 600,000 to do so in 2027. Not all of those will hit the used car market, but many will, providing a rush of inventory that helps drive down prices.

Speaking of prices, on average a used EV is now basically at price parity with a used gas car. That’s a big deal: Up-front cost is one of the main barriers preventing people from buying battery-powered vehicles, which are typically cheaper to drive and maintain but have long been more expensive than similar gas-fueled models.

A new EV is still about $6,500 more than a new gas car, on average. Consumers used to be able to shave $7,500 off the EV price with a federal tax credit, but the Trump administration did away with that incentive in September.

The rise of used EVs is a rare positive signal for the American vehicle-electrification effort.

While new EV sales hit record highs under the pro-EV Biden administration, adoption was slower than expected, causing some automakers to walk back commitments to churn out electric models. When President Donald Trump took office last year and tossed out the tax credit along with a bunch of other supportive regulations, it added fuel to the fire.

Some analysts expect EV sales to surge as fallout from the war in the Middle East spikes oil and gas prices worldwide. In the U.S., the average cost of a gallon of gas is now well over $4 a gallon — and climbing — and in some countries, fuel shortages have spurred driving bans and fuel rationing. So far, the early evidence suggests that those expecting an EV boom are on to something.

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