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Energy storage is having a moment — but the batteries that are taking off today only have enough juice to provide a few hours of grid power. Developers technically could stack up more batteries for longer-term storage, but that gets prohibitively expensive. For a renewables-dominated grid to ride out days of poor solar production or even just an entire night, a breakthrough in cost-effective, longer-term storage is needed.
Over the last couple decades, venture capitalists have recognized this transformative possibility and heaped billions of dollars into the sector known as long-duration energy storage, or LDES. They have little to show for their efforts. The startups that haven’t gone bankrupt have built some factories and early installations, but have not built any particularly large-scale projects, at least in the U.S.
A few weeks ago, I saw something in the desert outside Reno, Nevada, that got me thinking the investors and startups may have been barking up the wrong tree all along.
Former Tesla Chief Technology Officer JB Straubel unveiled a surprising new project in June at the Tahoe campus of his lithium-ion recycling company, Redwood Materials. Instead of ripping apart old electric vehicle battery packs, his engineers arranged them across a patch of desert and hooked them up to an adjacent solar field. This assemblage now stores so much clean power that it can run a small on-site data center, rain or shine, night or day.
In other words, instead of inventing a brand-new technology tailored for long-term storage, Redwood made it way cheaper to stack enough time-tested lithium-ion batteries to accomplish that goal.
Unveiling this new business line, Straubel wasn’t just diversifying his revenue streams. He was staking claim to the long-duration storage market writ large.
“We’re confident this is the lowest-cost storage solution out there,” Straubel said. “Not only just lower than new lithium-ion batteries, but lower than compressed-air energy storage, lower than iron-air, lower than a number of these other ones that carry a little more technology risk.”
As he spoke, Straubel pointed at a bar graph depicting the costs of those types of LDES technology, as well as thermal storage, pumped-hydro storage, and flow batteries. Naturally, the chart showed his used batteries clocking in cheaper than all of them.
It’s a big claim. Second-life battery development is even newer than the LDES field; prior to Redwood, only a handful of companies, like B2U Storage Solutions and Element Energy, had built large-scale second-life storage plants, and those were just in the last few years. The sector has a lot of work to do to convince customers and financiers that the gently used battery packs can be trusted to hold up over years of service. And with new lithium-ion packs getting ever cheaper, the discount offered by used batteries may prove tenuous.
Still, Straubel’s first operating project, which holds 63 megawatt-hours of energy storage, is already bigger than any novel battery installation in the U.S. If Straubel takes this concept mainstream, it could revolutionize the arms race for long-duration storage — and radically improve the odds of running the economy on a largely renewable grid.
At the June event, Straubel essentially asserted that his band of desert engineers, in just a few months of tinkering, has outmaneuvered the researchers and companies working on long-duration for decades.
That deserves some scrutiny — but even pinpointing the costs of the competition is challenging.
“There are a lot of flavors of long-duration storage. What all of them have in common is that actual deployments have been very limited up until now,” said Pavel Molchanov, who analyzes cleantech companies for financial services firm Raymond James. “To make any clear-cut statements about which particular flavor is cheaper than any other would be quite premature.”
Redwood says its second-life battery installations cost less than $150 per kilowatt-hour today, for systems that can deliver power over 24 to 48 hours. The company’s datapoints on the prices of other battery types were drawn from BloombergNEF’s 2024 analysis of the LDES field, augmented with Redwood’s internal estimates for what a complete iron-air system would cost today, since that technology isn’t yet commercially available.
Iron-air is under development, most famously, by Straubel’s former Tesla Energy compatriot Mateo Jaramillo at Form Energy, a VC darling that’s raised more than $1.2 billion to date. Redwood calculated iron-air costs at higher than $150 per kilowatt-hour, but Form has stated its intentions to sell batteries below $20 per kilowatt-hour when its factory reaches full production scale.
It’s worth noting that not all these technologies are directly comparable, because companies design and market them at different durations based on their technical sweet spots. If a technology works especially well at, say, 12 hours duration, the company might not even sell it for 48-hour configurations.
“Part of the issue with comparing long-duration storage systems and prices is that every company will give you their price point for a different duration,” said James Frith, a longtime battery analyst now at VC firm Volta Energy Technologies. “Then you’re thinking, how do I normalize this? How do we get to a base point that is comparable amongst the technologies?”
Epistemological issues aside, Redwood accurately diagnoses that the LDES sector’s struggle to deliver real installations at super-low cost leaves an opening for new competitors.
Brand-new lithium-ion batteries aren’t economically viable at longer durations, though their limits keep expanding as battery prices fall.
“Lithium-ion storage systems with longer durations require more battery cells, making the system capital-intensive and less economically competitive compared to emerging long-duration storage alternatives,” said Evelina Stoikou, head of battery technology and supply chain research at BloombergNEF.
Pumped-hydro and compressed-air energy storage work for longer durations, but they are huge, billion-dollar infrastructure projects of the sort that don’t get built anymore in the U.S. (Canadian company Hydrostor is attempting to break that curse with a $1.5 billion, 500 MW/4,000 Mwh compressed air project in California; if it gets permits to build, it might be online by 2030.)
Flow batteries — which store energy in tanks of liquid electrolytes — have been kicking around for decades with some success in China, where they benefit from government favor. In the U.S., they’ve not gained much traction.
Meanwhile, many LDES startups have made the strategic error of designing exotic storage solutions to eke out a few more hours, under the incorrect assumption that lithium-ion would never be able to compete at four, then six, and then eight hours.
Take ESS, which has developed an iron-based flow battery since 2011: Despite leaning into “long-duration” branding, the company was selling an Energy Warehouse with a bit over six hours duration, and only this year announced a “strategic shift to the 10+ hour product.” (Its board members had to throw in more cash last month to sustain the company through that shift, and gamely agreed to forgo personal compensation for the year.)
The LDES companies most vulnerable to competition from Redwood are the ones that aren’t actually very long-duration, and which haven’t gotten big enough to make their products cheaper.
That’s not to say the other LDES contenders are left quaking in their boots.
“We’re a long way away from proof that second-life batteries are a proper utility-grade asset, capable of 20 years of daily cycling,” said Ben Kaun, who for years analyzed LDES technologies for the Electric Power Research Institute and now works for battery startup Inlyte Energy. “I don’t see an existential threat to LDES.”
The sector has even been showing signs of life, at least compared to its dismal track record from the preceding decade. Form completed its factory in Weirton, West Virginia, and broke ground on its first commercial deployment, in Minnesota, last summer. The company plans to deliver its first batteries to the project in the coming weeks, for commissioning this fall. Over in the Netherlands, a Dutch startup called Ore Energy recently installed a small 100-hour system of its own iron-air battery, based on research at the Delft University of Technology.
Flow batteries have built up considerable installed capacity in China, but that trend hasn’t gotten much coverage in English-language press, said Eugene Beh, CEO and cofounder of California-based flow-battery startup Quino Energy. His strategy is to leverage the now-mature supply chain for flow-battery equipment but to drop in an electrolyte based on quinones, commonly used in clothing dyes, instead of the more expensive vanadium that’s popular in China.
Italian startup Energy Dome has moved swiftly from demo to commercial operations with an iconoclastic design: It stores energy by compressing carbon dioxide in a controlled environment; decompressing it turns a turbine and generates electricity. After building a pilot and a commercial project in Sardinia, Energy Dome just announced an equity investment from Google for an undisclosed amount and a commitment to build its systems to power Google’s data center expansion around the world.
These more out-of-the-box LDES companies might take solace in a few limitations that second-life battery developers must overcome to mount a serious challenge.
Second-life companies take hundreds of batteries from different manufacturers, with different patterns of wear and tear, then operate them all in concert. If that was easy, more people would be doing it by now. Firms that get this wrong could start fires, and fire safety is one of the key arguments used against lithium-ion installations, both by rival technologists and the general public.
Then again, Straubel has as much experience as anyone with the inner workings of lithium-ion batteries. At Tesla, he built the nation’s leading electric-car company and a wildly successful stationary-storage business with the Powerwall and Megapack.
Then there’s the question of longevity. The batteries were pulled out of vehicles for a reason: usually due to their capacity degrading, though other problems develop with age, like higher internal resistance, which makes batteries heat up during discharge. If second-life packs need to be swapped out too frequently, it undercuts the ease and cheapness of the model.
That leaves the matter of supply. Success in second-life depends on a steady and cheap source of gently used EV packs. Here Redwood has a unique advantage, in that the company was constituted to collect the nation’s battery waste and recycle it. Straubel said Redwood was receiving less than 1 gigawatt-hour of used EV packs two years ago, and now is pulling in more than 5 GWh per year.
The available supply of used EV packs is “going to follow roughly the same curve as electric vehicle adoption, but lagging by, let’s say, 10 years,” Frith said. “So we are going to start seeing the volume of packs growing, and I think the real volumes start to kick in closer to 2030.”
Indeed, he added, the growth in volume of used EV packs could parallel the growth of demand for long-duration storage: Few customers buy it now, but many analysts expect demand to grow by the end of the decade as renewables saturate the grid.
It’s too soon to know if used EV batteries will actually wipe the floor with the more unconventional long-duration battery technologies. But the scale and price point of Redwood’s first project announces them as a force to be reckoned with in this arena.
In doing so, Redwood puts a new spin on an energy-storage maxim that venture capitalists keep forgetting, or simply ignoring: Lithium-ion always wins.
Challengers that rely on different chemistries have to build up from negligible production scale and convince customers to take a chance on a design that few people have seen before. It’s a clear uphill battle.
Lithium-ion batteries, in contrast, command an unmatched and ever-expanding scale of industrial production, mostly in China but increasingly in the U.S. too. That manufacturing juggernaut unlocks incremental gains from economies of scale and continual innovation. It also confers consumer confidence, because the technology has such a clear track record of performance.
“Compared to most experts’ predictions, the costs have gone down faster and the performance has improved faster for lithium-ion than people predicted 10 years ago,” said Jeff Chamberlain, who helped the Department of Energy license battery technology to General Motors and LG Chem back in the late 2000s, and now invests in storage technologies as CEO of Volta Energy Technologies.
Nonetheless, investors continued to bet that the streak would end, and they could own a piece of the transformational tech that would triumph for longer-term storage.
“What a lot of startups and investors are doing is assuming the LDES market will exist and it will be enormous, and they’re assuming lithium-ion won’t solve the problem,” Chamberlain said. “I believe that is a very, very bad assumption.”
Over the last decade, lithium-ion has steadily chipped away at use cases where new battery inventions were supposed to win out. New lithium-ion is starting to push into six-hour configurations and beyond, said Stoikou, from BloombergNEF. Global average pricing for turnkey grid storage averaged $165 per kilowatt-hour in 2024, per the data firm’s 2024 survey.
Now, the cost savings from reusing lithium-ion packs accelerate the chemistry’s push into the long-duration market — something that would be a big win for grid-decarbonization efforts, while delivering the LDES hopefuls yet another stinging loss.
Clarifications were made on August 6 and August 7, 2025: This story has been updated to reflect Eugene Beh’s full title and to note that Hydrostor is attempting to build a large-scale compressed air project in California.
The Trump administration recently terminated a $4.9 billion loan for the Grain Belt Express, the country’s biggest transmission grid project. Sen. Martin Heinrich, Democrat from New Mexico, says the decision is illegal.
In an exclusive new interview with Canary Media, Heinrich discusses why he’s demanding that the Department of Energy account for the decision — and what response he’s received.
Last month, Heinrich, the top Democrat on the Senate Committee on Energy and Natural Resources, sent a letter to the DOE challenging its vague excuse for cutting off the legally binding contract between the federal government and Invenergy, the Chicago-based energy project developer planning to build the power-line project from Kansas to Illinois.
“Not only am I concerned that this move is illegal,” Heinrich wrote — a belief shared by Jigar Shah, the former head of the DOE Loan Programs Office, which issued the conditional loan guarantee in the waning days of the Biden administration. “I am concerned that the federal government is eroding what little trust the private sector has in our ability to be reliable partners.”
That trust is eroding rapidly, Heinrich said. The project has been in the works for more than a decade and is one of only a handful of major transmission developments underway in the United States.
The Grain Belt Express would support gigawatts’ worth of new wind and solar projects — energy sources that are under attack by the Trump administration.
The new GOP megalaw is expected to cut new solar, wind, and battery deployments by more than half just as power demand is rising. Last year, clean energy made up 96% of the new energy capacity being added to the U.S. grid.
Meanwhile, the Trump administration has unleashed a flurry of anti-wind and anti-solar actions in the past month that threaten to subject wind and solar projects to burdensome and potentially insurmountable Interior Department reviews, block development on federal lands under “capacity density” restrictions, and potentially put a halt to already permitted wind farms on land and at sea.
The move to block the Grain Belt Express is part of this broader attempt to slow renewable energy — just when the country can least afford it, Heinrich said.
This interview has been edited for clarity and brevity.
Why did you decide to write the letter to Energy Secretary Chris Wright?
Secretary Wright, before he was secretary, said numerous times to our committee [the Senate Committee on Energy and Natural Resources] that he was going to follow the law, and a conditional loan guarantee is a legally binding commitment.
It’s as if you go to your bank and you get preapproved for a mortgage, then when you show up for the closing, you expect the bank to make good on that. And that’s what we had here.
The reality is, we need this administration to follow the law and make good on commitments that have been made so that there is predictability in the market. We also need every cheap electron we can get right now, and so if you put these big infrastructure projects in jeopardy, what you’re really doing is passing along more costs to consumers.
Have you received any response from DOE?
Not yet.
Do you expect you’ll eventually get a response?
I certainly expect to. And if the secretary wants to be taken seriously by the Senate, then he needs to provide that information.
One of the things that really bothers me about a lot of the actions that the Department of Energy and the Department of Interior are taking right now is the sum total is creating a lot of uncertainty in the finance markets, and that flows through to create additional costs for consumers.
When you have a big transmission project like this one, there are $52 billion in energy savings over the course of the next decade, and that should be accruing to consumers. And if you put all of this in jeopardy, the real impact is that costs are going up, and then when you put all of these permits that are usually very predictable and are now uncertain, all of this is going to raise costs for consumers — for retail consumers and for commercial consumers. We’re already seeing electric rates start to rise, and I am deeply concerned that that is going to get a lot worse in the coming years because of their actions and their inactions.
You asked the department if it had analyzed the impact of canceling the loan guarantee. What do you see as the administration’s responsibility in analyzing its actions on energy policy in terms of affordability? And are they fulfilling those responsibilities?
They are not. And it doesn’t take a detailed analysis to understand that, in an environment of surging demand, if you artificially constrain supply, you’re going to be raising costs for people. And I want the American people to know that this is not an accident. They are choosing to take actions which are raising people’s electric bills.
Sen. Chuck Grassley, a Republican representing Iowa, has said he won’t be moving Treasury Department nominations forward until there’s some response from the administration regarding its actions on wind and solar tax credits. Can you tell us more about where members of Congress have power to challenge how the administration is managing energy policy?
Well, I think the confirmation process is one obvious place. This is an administration that has been very public about saying that they need more people in place to be able to execute their agenda. But unless they’re responsive to the Congress, that process is not going to speed up.
You asked the DOE for a list of all the closed loans and conditional commitments that the department is reviewing. Have you received any response?
I’ll be honest, they have not been particularly transparent or responsive on many of these issues, and that is a trend that I think does not bode well for the next several years.
Having been through a 17-year process to get one transmission line built [the SunZia line in New Mexico and Arizona], I’m also acutely aware of the jobs that hang in the balance. We’re talking about thousands and thousands of good, high-quality American jobs that are simply not going to come to fruition because this administration has a political agenda. I’ve never seen an administration so insensitive to the job implications of their actions.
The country’s biggest power market is caught in a trap of its own making — and the more than 65 million people from the mid-Atlantic coast to the Great Lakes who rely on it for electricity will pay the price.
Last week, PJM Interconnection announced a new record in its annual capacity auction, the means by which the grid operator secures the resources it needs to maintain a reliable transmission grid across 13 states and Washington, D.C. Prices increased to $16.1 billion, up from last year’s already record-setting $14.7 billion and an eightfold increase compared to $2.2 billion for the 2023 auction.
Prices would have spiked even further if not for a cap instituted as part of a settlement agreement with Pennsylvania Gov. Josh Shapiro (D) reached in April. Even so, PJM estimates that residential customers could see utility bills rise by up to 5% in the years to come, or more than $100 in annual household costs — rate hikes that will occur on top of bill increases just now starting to hit customers as the result of last year’s auction.
These spiraling costs have galvanized both Republican and Democratic governors of states served by PJM to demand immediate reforms. “With billions of ratepayer dollars and the stability of our grid at stake, it is critical that PJM take concerted, effective action to restore state and stakeholder confidence,” governors from Delaware, Illinois, Kentucky, Maryland, Michigan, New Jersey, Pennsylvania, Tennessee, and Virginia wrote in a July letter to the grid operator.
But it’s unclear whether PJM can quickly solve the problems that are driving up costs. That’s because the core issue — barely any new generation capacity has been able to connect to the grid — will take years to resolve.
“You have a massive technical problem, which is the challenge to fix this broken interconnection queue and bring new resources online in a time of global uncertainty with tariffs, inflation, and supply chain issues that are slowing the construction and development of new generation resources,” Jon Gordon, a director at clean-energy trade group Advanced Energy United, said in a webinar last week dissecting the grid operator’s current predicament.
PJM isn’t the only U.S. regional grid operator struggling to get new power plants, solar and wind farms, and grid-scale batteries connected. But it has one of the worst track records, with projects taking an average of more than five years to move through the steps required to plug into the grid. Advanced Energy United gave PJM a D- score for its interconnection processes in a 2024 survey, the lowest of any U.S. grid operator.
The consequence has been a paltry amount of new generation and battery storage. PJM reported last week that about 2.7 gigawatts of new generation and “uprates” — existing projects that have augmented their capacity — had been added to its available pool of resources since its last auction. That’s the first such increase in the past four auctions, and a fraction of PJM’s roughly 180 GW of generation capacity.
Nor is PJM winning high marks for its efforts to fix its interconnection backlog. Critics say the grid operator has stalled on reforms that others have undertaken, including changes mandated by the Federal Energy Regulatory Commission. Last week, FERC ordered PJM to rework “conceptual proposals” that it said fail to meet federally mandated deadlines for implementing interconnection reforms.
In 2022, PJM froze the process for new projects seeking interconnection to deal with a backlog stretching back to the late 2010s. That backlog won’t be cleared until the end of 2026, leaving hundreds of gigawatts of prospective new supply in limbo.
“The market can’t work until the interconnection queue delay is fixed,” Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based utility customer watchdog group, said during last week’s webinar. An April study from research firm Synapse Energy Economics found that comprehensive interconnection reforms at PJM could save customers an average of $505 per year in utility bills and cut commercial and industrial electricity costs by 23% through 2040.
PJM noted in last week’s press release that it has processed more than 60% of the backlog in its interconnection queue. It also highlighted that more than 46 GW of “already-approved resources have yet to be built,” with many projects “navigating challenges outside PJM’s scope, such as permitting timelines, supply chain constraints and evolving project economics.”
Gordon pointed out that PJM’s interconnection bottlenecks have put energy developers in a very tough position. Nearly 95% of the grid operator’s backlog consists of solar, wind, and battery projects, and “many of those projects came into the queue pre-COVID,” he said.
Since then, interest rates have gone up dramatically, equipment costs have risen, and the Trump administration and Republicans in Congress have undone federal incentives and policies supporting clean energy growth. “Whatever those developers were thinking about those projects back then, the economics, everything has completely changed,” he said.
The forecasted demand for electricity on PJM’s grid has also increased enormously in the past four years. The AI bubble has driven up PJM’s projected load growth by 5.5 GW from last year’s auction, largely due to new plans for data centers in the region.
But PJM may not be applying the proper amount of skepticism to calculating future demand growth from data centers, said Abe Silverman, an attorney, energy consultant, and research scholar at Johns Hopkins University.
Many data center developers are seeking interconnection in multiple states for duplicative project proposals, he noted. Other U.S. grid operators are “doing a much better job trying to get a handle on the data center load growth,” including winnowing out speculative or duplicative requests, he said during last week’s webinar.
Without such safeguards, PJM runs the risk of overestimating the amount of new generation it will need to meet future demand, which will drive up prices, Silverman said. “If you believe the PJM load forecast, we need to add five nuclear units’ worth of generation to the market every year between now and 2030. And that’s just an enormous challenge, both financially and logistically.”
In the face of these issues, PJM has largely emphasized the need to keep fossil-fueled power plants online and has blamed state clean-energy policies for driving coal-fired power plants to close prematurely.
That argument has been echoed by Todd Snitchler, CEO and president of the Electric Power Supply Association, a trade group representing power plant operators with a preponderance of fossil-gas power plants in their portfolios.
“In recent years, a combination of state and federal policy shifts and poor market signals led to the premature retirement of essential generation,” Snitchler said in a statement after this month’s auction. “Now, as demand grows and supply tightens, we can’t ignore the consequences of past decisions, and we must accept that reliability comes at a cost.”
About 34 GW of coal capacity have retired across PJM since 2013, according to federal data. PJM’s independent market monitor forecast last year that as much as 58 gigawatts of generation will be retired by 2030.
But Citizens Utility Board has emphasized that those retirements are happening in both Republican-led states without clean-energy and climate mandates, including Ohio and West Virginia, as well as in Democrat-led states such as Maryland and New Jersey, indicating that state policies aren’t the chief driver. The main reason coal plants are closing is that they are increasingly unable to compete in energy markets against cheaper gas-fired power plants, renewable energy, and batteries.
Growing power demand is starting to slow the pace of closures. PJM noted last week that 1.1 GW of power plants have withdrawn their retirement plans since last year’s auction. PJM has also forced fossil-fueled power plants in Maryland that were set to close this year to remain open to maintain grid reliability.
The Trump administration may cite PJM’s growing capacity problems to justify using emergency federal powers to require aging fossil-fueled power plants to remain running. The Department of Energy has already used those powers to demand that a coal plant in Michigan stay open, as well as an oil- and gas-fired power plant in Pennsylvania — a move that PJM has publicly supported and that climate and consumer advocates are challenging.
At the same time, PJM has yet to advance near-term options for bringing power online quickly, Summers said. PJM’s proposal to reuse the grid connections left open at retiring plants for new resources, such as batteries, is still awaiting FERC approval, she said.
In February, FERC approved PJM’s plans to revamp another process known as “surplus interconnection service,” which allows existing projects to add new technologies to boost their grid value — for example, adding batteries to wind and solar farms. But the changes have not yet led to new capacity being brought into the market, Summers said.
Meanwhile, PJM’s attempt to fast-track new gas-fired generation won’t help in the near term, Summers said. In May, the grid operator announced 51 new projects selected through its Reliability Resource Initiative, which allows projects not already in the interconnection queue to propose additional resources to meet capacity needs. But most of the 9.4 GW of capacity secured through that process — and all of the newly built gas-fired power plant capacity — isn’t scheduled to be online until 2030 or later.
That’s not surprising. Major manufacturers have reported multiyear backlogs for gas turbines, restricting developers’ ability to add more capacity beyond what’s already in the works. These bottlenecks are likely to hamper similar fast-track efforts being undertaken by grid operators Midcontinent Independent System Operator and Southwest Power Pool.
Accelerating resources that can actually be built in the next two years — like solar and batteries — would be a better strategy to reduce costs, Silverman said.
“Prices are increasing right now because we don’t have enough supply,” he said. “We really have choked off that next generation of projects that should be coming in and taking those positions in the market.”
Five years ago, B2U Storage Solutions proved that old EV batteries could hook up to the grid to store clean energy, safely and cheaply. Now the company is taking the concept to Texas.
B2U just broke ground on a second-life grid battery project in Bexar County, near San Antonio, the company told Canary Media. In the next 12 months, B2U will complete four projects in the region, totalling 100 megawatt-hours of storage, CEO Freeman Hall said. The move marks a major expansion for the scrappy innovator, at a time of increased interest in the value of used EV batteries.
On paper, it makes perfect sense: Putting old EV batteries to work on the grid tackles the waste stream created by the growing adoption of EVs while expanding clean energy storage at a discount compared to brand-new lithium-ion batteries. But delivering on the concept efficiently and safely is much harder in practice, and after years of trying, the industry has only installed a handful of utility-scale grid batteries.
B2U stores up to 28 MWh at its first project, in Lancaster, California, and also developed two other smaller facilities in that state. Another company, Element Energy, built a record 53-MWh second-life storage plant in Texas last year. Earlier this summer, lithium-ion recycling startup Redwood Materials beat that record: It unveiled a second-life battery business that includes a 63-MWh storage plant to serve an on-site data center in the Nevada desert.
B2U’s new portfolio won’t set any individual records, but it could prove out the repeatability of the second-life model. In developing for the Texas market, B2U focused on areas near population centers that face transmission constraints. It designed the projects as 10-MW systems with a little over two hours of discharge at full capacity, allowing them to qualify for a fast-track permitting program in the grid managed by the Electric Reliability Council of Texas, or ERCOT.
Once built, the batteries can arbitrage from cheap hours when the state’s massive solar fleet is cranking to peak-demand hours when electricity prices shoot up. Batteries, with their ability to instantly inject or absorb power, can also compete to provide various other forms of grid-stabilizing services in the ERCOT markets.
“Texas has been a very strong market with ever more volatility,” Hall said. “And that’s what storage does well, is take advantage of volatile conditions.”
The expansion draws on the company’s five-year track record of operating second-life batteries on the grid, and making money at it.
One lingering question for the sector has been how long the previously worn-down packs would survive when used for daily charging and discharging. The Lancaster project was designed to eke out 2,000 cycles from its initial batch of early Nissan Leaf batteries, Hall said; those packs have now exceeded that target.
Crucially, the equipment has not required much upkeep: Of the 2,000 battery packs that B2U operates so far, technicians have only had to pull out a single-digit number of them for maintenance, Hall noted. That has given the company confidence to dispatch the batteries a bit more intensely.
“We’ve got all these guardrails and real-time monitoring of the batteries that ensure safety, but we’re not as concerned about degrading the batteries,” Hall said. “They’re turning out to be pretty strong workhorses that don’t degrade as people thought they might.”
B2U said its first project, built in 2020, cost about $200 per kilowatt-hour, which at the time offered a roughly one-third discount compared to new battery systems. Today, new lithium-ion enclosures have come down to $150 to $180 per kilowatt-hour, Hall said, and B2U can deliver at half that rate based on the savings from used batteries. Accounting for additional costs associated with permitting, interconnection, and installation, a finished project comes in 30% to 40% cheaper than a new lithium-ion facility would, he added.
B2U has gotten this far with just $20 million raised in an extended Series A funding round, and another $8 million from the founders and friends. Hall built his California projects on the company’s balance sheet to prove out the concept, which was quite risky for most investors at the time. Consequently, B2U has reaped all the profits from those early investments.
Now, though, B2U has far less cash to throw at its projects than newly minted second-life competitor Redwood Materials. That company was founded by former Tesla Chief Technology Officer JB Straubel, a certified celebrity of the battery engineering world who swiftly raised $2 billion to tackle battery recycling. But Hall found Redwood’s arrival onto the scene more encouraging than intimidating.
“For the North American recycler that has raised the most capital and has been hyping the recycling opportunity the most to now make a big splash and say that they believe that the repurposing market can grow faster and generate more revenue than their core business — that’s quite the validation point,” Hall said.
Going forward, B2U has raised a fund to own its operating projects with a mix of outside equity, debt, and tax equity. That means Hall can sell off the projects to the fund (although B2U will keep a stake in them), freeing up money for new business activities. This sets the company up for faster growth than if it continued to support all its projects with its own corporate balance sheet.
Still, B2U maintains a rare distinction in the cleantech-startup universe: For relatively minor funds raised, the company has built real things that generate profits. Cleantech venture capitalists have heaped far more cash on pre-revenue companies chasing far more dubious propositions.
Five years ago was like “the first at-bat of the first inning” for second-life storage, Hall said, meaning he had a lot to prove in the field to dispel investor concerns about the novel technology. He took it slow on fundraising while he tackled those proof points.
“We’ve been very disciplined in deploying capital. That tends to be viewed by investors as a good thing, but the opportunity is such a big one right now that we need to do what’s smart for shareholders — and staying small probably no longer is as smart,” he reflected. “It’s probably time for us to grow, to take advantage of the opportunity in front of us.”
Plans are in the works to build America’s first new aluminum smelters in nearly half a century. The two facilities, slated to go online in Oklahoma and possibly Kentucky in the coming years, would dramatically boost domestic production of the versatile metal if completed as planned.
But for that to happen, they will first have to secure a steady supply of electricity, at a time when AI data centers and other industrial facilities are competing fiercely for a share of the country’s limited power resources, and as the grid is strained by surging demand.
The smelters proposed by Emirates Global Aluminium and Century Aluminum would be energy hogs. Each plant is expected to produce about 600,000 metric tons of aluminum each year, requiring enough electricity annually to power the state of Rhode Island. That’s because the process of converting raw materials into primary aluminum requires hundreds of megawatts of power running at near-constant rates.
For the economics to pencil out for either facility, that power will need to be cheap. And it will need to be produced from carbon-free sources, like wind or solar, for the aluminum they produce to be more competitive on the global market, which increasingly favors low-carbon metal.
Unfortunately for American aluminum producers, both clean and affordable power are only getting harder to come by.
Electricity demand in the U.S. is rising faster than supply is forecast to grow, which is pushing up prices. Aging grid infrastructure and slow permitting timelines have long delayed the build-out of new power generation. Now the Trump administration and GOP-led Congress are creating additional financial and legal headwinds for wind, solar, and battery storage projects — the only resources that can be built fast enough to meet demand in the near term.
“With clean energy tax credits going away, we can reasonably expect the cost of electricity to go up in all markets,” said Annie Sartor, the aluminum campaign director for Industrious Labs, an advocacy organization. “That’s just profoundly challenging to aluminum facilities that are looking for electricity … especially in a moment when there’s a rush on electricity nationally.”
The deepening power crunch represents a major roadblock in the quest to reshore U.S. manufacturing.
The Trump administration recently raised tariffs on aluminum and steel imports from 25% to 50% to bolster the business case for producing primary metals domestically. It has also preserved a crucial award for Century Aluminum’s smelter that was issued in the final days of the Biden administration. In January, the Department of Energy awarded Century a grant of up to $500 million as part of a federal industrial decarbonization program, much of which has since been defunded.
But to successfully kick-start an American aluminum renaissance, the government and utilities will also need to make larger long-term investments in the nation’s ailing electricity sector, and develop tools that allow smelters to not just take power from the grid, but to help it run more smoothly, experts say.
“Ultimately, this is about energy,” said Matt Meenan, vice president of external affairs for the Aluminum Association, a trade group that supports an “all-of-the-above” approach to electricity sources.
“And until you crack that nut,” he added, “I think we’re going to have a hard time becoming fully self-sufficient for primary aluminum in the U.S.”
Aluminum companies worldwide produced 73 million metric tons of primary, or virgin, aluminum in 2024. The lightweight metal is used to make products as varied as fighter jets, power cables, soda cans, and deodorant. It’s also a key component of clean energy technologies like electric vehicles, solar panels, and heat pumps.
Producing aluminum contributes about 2% of total greenhouse gas emissions every year. The majority of those emissions come from generating high volumes of electricity — often derived from fossil fuels — to power smelters. The smelting process involves dissolving powdery white alumina in a scorching-hot salt bath, then zapping it with electrical currents to remove oxygen molecules and make aluminum.
The United States was once one of the world’s top producers of primary aluminum. In 1980 — the last year a new smelter was built — the nation had 33 operating facilities, many of which relied on cheap power from public hydropower plants. But then industrial electricity rates began to rise after the federal government restructured energy markets in 1977.
Deregulation was “the single most important factor leading to the near total demise of the primary aluminum industry,” the Aluminum Association said in a recent white paper entitled “Powering Up American Aluminum.” The U.S. industry’s downward spiral accelerated further after China joined the World Trade Organization in 2001, leading to a glut of inexpensive Chinese aluminum on the global market.
Today, just four American smelters remain operational. In 2024, they produced an estimated 670,000 metric tons of primary aluminum, or less than 1% of global production. The U.S. mainly makes secondary aluminum from scrap metal, which totaled over 5 million metric tons last year. While secondary production is growing, it can’t fully replace the need for strong and durable primary aluminum.
“There’s always going to be a role for primary aluminum,” Meenan said. “And we do think having smelters here is really important.”
Century Aluminum and Emirates Global Aluminium both say their new smelters will mark a new beginning for the U.S. primary-aluminum sector. The two facilities would together nearly triple the nation’s primary-aluminum capacity when they come online, potentially around 2030.
Century Aluminum first unveiled plans for its smelter in March 2024, after the Biden-era Department of Energy launched a $6 billion initiative to modernize and decarbonize America’s industrial base. As part of the award process, Century said its Green Aluminum Smelter could run on 100% renewable or nuclear energy and would use energy-efficient designs, making it 75% less carbon-intensive than traditional smelters.
At the time, the Chicago-based manufacturer identified northeastern Kentucky as its preferred location for the smelter, though the company was also evaluating sites in the Ohio and Mississippi river basins. More than a year later, Century still hasn’t picked a final project site for the $5 billion smelter — because it hasn’t yet locked down its power supply.
Electricity isn’t available at the fixed long-term price that smelters need to ensure profitability and pay back billions of dollars in construction costs, Matt Aboud, Century’s senior vice president of strategy and business development, said in May at a global aluminum summit in London, Reuters reported.
“We remain really excited about the project,” Jesse Gary, Century’s president and CEO, said on a May 7 earnings call. “The next two key milestones are to finalize negotiations of the power arrangements, and then following from that … we’ll be making a site selection.”
The Aluminum Association estimates that manufacturers would need a 20-year power contract at or below $40 per megawatt-hour to justify investing in a new smelter at today’s aluminum prices. Restarting the nation’s fleet of idled smelters, which represent 601,500 metric tons in primary capacity, would require a similar arrangement.
Currently, power-purchase agreements for U.S. renewable energy projects are in the range of $50 to $60 per MWh — a significant difference for these power-hungry facilities. Tech giants like Microsoft have signaled their willingness to pay north of $100 per MWh for electricity from nuclear and fossil-gas plants to fuel their data centers, giving those firms an advantage over price-sensitive buyers in the race for electricity.
Meanwhile, in Oklahoma, Emirates Global Aluminium is advancing its $4 billion smelter project with the promise of significant financial support from taxpayers and utility customers.
The Abu Dhabi-based conglomerate in May signed a nonbinding agreement to build the smelter with the office of Republican Gov. J. Kevin Stitt, a deal that includes over $275 million in incentives, including discounts for power. The manufacturer and governor’s office are working to establish a “special rate offer” from the Public Service Co. of Oklahoma — a subsidiary of utility giant AEP — for the new facility.
Simon Buerk, EGA’s senior vice president for corporate affairs, said that Oklahoma’s “energy abundance” was a key factor in selecting the state for the new aluminum smelter.
More than 40% of Oklahoma’s annual electricity generation comes from wind turbines spinning on open prairies, while about half the state’s generation comes from fossil-gas power plants. Last month, the Public Service Co. acquired an existing 795-MW gas plant just south of Tulsa to meet the rising energy needs of its customers, including potentially EGA.
Buerk said EGA and the utility are in “advanced negotiations” to finalize a competitive power contract. One option the groups are considering is a tariff structure that gives the smelter dedicated long-term access to a proportion of renewable energy, equal to 40% of the smelter’s needs. The smelter’s annual power mix “will be based on EGA’s decarbonisation objectives, market dynamics, and market demand for low-carbon aluminum,” he said by email.
Outside the United States, nearly all primary aluminum smelters receive some form of government backing in the countries where they operate — typically by ensuring access to affordable energy, said Sartor of Industrious Labs.
She pointed to Canada, the largest supplier of U.S. aluminum imports. Smelters in Quebec draw from the region’s abundant hydropower resources, which are operated by the government-owned entity Hydro-Quebec. The price of electricity that producers pay is often tied to the price of aluminum on commodities markets, so that smelters pay less during lean times and more when the market recovers.
“The industry functions through government support all over the world, and we should be looking at those models and finding one that fits us here,” said Sartor.
Manufacturers and utilities can also structure power-supply agreements that enable smelters to benefit, rather than strain, the grid, said Anna Johnson, a senior researcher in the industry program at the American Council for an Energy-Efficient Economy.
“When we think about how to address the challenge of procuring large amounts of clean power, one of the first tools we think about is, what can we do on the demand side to mitigate that load and make sure that the demand of these facilities is avoiding times of peak stress?” she said.
In New Zealand, for example, Rio Tinto’s Tiwai Point smelter receives financial incentives to curb its electricity use — and therefore lower its aluminum production — during dry seasons, when hydropower resources can become critically low. In Australia, the aluminum giant Alcoa is participating in a program that turns one of its smelters into an emergency resource when the grid is overly stressed. The Australian government pays Alcoa to halt production on some of its aluminum-making potlines for about an hour at a time.
In the U.S., other types of industrial plants — including a titanium-melting plant in West Virginia — are using behind-the-meter solar power and battery storage systems, so that the facilities are primarily drawing from the electrical grid only during off-peak hours.
Strategies like these that reduce electricity rates are especially crucial now that the development of cheap, renewable energy is set to slow in the United States. But manufacturers will still need access to new carbon-free electricity sources in order to produce the cleaner aluminum that customers are increasingly demanding, Sartor said.
“When [companies] build a new facility, they’re building it for 50 or 100 years,” she said. Even as the Trump administration winds back the clock on U.S. climate action, smelters “need to find clean power as a matter of international competitiveness.”
The Trump administration just dealt a blow to the biggest transmission line project currently underway in the United States.
The U.S. Department of Energy has canceled a $4.9 billion federal loan guarantee for the Grain Belt Express, a massive transmission line project seeking to carry wind and solar energy from the Great Plains to states farther east. It’s the latest in a series of Trump administration actions aimed at undermining the U.S. clean energy sector in the name of protecting taxpayer dollars.
In its Wednesday cancellation announcement, the DOE claimed that “the conditions necessary to issue the guarantee are unlikely to be met and it is not critical for the federal government to have a role in supporting this project.”
Energy Secretary Chris Wright is also scrutinizing several other loans made under the Biden administration by the DOE’s Loan Programs Office, which issued its conditional guarantee to the Grain Belt Express in November. He has pledged to closely review and potentially cancel tens of billions of dollars more in financing from the office, citing a need to more responsibly steward federal dollars. However, in its 20-year history, the office has turned a profit for taxpayers by collecting interest and principal payments from the companies that receive loans.
The Grain Belt Express has been in the works for more than a decade. It’s one of only a handful of major transmission projects underway in the U.S., and once built it will be able to support the development of gigawatts of new wind and solar projects and deliver $52 billion in energy cost savings over 15 years, according to Invenergy, the Chicago-based developer that’s building it. Around the country, more projects like the Grain Belt Express are needed to expand the grid fast enough to meet surging demand and to bolster electricity reliability.
The cancellation comes a week after Sen. Josh Hawley, a Missouri Republican, told The New York Times that he had made a personal appeal to President Donald Trump to take action to halt the project, and that Trump had promised to instruct the DOE to do so.
“He said, ‘Well, let’s just resolve this now,’” Hawley told The New York Times. “So he got Chris Wright on the line right there.”
Invenergy did not immediately respond to requests for comment Wednesday morning. The developer had sought the loan guarantee to reduce the expense of borrowing for the project, which will cost $11 billion in total and has already secured agreements with utilities in Missouri as part of its efforts to find buyers for the power it will make available across the regions it will connect.
It’s unclear to what extent the loss of federal loan guarantees will derail or slow down the project’s timeline. In May, Invenergy signed a nearly $1.7 billion contract with contractors Kiewit Energy Group and Quanta Services, and construction is slated to begin next year.
In a statement earlier this month responding to a social media post from Hawley criticizing the project, Invenergy accused the senator of “trying to deprive Americans billions of dollars in energy cost savings, thousands of jobs, grid reliability and national security, all in an era of exponentially growing demand.”
The U.S. faces a looming crisis as new data centers, factories, and broader economic growth cause electricity demand to rise faster than supply is forecast to grow.
Solar, wind, and batteries have made up more than 90% of new energy built in recent years, and are the only resources that can be constructed rapidly enough to meet surging demand in the near term. Other energy resources have far slower development times, including fossil-gas power plants, which currently face manufacturing bottlenecks that will take years to resolve.
In addition to headwinds from Trump and the GOP-led Congress, which just eliminated federal tax credits for solar and wind, the main factor that threatens to hold back clean-energy development is a lack of space on the grid.
The U.S. lags in building the new high-voltage transmission lines that grid experts say are necessary to bring even more new solar, wind, and batteries online. These lines carry clean power from where it’s cheap to produce to where the most energy is consumed, like cities, and building more of them can reduce grid congestion, improve power system reliability, and lower electricity rates.
The Grain Belt Express has won approval from utility regulators in Kansas, Missouri, Illinois, and Indiana, and has received support from lawmakers and organizations representing farmers and large electricity consumers. But the project has also faced multiple challenges from landowners and farmers. Invenergy is currently contesting an Illinois court’s 2024 decision to overturn state regulatory approval for the project, made in response to a challenge from the Illinois Farm Bureau and landowner groups.
Missouri’s attorney general, a Republican, launched an investigation into the project earlier this month, accusing Invenergy of inflating economic benefits and overstating cost savings it would deliver. Invenergy contested the validity of that challenge in a letter to Energy Secretary Wright, saying that all relevant issues have already been decided by state courts and regulators.
It’s common for large-scale transmission projects, which traverse hundreds of miles across many different municipalities, counties, and states, to get bogged down in court battles. It’s a big reason why it takes so long to build new power lines in the U.S. But the Trump administration’s decision to cancel financing for the project is uncharted territory, and the impact is still unclear.
Should the project be delayed, it’d be a major setback for the U.S.’s already-sluggish transmission buildout.
The U.S. needs far more transmission to be built to lower energy costs and reduce the increasing threat of blackouts caused by extreme weather, according to reports from groups ranging from the Department of Energy and the North American Electric Reliability Corp. to the Massachusetts Institute of Technology and Princeton University.
Over the past decade, the number of miles of long-range, high-voltage transmission built across the country has fallen, even as utility transmission spending has risen. A report released this week by advocacy group Americans for a Clean Energy Grid and consultancy Grid Strategies found that only 322 miles of high-voltage transmission lines were completed last year, the third-lowest buildout of the past 15 years, and well below the nearly 4,000 miles built in 2013.
“The Grain Belt Express represents a critical opportunity to modernize the grid, lower electricity costs, and deliver reliable energy across multiple states,” Christina Hayes, executive director of Americans for a Clean Energy Grid, told Canary Media in a Wednesday email. “We encourage the administration to take a fresh look at the value this project brings to achieving its own goals for economic growth and energy dominance.”
Southern California’s grid needed help in the fall of 2016. The region was still reeling from the calamitous Aliso Canyon gas leak, and its power plants faced a potential shortfall of that fuel to meet air-conditioning demand when the next summer rolled around. The state took a chance on a new grid technology, lithium-ion batteries, to fill in the gaps.
Big names like Tesla and AES stepped in to help, installing storage at record speed, but so did a little-known firm called Powin. Joseph Lu had founded the Oregon-based company years earlier to import consumer products from China and Taiwan. Sensing a new business opportunity, Powin won a bid and installed 2 megawatts of batteries in a warehouse it owned in Orange County.
This proved to be a launchpad for the firm, which rose to the upper echelons of the booming U.S. battery industry before crashing down to earth last month.
After that Orange County installation, Powin refocused on importing battery cells from China and integrating them into grid storage systems, fully packaged with inverters, controls, and safety systems. Powin went on to deliver battery enclosures for many pathbreaking projects: It supplied the first utility-scale battery in Mexico, a landmark utility-endorsed battery fleet in Arizona, and a truly mammoth system in Australia, to name just a few of Powin’s self-reported 11.3 gigawatt-hours of installed systems. It raised some major outside equity rounds to keep growing and last fall obtained a $200 million debt facility from investment giant KKR.
And then in June, Powin filed for bankruptcy, alerting the state of Oregon of mass layoffs at its Tualatin campus, outside Portland. The news jolted the storage industry, since so many major grid storage plants run on Powin’s hardware and software. The bankruptcy proceedings are ongoing, but storage software specialist FlexGen has placed a bid to buy Powin’s assets at auction in early August, offering Powin customers a way to keep their batteries running.
Cleantech bankruptcies have flourished under the second Trump presidency, and the storage sector is uniquely exposed. The industry runs almost entirely on imported battery cells from China, making it vulnerable to rapidly shifting trade policies. The Biden administration raised tariffs on Chinese batteries, and President Donald Trump cranked the overall rate on Chinese imports as high as 145% in April, though he has altered the rate repeatedly in the opening months of his presidency. Trump’s budget law preserved tax credits for installing grid batteries but added a new bureaucratic regime to regulate the amount of China-derived equipment in those storage plants.
“The business model of integrating batteries into a full storage system is one of these classic high-volume, low-margin businesses,” said Pavel Molchanov, a Raymond James analyst covering cleantech companies. “Margins were low even before Trump and these new tariffs on China, and now it’s a safe bet that their margins have been squeezed even further.”
Nonetheless, Powin’s collapse stands out for the scale of the company’s reach — and raises serious questions. Is Trumpian chaos enough to unseat a leading battery supplier, even as the market for grid batteries continues to surge? Or did Powin’s leadership make choices that ultimately led to its early demise? And perhaps more important, what’s going to happen to those 11.3 gigawatt-hours Powin installed before it went bankrupt?
Powin got to the big leagues by spotting technological trends before they hit the energy-storage mainstream.
That started with the rapid-fire California installations in 2016, when hardly anyone was building large-scale storage. At the time, American developers looked to a handful of Tier 1 battery suppliers, like LG, Samsung, and Panasonic. Powin instead scoured China for manufacturers that American buyers hadn’t discovered yet but that could match key quality metrics. Powin signed an early supply deal with a firm called Contemporary Amperex Technology Co., or CATL, which has since become far better known in the West as the world’s largest battery maker.
Powin also focused on the then-lesser-known lithium ferrous phosphate (LFP) chemistry, which executives hailed as safer and longer-lasting than the mainstream nickel-based chemistries handed down from the electric vehicle supply chain. Powin imported these LFP cells from trusted vendors in China, installed them in engineered metal cabinets in Tualatin, then delivered them to project sites across the U.S. and, later, the world.
By the 2020s, U.S. storage installations were growing at a shocking rate. To keep pace with soaring demand, Powin raised $100 million in February 2021 from investors Trilantic Capital Partners and Energy Impact Partners, followed by $135 million in 2022, led by Singapore’s sovereign wealth fund GIC.
The firm’s first major public setback came when a Powin-supplied battery system in Warwick, New York, burst into flames after a summer storm in 2023. Days later, authorities responded to fumes emerging from another Powin-supplied system in that town.
Developer Convergent Energy and Power owned both systems, and its investigation concluded that a manufacturing flaw in that generation of Powin’s Centipede battery container let water leak in and start electrical fires. Those incidents prompted the Warwick Village Board to freeze local battery development, and they undercut Powin’s reputation for safety, which the company previously had promoted after other companies’ battery fires elsewhere in the country. A spokesperson for Convergent did not respond to requests for comment.
It’s unclear what kind of financial impact the fallout from those fires had on Powin, but the firm subsequently found itself locked in a legal dispute with none other than its longtime supplier, CATL. That company sued Powin in Oregon Circuit Court in December 2024 for $44 million in allegedly unpaid bills, following an earlier arbitration on the matter in Hong Kong.
The circuit court noted in February that Powin “does not deny that they owe money to CATL” and that “it is apparent to the court that the amount of money Powin owes to CATL exceeds the value of the assets Powin holds in Oregon.” That’s not a great sign for a company’s metabolism.
In a subsequent filing, Powin’s lawyers asserted that, actually, CATL was refusing to honor the contracts and instead tried to spring non-contracted price hikes at the last minute: “CATL effectively held Powin hostage to choosing between negotiating a solution with CATL or breaching contracts with its customers.”
In the same suit, the Powin lawyers proposed a nefarious explanation for the souring relationship with CATL, one that sheds light on a broader challenge Powin faced in the maturing storage market.
“Powin finds it highly suspect that the timing of this filing for pre-judgment remedies comes as CATL is aiming to compete directly with Powin to supply complete energy storage systems, moving beyond its historical business model of supplying subcomponents to Powin and others like Powin.”
Powin championed CATL’s battery cells to the U.S. market when buyers still had hang-ups about sourcing high-quality batteries from China. But CATL, recently valued at more than $180 billion, did indeed move beyond simply shipping cells and began competing directly with Powin. CATL launched a containerized storage product in 2023, and in May it rolled out a new 9-megawatt-hour, double-decker grid battery enclosure called TENER Stack.
“The past few months have presented considerable headwinds for system integrators, even without considering company-specific challenges,” said Ravi Manghani, senior director of strategic sourcing at data firm Anza Renewables. “The increasing number of battery [original equipment manufacturers] entering the U.S. market with attractively priced DC blocks and AC solutions has put pressure on the traditional value proposition of system integrators.”
Other sources in the grid storage industry noted that Powin’s quality had suffered in the scale-up, lowering customer interest in its products. The company had always had a smaller balance sheet than competitors like Tesla, Fluence, and Wärtsilä, all of which are publicly traded and worth billions.
Longtime Powin CEO Geoff Brown, who led the company from 2016 through its dynamic growth phase, departed in 2023. He was replaced by Jeff Waters, who touted his leadership at solar panel manufacturer Maxeon during its spin-off from SunPower. Those accolades look less auspicious from today’s standpoint: SunPower went bankrupt last year, and Maxeon’s valuation has tumbled precipitously from its 2023 levels.
Last fall, Powin turned to the credit business at KKR, a private-equity trailblazer famous for record-busting leveraged buyouts like RJR Nabisco in the 1980s and utility TXU in the 2000s.
“The facility will be instrumental in supporting Powin’s working capital needs, driving continued innovation, and further enhancing the company’s financial flexibility as it expands its leadership position in the storage industry,” KKR said in a press release from October announcing the $200 million facility.
It’s a strange thing when a company that just secured ample working capital then runs out of working capital just a few months later. Sources familiar with Powin’s business said the debt package, paradoxically, hastened the company’s demise.
Powin drew on only about $25 million of the available debt, but the deal company leadership accepted was “very ugly” and “poorly structured” for Powin’s purposes, said one former Powin customer granted anonymity to speak on sensitive business matters. Another grid storage veteran, who also spoke on condition of anonymity, likened the situation to a payday loan: “They got upside down, and KKR called it in.”
KKR declined to comment on the specifics of Powin’s debt facility.
Powin wouldn’t be the first cleantech company that failed after getting behind on its debt payments. Major rooftop solar provider Sunnova increasingly turned to corporate debt to raise cash as the market soured, then struggled to find cash for debt payments and fell into bankruptcy in June. Electric bus maker Proterra piled up corporate debt before its bankruptcy filing in 2023. When it’s time to pay the tab, even a promising customer pipeline is no legal tender.
Powin’s financial collapse triggered an existential question for all the storage plants out there running on its hardware and software.
“Everyone’s trying to figure out how to maintain their products and solutions and not have bricked systems,” the former customer said.
Software needs updates, as anyone with an iPhone is repeatedly reminded, and the same goes for the systems that tell huge banks of batteries when to charge and discharge. Energy market rules change; hardware trips up. If Powin simply ceased to exist, it would jeopardize the reliability of all the critical power plants running on its control systems.
But those anxious battery owners may soon get some relief now that software startup FlexGen became a stalking horse bidder in June, proposing to buy “substantially all” of Powin’s assets for $36 million. It’s also lending money to keep Powin operating in the meantime. There will still be an auction, and other firms could bid more. But if all goes according to plan, this process will conclude by early August.
FlexGen CEO Kelcy Pegler said he had great respect for Powin, and “gratitude for them being an early mover” in the grid storage industry.
“Powin was such a substantial part of the market,” Pegler told Canary Media. “FlexGen’s interest is in making sure the customers have a successful path to continuous operations.”
FlexGen, based in Durham, North Carolina, employs some 120 software engineers to constantly maintain and improve its storage management software, Hybrid OS, Pegler noted; that product works on whatever storage hardware the customer wants to operate. If the bid goes through, FlexGen will first provide Powin customers with a “continuity plan” that keeps systems running as they are, and customers will have the option to sign new long-term service agreements with FlexGen.
Customers will have good reason to switch over to FlexGen’s flagship product, Pegler added: An independent market study by cleantech data firm Orennia found that batteries running on FlexGen software performed better than those running on that of Powin (and other competitors) in the wholesale markets of Texas and California in 2023.
As for the business of buying battery cells and turning them into storage plants, Pegler is happy to leave that to the existing field of storage manufacturers. He plans to stick to software and services.
Powin has let go of much of its staff. The founders will lose their stakes, and the venture capitalists and private-equity investors won’t rake in a multiple on their few hundred million dollars invested. But a sale to FlexGen would protect Powin’s physical legacy: The gigawatt-hours of batteries installed across the world could keep on humming, as the energy storage market careens ever onward.
As temperatures across New England soared above 100 degrees Fahrenheit in recent weeks, solar panels and batteries helped keep air conditioners running while reducing fossil-fuel generation and likely saving consumers more than $20 million.
“Local solar, energy efficiency, and other clean energy resources helped make the power grid more reliable and more affordable for consumers,” said Jamie Dickerson, senior director of clean energy and climate programs at the Acadia Center, a regional nonprofit that analyzed clean energy’s financial benefits during the recent heat wave.
On June 24, as temperatures in the Northeast hit their highest levels so far this year, demand on the New England grid approached maximum capacity, climbing even higher than forecast. Then, unexpected outages at power plants reduced available generation by more than 1 gigawatt. As pressure increased, grid operator ISO New England made sure the power kept flowing by reducing exports to other regions, arranging for imports from neighboring areas, and tapping into reserve resources.
At the same time, rooftop and other “behind-the-meter” solar panels throughout the region, plus Vermont’s network of thousands of batteries, supplied several gigawatts of needed power, reducing demand on an already-strained system and saving customers millions of dollars. It was a demonstration, supporters say, of the way clean energy and battery storage can make the grid less carbon-intensive and more resilient, adaptable, and affordable as climate change drives increased extreme weather events.
“As we see more extremes, the region still will need to pursue an even more robust and diverse fleet of clean energy resources,” Dickerson said. “The power grid was not built for climate change.”
On June 24, behind-the-meter solar made up as much as 22% of the power being used in New England at any given time, according to the Acadia Center. At 3:40 p.m., total demand peaked at 28.5 GW, of which 4.4 GW was met by solar installed by homeowners, businesses, and other institutions.
As wholesale power prices surpassed $1,000 per megawatt-hour, this avoided consumption from the grid saved consumers at least $8.2 million, according to the Acadia Center.
This estimate, however, is conservative, Dickerson said. He and his colleagues also did a more rigorous analysis accounting for the fact that solar suppresses wholesale energy prices by reducing overall demand on the system. By these calculations, the true savings for consumers actually topped $19 million, and even that seems low, Dickerson said.
In Vermont, the state’s largest utility also relieved some of the pressure on the grid by deploying its widespread network of residential and EV batteries. That could save its customers some $3 million by eliminating the utility’s need to buy expensive power from the grid and reducing fees tied to peak demand.
“Green Mountain Power has proven that by making these upfront investments in batteries, you can save ratepayers money,” said Peter Sterling, executive director of trade association Renewable Energy Vermont. “It’s something I think is replicable by other utilities in the country.”
Green Mountain Power’s system of thousands of batteries is what is often called a “virtual power plant” — a collection of geographically distributed resources like residential batteries, electric vehicles, solar panels, and wind turbines that can work together to supply power to the grid and or reduce demand. In Vermont, Green Mountain Power’s virtual power plant is its largest dispatchable resource, spokesperson Kristin Carlson said. The 72-MW system includes batteries from 5,000 customers, electric school bus batteries, and a mobile, utility-scale battery on wheels.
The network began in 2015 with the construction of a 3.4-megawatt-hour storage facility at a solar field in Rutland, Vermont. Two years later, the utility launched a modest pilot program offering Tesla’s Powerwall batteries to 20 customers, followed in 2018 by a pilot that paid customers to share their battery capacity during high-demand times. In 2022, a partnership with South Burlington’s school district linked electric school buses to the system, and in 2023, state regulators lifted an annual cap on new enrollments it had imposed on a Green Mountain Power program that leases batteries to households. The number of customers with home batteries has since grown by 72%.
“We’ve had a really dramatic expansion,” Carlson said. “It is growing by leaps and bounds.”
The network saved consumers money during the heat wave by avoiding the need to buy power at the high prices the market reached that day, but also by helping to lower the “capacity fees” charged by ISO New England. These charges are determined by the one hour of highest demand on the grid all year, and then allocated to each utility based on their contributions to that peak. By pulling power from batteries rather than just the grid, Green Mountain Power lowered its part of the peak.
If the afternoon of June 24 remains the time of peak demand for 2025, Green Mountain Power’s 275,000 customers will save about $3 million in total and avoided power purchases, the utility calculated. Looking ahead, more hot weather and further expansion of the utility’s virtual power plant will likely continue to put money back in customers’ pockets, Sterling said: “When you play that out over many years, that’s real savings to ratepayers.”
In late spring, the Department of Energy ordered two aging and costly fossil-fueled power plants that were on the verge of shutting down to stay open. The agency claimed that the moves were necessary to prevent the power grid from collapsing — and that it has the power to force the plants to stay open even if the utilities, state regulators, and grid operators managing them say that no such emergency exists.
More of these orders could be on the way. The DOE published a report this week, in response to one of the “Beautiful Clean Coal” executive orders issued by President Donald Trump in April, that lays out the case for Energy Secretary Chris Wright, a former gas industry executive who has denied there is a climate change crisis, to demand that more fossil-fueled plants remain open past their scheduled closures.
But state regulators, regional grid operators, environmental groups, and consumer groups are pushing back on the notion that the grids in question even need these interventions — and are challenging the legality of the DOE’s stay-open orders.
Last month, state utility regulators and environmental groups filed rehearing requests with the DOE, demanding that it reconsider emergency orders to force the J.H. Campbell coal plant in Michigan and the Eddystone oil and gas-burning plant in Pennsylvania to stay open through the summer.
The DOE claimed that the threat of large-scale grid blackouts forced its hand. But state utility regulators, environmental groups, consumer advocates, and energy experts say that careful analysis from the plant’s owners, state regulators, regional grid operators, and grid reliability experts had determined both plants could be safely closed.
These groups argue that clean energy, not fossil fuels, are the true solution to the country’s grid challenges — even if the “big, beautiful” bill signed by Trump last week will make those resources more expensive to build. Some of the environmental organizations challenging DOE’s orders have pledged to take their case to federal court if necessary.
“We need to get more electrons on the grid. We need those to be clean, reliable, and affordable,” said Robert Routh, Pennsylvania climate and energy policy director for the Natural Resources Defense Council, one of the groups demanding that DOE reconsider its orders. Keeping J.H. Campbell and Eddystone open “results in the exact opposite. It’s costly, harmful, unnecessary, and unlawful.”
The groups challenging the DOE’s J.H. Campbell and Eddystone stay-open orders point out that the agency is using a power originally designed to protect the grid against unanticipated emergencies, including during wartime, but without proving that such an emergency is underway.
“This authority that the Department of Energy is acting under — Section 202(c) of the Federal Power Act — is a very tailored emergency authority,” said Caroline Reiser, NRDC senior attorney for climate and energy. “Congress intentionally wrote it only to be usable in specific, narrow, short-term emergencies. This is not that.”
For decades, the DOE has used its Section 202(c) power sparingly, and only in response to requests from utilities or grid operators to waive federal air pollution regulations or other requirements in moments when the grid faces imminent threats like widespread power outages, Reiser said.
But the DOE’s orders for Eddystone and J.H. Campbell were not spurred by requests from state regulators or regional grid operators. In fact, the orders caught those parties by surprise.
They also came mere days before the plants were set to close down and after years of effort to ensure their closure wouldn’t threaten grid reliability. J.H. Campbell was scheduled to close in May under a plan that has been in the works since 2021 as part of a broader agreement between utility Consumers Energy and state regulators, and which was approved by the Midcontinent Independent System Operator (MISO), the entity that manages grid reliability across Michigan and 14 other states.
“The plant is really old, unreliable, extremely polluting, and extremely expensive,” Reiser said. “Nobody is saying that this plant is needed or is going to be beneficial for any reliability purposes.”
To justify its stay-open order, the DOE cited reports from the North American Electric Reliability Corp. (NERC), a nonprofit regulatory authority that includes utilities and grid operators in the U.S. and Canada. NERC found MISO is at higher risk of summertime reliability problems than other U.S. grid regions, but environmental groups argue in their rehearing request that the DOE has “misrepresented the reports on which it relies,” and that Consumers Energy, Michigan regulators, and MISO have collectively shown closing the plant won’t endanger grid reliability.
Eddystone, which had operated only infrequently over the past few years, also went through a rigorous process with mid-Atlantic grid operator PJM Interconnection to ensure its closure wouldn’t harm grid reliability. The DOE’s reason for keeping that plant open is based on a report from PJM that states the grid operator might need to ask utility customers to use less power if it faces extreme conditions this summer — an even scantier justification than what the agency cited in its J.H. Campbell order, Reiser said.
As long as the DOE continues to take the position that it can issue emergency stay-open orders to any power plant it decides to, these established methods for managing plant closures and fairly allocating costs will be thrown into disarray, she said.
“We have a system of competitive energy markets in the United States that is successful in keeping the lights on and maintaining reliability the vast, vast majority of the time,” Reiser said. “The Department of Energy stepping in and using a command-and-control system interferes with those markets.”
Utility regulators from MISO states including Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, and Wisconsin made a similar argument in their rehearing request to the DOE. “This expansive use of emergency powers sets a troubling precedent, enabling intervention in routine, state-approved planning decisions without an actual crisis,” they wrote. “Such preemptive action risks undermining the credibility of future emergency orders, distorting market signals, and eroding the statutory balance between federal and state authority.”
Dan Scripps, chair of the Michigan Public Service Commission, highlighted the years of work that went into enabling the J.H. Campbell plant to safely close, and the hundreds of millions of dollars that replacing it with fossil gas, solar, and battery resources would save.
“For DOE to substitute its judgment of what’s necessary for the work that’s done by the states and the regional grid operators is something that a large number of states of different political makeups find most troubling,” he said.
Forcing aging and expensive power plants to stay open past their long-planned retirement dates also threatens to drive up costs for utility customers at a time when energy prices are already set to rise due to GOP policies. Think tank Energy Innovation forecasts the megabill passed by congressional Republicans last week will lead to a 25% increase in wholesale electricity prices by 2030, as cuts to tax credits stifle investment in solar, wind, and battery projects and force power grids to rely on older, costlier resources.
This week’s DOE report “is another attempt to push the false narrative that our country’s energy future depends upon decades-old coal- and gas-plants, rather than clean renewables,” Greg Wannier, senior attorney at the Sierra Club, said in a statement. “The only energy crisis faced by the American public is the catastrophic increase in costs that the Trump Administration is forcing on the country’s ratepayers.”
Coal has fallen from nearly half U.S. generation capacity in 2011 to just 15% last year, and more than 120 U.S. coal plants are expected to close over the next five years. Coal industry groups and many Republicans blame state climate regulations for that trend. But energy experts agree that the primary driver is that coal plants are unable to provide power at prices that can compete with fossil gas or renewables.
Aging power plants like J.H. Campbell and Eddystone, which were built roughly 60 years ago, are among the most expensive to run — one of the main reasons why those two were both slated for retirement. Forcing them to restart and stay open for three months on the eve of their planned closures involves additional costs to secure new fuel contracts, undertake deferred maintenance, and rehire workers.
Utility customers in the Midwest and mid-Atlantic grid regions those plants are connected to will now bear all of those costs. While the total dollar amount has yet to be calculated, it could run into the tens of millions for each plant, or as much as $100 million for J.H. Campbell, Scripps told reporters in June.
Under its Section 202(c) authority, the DOE doesn’t have to deal with the costs its emergency orders incur, said Clara Summers, campaign manager for the Citizens Utility Board, an Illinois-based utility customer watchdog group. Instead, it gets to delegate the method of recovering those expenses to grid operators and regulators.
But the DOE has failed to show that keeping those plants open will benefit customers, which puts those entities in a bind.
“There is a standard in ratemaking that costs should be prudently incurred,” Summers said. “Since these costs are manufactured emergencies and are not prudently incurred, they are not just and reasonable.”
That’s the argument that environmental and consumer watchdog groups have made in filings with the Federal Energy Regulatory Commission, the agency tasked with overseeing the U.S. power grid. The groups have asked FERC to reject plans to recover costs from DOE’s J.H. Campbell and Eddystone orders on the grounds that the DOE has failed to show how keeping the plants open will benefit consumers.
“What’s especially frustrating about that is that we already have capacity markets that are there to make sure that we have enough electricity, and consumers already pay for that,” Summers said. Those costs to utility customers are rising dramatically in PJM, where years of backlogged interconnection processes have prevented new solar, wind, and battery projects from coming online to help replace power plants being closed. MISO also saw prices spike in its most recent capacity auction.
“The whole function of those markets is to ensure we have enough electricity — and those markets procure enough electricity,” Summers said. “This is something PJM agrees with, that MISO agrees with, that NERC agrees with.”
The DOE has 30 days from when the rehearing requests were filed to open a review of its stay-open orders, Reiser said. If the DOE doesn’t issue an order within that time, “it basically opens up the option for us to go to court.”
The DOE has never used its Section 202(c) authority in this way before, which means it has never been challenged in court on the issues at hand, Reiser said.
But “the fact that there are related executive orders kind of directing the Department of Energy to do these things doesn’t change the basic standards of how our legal system works and how courts interpret statutes,” she added. “No matter the reasoning, they still have to comply with the law.”
RENO, Nev. — I was supposed to be looking at the largest energy-storage installation ever assembled from used electric-vehicle batteries, the tantalizing new side project of former Tesla Chief Technology Officer JB Straubel’s recycling juggernaut, Redwood Materials. Instead, all I saw was a dusty field strewn with oddly shaped boxes wrapped in some kind of plastic sheeting. The boxes were propped up on cinder blocks, in the manner of rusted cars in a forgotten yard. It looked a bit like a garbage dump.
My Redwood tour guide assured me, however, that we were in the right place. Underneath those white shrouds were 792 individual EV battery packs, wired up in long rows and spread across two acres on the firm’s campus outside Reno, Nevada. The plastic wrapping was meant to protect them from the dust. Nearby was a field of solar panels laid flat on the ground, making it hard to gauge just how far back they went. These panels convert sunlight to electricity and store it in the array of old car batteries, to power a miniature data center that a startup named Crusoe built in the same field as the batteries. Any surplus power flows to Redwood’s own facilities surrounding the installation.
Redwood hailed the installation as a breakthrough in the sleepy field of second-life batteries, which has been around for a while but failed to move beyond initial proofs of concept to repeated, large-scale deployments. The firm has indeed broken a record for that stunted sector, certainly in the U.S. and likely the world, delivering 63 megawatt-hours of second-life grid storage in its own backyard. That’s a very deep reservoir of storage for the diminutive onsite data center, which has just 1 megawatt of computing load. The goal is to guarantee 24/7 clean power even with days of inclement weather.
Given the initial success, Straubel sees the energy storage business as a key growth area for Redwood, which was founded in 2017 to recycle battery materials into the domestic supply chain.
“This is, in a way, a first of its kind, and to be able to have a profitable project as a first one is pretty cool,” Straubel said prior to a sunset celebration of the project, held on the desert outcropping above it. “You will absolutely see much larger deployments of this in well under a year, and we are actively engineering and working on those projects today.”
Assuming the concept scales up further, it could be a game changer for data centers that prize speedy new energy construction. But it could further reshape the clean energy transition. Dozens of startups have toiled for years to invent new batteries for long-duration storage. Redwood has already beaten them to a large-scale deployment, without inventing anything new and risky — all it took was some clever reimagining of what others viewed as waste.
Using old EV batteries to store energy for the grid makes intuitive sense. Diminished battery capacity is a bigger deal for a vehicle than it is for grid storage; stationary stuff doesn’t need to work as hard as EV batteries, and it can take up a lot more space. A battery with just 80% of its original capacity left may get plucked from a vehicle, but it can still function fine for storing solar power. In theory, these secondhand batteries should be cheaper than new ones, reducing the cost of much-needed grid storage to accompany the rise of renewables.
Yet few second-life grid storage installations exist.
Most of the people who have actually installed second-life batteries have approached it as a small-scale research project, typically grant-funded. A scrappy company called B2U Storage Solutions broke that mold in 2020, when it built an array of old packs to deliver solar power into California’s energy markets in the most lucrative evening hours. I verified that with my own eyes in 2021, since it went far beyond the sector’s accomplishments at the time. B2U has since expanded the capacity to 28 megawatt-hours, but I haven’t seen a repeat project at that scale yet (though the company did build a 12-MWh project elsewhere in California).
Another startup called Element Energy obtained a bounty of lightly used packs, quite possibly through their investor LG, which endured a billion-dollar recall for units it supplied to General Motors a few years back. Element installed a couple dozen containers in West Texas last year, filled with 53 megawatt-hours of second-life storage. Next, it plans to build a factory to mass-produce enclosures for second-life installations.
Now, Redwood has entered the scene with its sprawling Nevada installation.
All of these developers have had to grapple with the same initial challenges. They need to get their hands on old EV packs and then sort out the ones that aren’t going to catch fire. Then they have to figure out how to safely control a patchwork fleet of batteries cobbled together from several manufacturers.
Redwood immediately stands out for its ability to handily source old packs. The company is, officially, a battery recycler, and it says it receives more old batteries than any of its U.S. competitors. All week long, trucks drop off pallets of everything from toothbrush batteries to electric-truck packs, which workers sort and stash in a 32-acre open-air depot. (Redwood says the safety benefits of super-dry air outweigh any risks associated with the bludgeoning Nevada sunshine.)
“If you ever used a lithium-ion battery, it’s probably going to end up coming through here in one way, shape, or form,” Straubel said. EV packs have been shooting up as a portion of total intake, from less than 1 gigawatt-hour per year in 2023 to more than 5 now, he added.
“That’s really one of the keys, is having the scale and having the access to the partnerships and the ability to move and transact and just physically harness that much material,” Straubel said.
Another differentiator might as well be called moxie. Founder Straubel sets the tone as a clean-energy nerd who just likes to give things a shot. He tried second-life microgrids at home before making it a focus for the workplace. His engineers hacked together a universal controller box that connects to each type of EV pack and operates it according to its unique needs. When the time came to test the concept, Straubel oversaw construction of the biggest second-life storage project in the world, all in five months from clearing ground to completion. No grant applications required.
Lastly, the Redwood approach bucks conventional opinion in ways that save time and money.
The storage industry, as a rule, puts its batteries in big metal boxes. Redwood engineers saw that as unnecessary, given how painstakingly ruggedized the packs had to be for vehicular use. No big boxes means no pouring concrete pads. The approach saves on labor, time, and materials.
“There’s almost no poured concrete, frankly — it’s a very light touch on the ground,” Straubel said. “You can pick up and move everything. You can deploy it very fast. Solar was the same way. We actually used this type of architecture specifically because we could deploy it very fast.”
On the solar side, Redwood went with a company that shares the “just throw it on the ground” mentality: Erthos, a scrappy new alternative to the highly engineered trackers that eke every last electron out of the day’s solar arc. This flat-on-the-ground installation also allows a handful of cleaning robots to circumnavigate the array daily and wipe the dust away; their little headlights peeked through the night as Redwood’s celebration cast laser lights across the battery field.
Redwood launched Redwood Energy, its business line for second-life storage, at a precarious time for the battery recycling industry, which has promised to recover nearly all the useful materials from old EV batteries.
Redwood succeeded in raising nearly $2 billion in equity investment since its founding in 2017. It seems to have plenty of resources for the time being. But a leading competitor, Li-Cycle, declared bankruptcy this year after failing to raise the money to complete its recycling facility in upstate New York. Another top contender, Ascend Elements, has pushed back its timeline for a facility in Kentucky, citing delays from its anchor customer.
The actual task of economically recovering the most valuable battery materials appears to have proven harder in practice than it looked in the pitch decks. Setting aside the technical challenges, there are serious business obstacles. Many key battery commodities have fallen steeply from high prices a few years back, undercutting the value of the recycled products. And there isn’t yet a critical mass of cathode makers to sell to in the U.S., so any recovered materials are just going to generic metals markets for now.
“In a way, we started Redwood almost too early,” Straubel admitted. He was talking about how used EV packs were hard to come by a few years ago. But Redwood and the other recyclers are also now too early for the domestic EV-battery-materials market they would like to sell into.
While that market for recycled materials develops, Redwood can pull in “almost an order of magnitude” more value from its batteries by deploying them for energy storage needs.
“Every battery that we can possibly redeploy, even for as short as a few months, we see a compelling financial case to do that,” Straubel said. In fact, he noted, “This definitely has the potential to grow faster and even to contribute more revenue than the core recycling business.”
That’s somewhat jarring to hear from the battery recycling startup with the most money behind it. The investors funded a battery materials business, not a second-hand battery purveyor. But Straubel stressed that he sees the energy business as additive, not competitive with the original business.
“We’re not getting rid of that material — we’re actually keeping ownership of it,” he said. “We’re keeping the rights to recycle it, and we’re excited to recycle it when it’s done doing its second life in energy storage.”
Redwood Energy is talking with AI customers around the country, but it’s also well-positioned in a desert valley east of Reno that has become something of an industrial and telecom hub. A particularly energetic trick-or-treater could leave Redwood’s campus and knock on the doors of Google, Apple, and Switch, the owner of a fortress-like data center. Microsoft just acquired 300 acres in the neighborhood.
“Those would be logical targets,” Straubel allowed.
A clarification was made on July 7, 2025: This article has been updated to clarify that B2U built a 12-MWh second-life storage facility in California, in addition to its initial 28-MWh installation.
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