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AI infrastructure startup Crusoe has always differentiated itself from its competitors by finding creative ways to tap energy. Now, it’s investing in two of the most potentially transformative battery technologies on the market.
Crusoe has signed a deal with Form Energy to purchase 120 megawatts of iron-air batteries, which would store a massive 12 gigawatt-hours of electricity. Form promises that this novel type of battery — the first commercial installation is still under construction — will make renewable energy available for days on end, a crucial breakthrough for cleaning up the grid but also for cleanly powering data center operations. The deal comes just a month after Form won a 30-gigawatt-hour contract to supply a Google data center in Minnesota with round-the-clock clean energy.
Crusoe also said Tuesday it was doubling down on used electric vehicle batteries as a tool for cheaply storing electricity for computing.
Last summer, the company installed four modular data centers on the Nevada campus of battery recycling startup Redwood Materials; the latter built a field of solar panels and wired up an array of EV battery packs to serve round-the-clock clean power to Crusoe. After about nine months of operations, Crusoe decided to add 20 more of its modular Spark data centers to the site, utilizing the existing microgrid for a lot more computing. And Redwood said Wednesday it had passed key safety tests for its used-battery architecture, clearing the way for broader deployment.
The two announcements, emerging from the bustling CERAWeek energy conference in Houston, signal how one of the nation’s leading energy-savvy data center developers is scouting futuristic clean energy tech to speed the AI buildout today.
Crusoe launched in 2018 as a bitcoin miner that leveraged stranded energy resources, like oil-field gas that would have been flared. Its founders designed rugged computing modules that could survive in harsh circumstances, and built up domestic supply chains to give them more certainty on timing and delivery. Later, they flipped that expertise into the emerging AI infrastructure market.
Then, Crusoe shot to an improbable level of prominence for a startup of its size (it closed a $600 million fundraise in late 2024, valuing the company at $2.8 billion). Oracle chose Crusoe in 2025 to build the largest and most famous data center project to date: the Stargate flagship in Abilene, Texas. Stargate is typically described as a $500 billion effort, though that number actually refers to the broader joint venture between AI juggernaut OpenAI, cloud provider Oracle, and Japanese investment firm SoftBank. Crusoe has delivered two buildings in Abilene, which each consume about 100 megawatts to run their GPUs.
Setting aside the lingering questions around how much of the $500 billion investment pledge actually gets spent, it’s clear that Crusoe has leaped to the upper echelon of the AI industry. That means its choices to embrace novel clean energy technologies could turbocharge their pace of deployment and inspire new customers to follow suit.
The Form deal is a confident first bite. The purchase of 12 gigawatt-hours represents more storage capacity than any existing battery plant on the grid. To be clear, the deal does not imply that all that capacity will go to one site (and there’s no indication that iron-air batteries will go to Abilene in particular).
“They have a lot of projects that they’re working on simultaneously,” Form CEO Mateo Jaramillo told Canary Media. “They can choose where these first installations happen.”
The deal reserves iron-air batteries that will be manufactured in Weirton, West Virginia, and sets terms for the eventual purchase, Jaramillo said. Form is expanding its production capacity from 15 megawatts to 50 megawatts in a few months and will start initial deliveries of Crusoe’s 120 megawatts in 2027. At this point, Form has sold out its production through 2028 and is focused on executing the factory expansion, Jaramillo said.
Form chose iron as its key battery ingredient because it’s so cheap, which makes it economically viable to store and release clean energy over much longer time horizons than the four or five hours that today’s lithium-ion batteries are designed for. This means that a data center could rely on cheap wind and solar power, but call on Form’s tech to ensure on-demand electricity through multiday bouts of bad weather.
That serves Crusoe’s goal of bringing its own capacity as it builds data centers. Doing so avoids having to wait around for lengthy grid upgrades, and portends better community relations than having data centers compete with everyone else for existing power supplies.
Like Form, Redwood is working to deliver batteries with many more hours of storage, and at a radically lower price, than today’s lithium-ion batteries. Redwood does this not through breakthroughs in electrochemistry but by repurposing battery packs that would otherwise be dismantled.
Redwood’s original system looked like the product of creative tinkering — a field full of oddly shaped packs propped up on cinder blocks, quite unlike the uniform metal containers at most grid battery plants. Since then, it has formalized the architecture. Metal racks have replaced the cinder blocks, for instance, and the packs are mounted vertically so that more fit in a given space.
For performance, the company noted that its solar-battery microgrid has operated 99.2% of the time since installation. That’s commendable for a microgrid powered only by solar panels, but not up to the usual standards for AI computing. A spokesperson for Crusoe noted the data centers at Redwood’s campus tapped grid power as backup to maintain 99.9% uptime.
For the business to grow, Redwood founder JB Straubel (formerly CTO at Tesla, where Jaramillo once helmed the energy storage business) also needed to prove that the system wouldn’t catch fire. Just this month, Redwood cleared a barrage of safety tests by UL Solutions, the renowned independent safety lab. The repurposed batteries prevented the spread of fire from pack to pack, said Andrew Hoover, who leads product safety and compliance for Redwood. The Redwood team also ran a high-octane “deflagration” test by injecting explosive gases into a pack and igniting them. In this “absolute worst-case” scenario, Hoover noted, “the pack safely vented those gases out.”
Redwood’s battery installations buck the industry convention of stuffing batteries in a big metal container. But that decision makes the systems “inherently safe without relying on all these complex mitigation systems,” Hoover said. There’s no big box for explosive gas to build up in, and the packs are spread out enough to isolate any fire that might start.
With this safety credential to assuage potential customer concerns, Redwood is in a position to ship beyond its own campus in Nevada. Crusoe has plenty of other data center developments in need of power, and its latest storage deals expand its energy arsenal.
Harris Ranch Resort isn’t close to much. Residents of California’s major cities know it mainly as a rest stop about halfway between Los Angeles and San Francisco on Interstate 5’s long run through the San Joaquin Valley. The sprawling stucco building has a Western-themed gift shop and a couple of good restaurants where travelers can enjoy regional specialties like tri-tip tacos and almond-smoked prime rib — perhaps while they charge their EV at one of the Tesla stations outside.
But in the vast expanse of California’s Westlands Water District, the ranch is about the most central spot for a meeting. On a sunny afternoon in late January, Jeff Fortune, Ross Franson, and Jeremy Hughes, three of the nine directors of the country’s largest agricultural water agency, gathered there for lunch to discuss an ambitious plan to rescue some of the most productive farmland in the U.S. from a decades-long water crisis.
The Valley Clean Infrastructure Plan (VCIP) envisions converting 136,000 acres of land into 21 gigawatts of battery-backed solar power — nearly as much utility-scale solar capacity as has been installed in California to date.
“This will be not only the largest project in California, or the largest project in the United States,” said Fortune, a third-generation farmer and the district’s board president since 2022. “This will be the largest project in the world.”
The scale of the plan matches that of the land. Westlands Water District was formed more than 60 years ago to collectively manage water resources and irrigation infrastructure for the farmers within its 1,000-square-mile territory. The district’s 614,000 acres grow billions of dollars’ worth of crops per year — grapes, lettuce, tomatoes, onions, garlic, citrus fruits, almonds, pistachios, and many others. Those crops make up a major share of the bounty in a region that produces a quarter of the country’s food, including 40% of its fruits and nuts.
Fortune, Franson, and Hughes run family farming operations that collectively own or manage thousands of acres of a landscape transformed by industrial-scale irrigated agriculture. The water flows from reservoirs hundreds of miles north and is pumped from the Sacramento–San Joaquin River Delta via the Central Valley Project, one of the biggest water projects in the state. The water supply is augmented by wells that have delved ever deeper into the region’s aquifers.
But that water supply is drying up. Since the 1990s, surface-water cutbacks from the environmentally stressed delta have led to the fallowing of hundreds of thousands of acres. And under state law, Westlands farmers face increasingly strict limits on the groundwater they use.
Now, after decades of fighting state and federal agencies and lobbying Congress to increase the flow of water, Westlands farmers are shifting to a new approach. “Our hand is forced,” Fortune said. “Everyone’s in the same sinking ship together.”
VCIP could keep the ship afloat by financing a wholesale conversion of fallowed land into solar farms and battery storage systems capable of powering the equivalent of 9 million homes. To carry those clean electrons to market, the district will finance and build a transmission network that will speed interconnection to California’s congested grid and expand power flows between the state’s two biggest utilities, Pacific Gas & Electric and Southern California Edison.
None of this has happened yet, and completing it will take 10 years or more. But after years of work with developer Golden State Clean Energy, VCIP is now poised to move from concept to reality.
In December, Westlands Water District’s board approved the programmatic environmental impact report that lays out a master plan for the project. Hughes, a fifth-generation farmer who has been operating in Westlands for a quarter century, said that about 150 contracts so far have been signed by growers to make land available — including about 800 acres of his family’s land.
“The way we look at it is as a new crop,” he said. “We’re harvesting the sun and producing electricity.”
Critically, farmers will retain land ownership under VCIP’s lease and easement deals, and thus, access to the water allocations. And under Westlands’ agricultural-land repurposing plan and its VCIP master plan, water allocations for acres put into solar can be redirected to remaining farmland.
“You’re making the district more sustainable,” Fortune said, summing up the plan. “And that just helps the grower, it helps the communities, it helps the farmworkers — everybody.”
That help is desperately needed. The farms that make up Westlands Water District — many of them sprawling, multigenerational family-run organizations with substantial landholdings — have struggled for years with drainage challenges, salination, and other effects of heavy irrigation, which have polluted watersheds. The communities in and around the district have high rates of poverty and unemployment, a lack of economic opportunities, tainted groundwater, and inadequate investment in roads, schools, and public safety. State law requires VCIP to include a community benefits plan that delivers economic value to not just its growers but also the local governments and residents.
While it will be a massive and complicated undertaking, California needs four to five times as much new clean energy and storage as this project is slated to provide in the next 20 years, said Franson, president of farming at Woolf Farming & Processing, which cultivates 30,000 acres across the San Joaquin Valley, most of it in Westlands.
The master plan could provide a model for what the state must accomplish to meet that need for power on a grand scale, he said. “There’s so much talk in the state about the demand they’re seeing, about energy transition, about water issues … This hits all those boxes.”
Highway 33 runs south from the Mendota pool, a key water-exchange point for the San Joaquin Valley’s interlocking irrigation systems, and into Westlands Water District’s northeastern zone.
On a cold winter morning, Jose Gutierrez, the district’s assistant general manager, and I drove along the two-lane road through a thick blanket of Tule fog. Despite the limited visibility, Gutierrez had no trouble pointing out the solar farms on both sides of us. Farther down the road, pile drivers rattled away, busy planting anchor posts for yet more solar projects.
The installations there now are a fraction of what’s envisioned under VCIP. If that plan is fully realized, the trucks roaring up and down Highway 33 will pass solar fields stretching uninterrupted for roughly 30 miles, Gutierrez said. The surrounding area is slated for solar for a simple reason: It’s no longer irrigable.
Much of the land designated for solar development under the master plan is drainage-impaired — undergirded by a shallow layer of clay soil that prevents water from percolating deeper. As water accumulates above the clay layer, it becomes increasingly salty, but cannot be flushed out — and there’s no easy fix, thanks to a decades-old impasse between the federal government and the water district.
Under a 2015 settlement agreement with the U.S. Bureau of Reclamation, Westlands was required to retire at least 100,000 acres from irrigated agriculture. In 2022, the district launched a land purchasing program to take on managing the retirement and eventual remediation of those drainage-impaired acres.
That land can still be planted with wheat or other cereal crops that tolerate being irrigated by rainfall alone, or leased to sheepherders. “But its value from a commodity perspective is pretty low,” Gutierrez said. As a result, it has mostly been left unused.
In fact, it’s a financial drag on the district. Idle land must still be managed to prevent pests and invasive weeds from setting in and endangering neighboring farms. Several times while on the highway, I spotted signs on utility poles advertising barn-owl boxes for rent — the birds help control gopher populations. And the debt the district took on to buy the fallowed acres must be paid off.
All this makes the land ideal for solar in a region whose clean energy potential is well understood. State agencies have designated large swaths here as the Westlands Competitive Renewable Energy Zone, meaning they are primed for solar development. Studies from universities and nonprofit groups indicate that the San Joaquin Valley can build solar while retaining sustainable levels of agriculture.
In the 13 years Gutierrez has worked for the district, eight solar projects have been launched on non-irrigable lands that the district has purchased and sold to developers. The biggest ones include the Darden Clean Energy Project, a 1.15-gigawatt solar-battery system being constructed on about 9,500 acres in the district’s central area; and Westlands Solar Park, a 2.27-gigawatt multistage development on roughly 20,000 acres in the district’s southern reaches.
Private landowners, like Fortune, Franson, and Hughes, have also been making deals with developers, and many other farmers could follow suit, Gutierrez said. In fact, VCIP expects that roughly half the 136,000 acres of solar and batteries it plans to develop will be on privately owned land.
Water shortages are the primary reason that Westlands growers are seeking alternatives to farming. But growers are facing other pressures, too, Gutierrez said. Volatile commodity prices have driven a boom and bust in certain crops, such as almonds. Rising energy and labor costs have taken their toll.
Landowners are eager to move more acres into solar to defray these costs, hedge against market risks, and bolster their bottom lines, he said. But there are roadblocks. Solar developers face long and onerous environmental reviews for each project under the California Environmental Quality Act, as well as drawn-out county permitting processes. And in California, as in many other parts of the country, limited grid capacity is forcing projects to wait for years in clogged-up interconnection queues.
Patrick Mealoy, partner and chief operating officer of Golden State Clean Energy, the VCIP developer, summarized the situation as a convergence of factors. “The land use planning, the water restrictions in the valley, the congestion on the transmission grid,” he said, “screamed for a master plan.”
Mealoy was part of the development team that put together a similar, if much smaller, master plan for Westlands Solar Park, the biggest solar-battery project in the district to date. That plan set key terms for individual developers on issues ranging from environmental mitigation and land management practices, to standard lease and contract requirements, to agreements regarding the arrays’ eventual decommissioning.
VCIP takes essentially the same approach, Mealoy said. Golden State Clean Energy itself will likely develop less than a fifth of the 21 gigawatts and will be working with independent developers for the rest, he said. But it’s far more efficient to create a master plan than to have each developer go it alone.
“When you look at the sheer magnitude of the tens of thousands of megawatts we need to build in California, the targets are getting higher. We’re doing a remarkable job, but we’re actually falling behind,” he said. “VCIP is enormous, but it’s a fraction of what we have to add.”
The programmatic environmental impact review approved by the district in December is the culmination of that master planning effort, Gutierrez said. It took two years, but now that it’s done, “it sets a standard for all VCIP solar developments of what they’re going to have to follow.”
That includes requirements for limiting construction impacts like air pollution, noise pollution, traffic safety, fire prevention, and the like, he said — an important consideration for nearby communities.
It also sets out how solar farms will be maintained once they’re built, said Allison Febbo, Westland’s general manager. That’s good not just for the neighbors but also for the developers.
Individual projects will still need conditional land use permits and construction permits from Fresno County, which encompasses the VCIP project boundaries. But with the approved guidelines in place, “we believe that we’ve knocked off two years in the planning process,” Gutierrez said, as opposed to “if a solar developer was to come in and do a one-off.”
Golden State Clean Energy has also laid out common financial terms and conditions for landowners and solar developers, Mealoy said. “If you’re farming near Kerman or if you’re farming near Huron, you have the exact same deal.”
The district hopes that all this planning ahead will help bring enough privately held land on board to roughly match the amount of district-owned land on the table, Gutierrez explained. That is vital to achieve the scale needed to enable the most unusual aspect of the plan, he said: building out the transmission.
“The district had enough land to make it interesting,” Gutierrez said. “But we knew we needed more land on the private side to justify the investments in infrastructure.”
To be reminded of how important new power lines and substations are to achieving the VCIP vision, Ross Franson need only look out his office window.
I met up with Franson at the white-painted, single-story field operations offices of Woolf Farming & Processing, which sits just east of Interstate 5, near Huron, the district’s sole incorporated city. To the south, past a field now under solar development, a spiderweb of power lines and transmission towers march southward. They converge just over the horizon, at PG&E’s Gates Substation — a critical juncture for solar power to interconnect to the larger state grid.
Of the 20,000 or so acres the company farms, roughly 1,200 have been built out in solar, Franson told me. Woolf plans to develop up to 3,000 acres in total. “We’re a little bit unique, in the sense that our farm is right next to the Gates Substation,” he said.
That’s not the case for much of the district’s acreage, he explained: “It’s far away from transmission lines and substations. And so the cost of doing that isn’t ideal.”
Enter Assembly Bill 2661, a state law passed in 2024. It allows Westlands to finance and build its own grid infrastructure. It also allows the district to use the clean energy it generates for its own purposes, and to sell the rest to utilities and other power buyers via the transmission system run by the California Independent System Operator.
In that sense, as Hughes said over lunch at Harris Ranch, VCIP is a “transmission play, not a solar play. The solar is doable because of the transmission.”
VCIP’s 500-kilovolt system will entail five new electrical substations and roughly 70 miles of high-voltage transmission connecting to the CAISO grid to the north, south, and west, Hughes said. In essence, it will provide an eastern parallel to the two 500-kilovolt transmission pathways already running along I-5 on the district’s western border.
Transmission is notoriously hard to build. But Westlands hopes that its master plan can forestall landowner and environmental opposition that has stymied many other projects. Much of the 70-mile line has been sited to cross district-owned lands. Where transmission will be situated on privately owned land, Westlands has crafted standard easement agreements to give landowners confidence they’re getting the same deals as their neighbors, Gutierrez said.
Westlands is taking on a significant financial commitment to unblock the grid bottleneck. Gutierrez estimated the price tag of building the project’s grid infrastructure is more than $1 billion.
The district will need to negotiate agreements with CAISO to earn back that money through transmission access charges. That’s the same way the state’s major new grid expansions are repaid over time via increases to utility customers’ bills.
But Mealoy believes those costs will be more than counterbalanced by benefits to the state at large. A study commissioned by Golden State Clean Energy found that VCIP could yield more than $9 billion in net energy cost savings over the next 25 years, both by adding more clean power and by reducing grid congestion that drives up rates and reliance on fossil gas–fired power plants in Northern California.
State agencies are loath to approve massive transmission investments to accommodate future clean energy projects. But as that buildout lags, CAISO’s grid remains congested — and clean energy developers face potentially project-killing costs for upgrades to connect to it.
That’s why VCIP relies on doing solar, batteries, and transmission together, Mealoy said. “To get transmission built, you needed size and scale,” he said.
Owning the power lines also gives Westlands control over some of its energy-related expenses. Several California irrigation districts operate their own utility services, including Turlock Irrigation District and Modesto Irrigation District in the Central Valley and Imperial Irrigation District in the southeast corner of the state.
Westlands, which is served by PG&E, isn’t becoming its own utility, Fortune stressed during lunch at Harris Ranch. “PG&E is not fighting us, and we’re not fighting PG&E.”
But running the district’s massive pumping stations requires a lot of power, as does operating well pumps and drip irrigation motors, he said. “The district is going to get lower power costs to supply the water, and [growers] are going to get the option of lower-cost power on their end — so the water cost is going to come down.”
The central role of water in Westlands is evident to anyone driving along I-5. Scattered among the fields and orchards are signs — posted on fences and on wheeled trailers once used to haul cotton — broadcasting slogans like “No Water = Lost Jobs,” “Stop the Politicians Created Water Crisis,” and “Congress-Created Dust Bowl.”
The angry sentiments stem from the decades-long conflict over California’s massive state and federally managed water distribution. Westlands secured its water allotments from the Central Valley Project in the 1960s. But since the 1990s, joint federal and state efforts to restore endangered fish species and protect the delta’s environment have increasingly restricted flows from the massive pumping stations that move water southward. And as the most recent water district to be created and served by the federal water system, Westlands is a junior holder of water rights, which makes it first in line for cuts.
Historically, San Joaquin Valley farmers and politicians have held a hard line on keeping the water flowing, with Westlands-bankrolled lobbyists often taking the lead. But as those political efforts faltered and drew public pushback during the state’s historic drought of 2011 to 2017, Westlands growers shifted their stance.
In 2022, Franson, Hughes, and two other growers won seats on the district’s board on a “change coalition” platform, aimed at putting an end to the adversarial water policies of Tom Birmingham. The district’s general manager for more than 20 years, Birmingham announced his retirement after the election.
To be clear, Westlands hasn’t surrendered the fight for water, said Febbo, who replaced Birmingham in 2023. “Our growers have shifted, from saying we don’t want to repurpose any of our agricultural lands, to a position where we have to fallow a significant portion of our area,” she said, “and that we should do that in a planned and thoughtful way until we determine a way to restore our water supply.”
If decades of on-again, off-again surface water allocations were the instigating incident, the Sustainable Groundwater Management Act was the hard closer. Passed in 2014, SGMA created the first statewide regulations to manage groundwater resources that provide roughly 40% of California’s water and that have sustained San Joaquin Valley agriculture for more than a century.
But overpumping has reached a crisis point in the San Joaquin Valley. Thousands of public and private wells have run dry. The land itself is sinking, as water from underground aquifers gets depleted by as much as 2 feet per year in some parts of the valley. That subsidence is threatening to undermine critical infrastructure, including the San Luis Canal, the section of the California Aqueduct serving Westlands Water District.
SGMA requires overdrafted water basins to achieve sustainability by the early 2040s, which will entail both significant cutbacks on pumping and replenishing depleted aquifers. Complying with the law will likely necessitate fallowing about 500,000 acres across the San Joaquin Valley, according to the nonprofit Public Policy Institute of California.
Under the Westlands groundwater management plan approved by the state in 2022, the district must roughly halve the amount of water it normally pulls from the ground during dry years by 2030, Gutierrez said. That reduction, along with the uncertainty around future surface water deliveries from the Central Valley Project, forces growers to face the prospect of reducing by half the amount of land they’re able to irrigate every year.
This prospect has helped convince a critical mass of Westlands growers to support VCIP, Franson, Hughes, and Fortune said over lunch.
“I really do think SGMA forced the issue,” Franson said. “When push comes to shove, we needed to come up with an alternative plan.”
Allowing farmers to put land into solar without losing its water allocations is essential to making that plan work, Fortune said. Typically, allocations for land repurposed or sold for nonagricultural uses revert to the district, he explained. But under VCIP, landowners with long-term leases or cash-up-front easement deals with solar developers keep both surface water and groundwater allocations, which they can apply to remaining farmland.
That’s important for Westlands growers like Rebecca Kaser, owner of Avellar-Moore Farms. Her family has been farming in Westlands for four generations. She hasn’t put land into VCIP yet, but her father has.
“We have fallowed over half our acreage,” she said. “We still have property taxes, we still have horticultural expenses … and they don’t return any income. And we do this just for the water allocation, so we can continue to grow, to help out our neighboring communities providing jobs and paying property taxes.”
VCIP offers “financial relief from the incurred expenses year over year on this fallowed acreage — and the way it was designed, we could still keep our water,” she said. “What I really want to emphasize is that if we can keep on farming all of it, we would. The VCIP is a tool in the tool box to at least stay farming with the little that we can.”
If VCIP develops as intended, it’s not just the growers who will benefit but all residents in Westlands Water District.
Danny Garcia, 41, has lived his entire life in Three Rocks, an unincorporated community in the middle of the district. He hopes that building the world’s biggest solar and battery project will bring prosperity to Three Rocks, which is also known as El Porvenir, which means “the future.” But he and his family have their doubts.
“People are struggling right now,” he told me when I stopped by his home. “There’s many ways that people could work on solar.” Garcia makes a living as a trucker, hauling produce and delivering fruit and nut tree seedlings from nurseries for planting in the fields. He can envision participating in the construction boom when VCIP gets underway.
Almost everyone who lives in Three Rocks is employed in agriculture in one way or another, he said — including longtime farmworkers like his mother, Rosa Ramirez. She’s worked in the fields since she moved here from Mexico about 50 years ago, she told me in Spanish as Garcia translated. She can earn up to $600 per week when jobs are steady, but less than $200 a week when it’s slow.
And work has been slower and slower, Ramirez said, sitting at her son’s dining room table. “Back in the ’90s, they used to have tomato fields, lettuce, onions.” But as water has become scarcer, “a lot of almond trees are knocked out because of water — less and less.”
With solar panels eating up more and more farmland, “how is she going to pay her bills?” Garcia asked. “Is she going to work there with the solar system? She has no experience.”
The San Joaquin Valley includes some of the poorest counties in the state. The confluence of water stresses, environmental degradation, and rising heat and weather disruptions from climate change are only set to intensify the area’s challenges, according to a report issued as part of California’s 2021 climate change assessment.
Agriculture provides 17 percent of the San Joaquin Valley’s employment and 19 percent of its revenues. Those economic ties are even tighter in the sparsely populated Westlands, where agriculture generated $3.6 billion in economic activity and more than 27,500 jobs as of 2022, according to a 2025 study commissioned by the district.
But those figures were down from an estimated $4.7 billion in economic activity and about 35,000 jobs in 2019, driven largely by increases in fallowed land due to water restrictions. Those declines led to roughly 30% less in public tax revenues for counties, cities, and special districts, meaning millions of dollars no longer available for roads, water systems, schools, and other public services.
VCIP could help buck those trends, Mealoy of Golden State Clean Energy said. Building the solar and battery farms and grid infrastructure will require employing about 6,000 people for at least 10 years — in what he described as “good-paying, labor union jobs” — as well as about 1,000 full-time operations jobs once the project is complete. Some of those positions could be filled locally through apprenticeship and training programs with community colleges and workforce development agencies.
Businesses in the region could provide equipment and services to developers, and secondary spending will boost local economies, he added. The cost of building solar and battery projects ranges from $1 million to $1.5 million per megawatt, he noted.
And the towns, school districts, and county services will benefit from “billions of dollars that could be injected” into the tax base, once the state’s current property tax exemption for solar projects expires at the end of 2026, he said. It’s hard to predict future property tax revenues for Fresno County, but they’re certain to be significantly higher than those collected on fallowed fields, he said.
How those economic benefits will flow to communities suffering from generations of underinvestment and facing the loss of agricultural jobs has yet to be defined, however. In January, Westlands’ board voted in favor of a draft approach to meet the requirements in AB 2661, the law making VCIP possible, to “ensure that local communities have meaningful opportunities to participate and access benefits” from its clean energy transformation.
That plan for the community benefits agreement commits the district to work with Fresno County and seven incorporated cities to “commit a portion of project revenues” to workforce, energy-affordability, environmental, and quality-of-life benefits.
But Westlands doesn’t plan to start making that money available for “at least 60 months out, coinciding with the commercial operation of the facilities,” Russ Freeman, the district’s deputy general counsel, said at the January meeting before the vote took place.
That’s worrisome to community groups that feel they’ve been neglected by Westlands’ power players and the region’s political leaders. Rural Communities Rising, representing 36 communities across western Fresno County, was formed last year so that residents “are heard, respected, and prioritized,” as the clean-energy developments envisioned by VCIP move ahead.
“We believe in a big-tent concept. Everybody should participate,” Espi Sandoval, a Rural Communities Rising board member and educator, said at that January meeting. His group is advocating for a formal organization, including local governments, school and water districts, labor associations, workforce agencies, nonprofits, and local representatives, to “work collectively with developers to address … priorities.”
Community groups are focused first on mitigating impacts from construction, like limiting vehicle traffic that can clog narrow roads, worsen already poor air quality, and kick up dust carrying fungi that cause a pulmonary ailment known as valley fever. They’re also demanding more emergency services, including fire stations located closer to solar and battery sites that could pose fire risks.
And they’re asking for remediation of longtime problems like high energy costs and polluted water supplies. Ramirez’s electric bill from PG&E was $331.74 for the month of November — far more than she thinks she ought to be paying for a small single-story home. California has the highest electric bills in the mainland U.S. That’s a particular burden for low-income San Joaquin Valley residents during days or weeks of triple-digit summer temperatures.
Ramirez’s water bills have also risen, even as the water remains undrinkable, she said — a problem plaguing hundreds of thousands of California residents, many of them in the San Joaquin Valley. In Three Rocks and nearby Cantua Creek, the cause is disinfectant by-products from chemicals, such as chlorine, used to treat surface water delivered from Westlands to a Fresno County–managed treatment facility.
“That’s why we have the water jugs,” Garcia said, pointing to the five-gallon containers arrayed under the trampoline in his front yard. “Every two weeks, the water man comes in and leaves them.”
Clean energy could provide an economic lifeline for the region — but that’s not guaranteed. A 2024 report from the Sierra San Joaquin Jobs Initiative, a joint project of the Fresno-based Central Valley Community Foundation and the state-funded California Jobs First Council, found that the four counties of Fresno, Kings, Madera, and San Joaquin could host 29 gigawatts of solar and energy storage through 2045, adding up to about $10 billion in investment and an estimated 73,000 new jobs paying an average of $32 per hour.
But it also found that workers “feel inadequately prepared for this transition” in terms of education, training, and opportunity to break into the industries involved.
Elizabeth Cabrera, city manager of San Joaquin, a town of about 3,700 people in western Fresno County, has attended meetings held by nonprofit groups working with solar developers to offer jobs and training to locals. But less than a third of San Joaquin residents have a high school degree or equivalent, she said. Many speak only Spanish, and “a high percentage are undocumented. That’s already three major barriers to entry.”
Leticia Fernández, the 63-year-old owner of the Half-Way Store in Cantua Creek, is also doubtful that solar development can make up for the loss of agriculture in the area. She started working at the store when she was 16, and bought it from the previous owner in 1997. But business has declined as more land has been fallowed, and the solar projects being built haven’t reversed that, she said. “They’re not spending the money like they tell us at the meetings.”
That’s not to say that solar projects aren’t doing some good, Fernández said. She pointed to the new fire station being built in Cantua Creek, financed in part through a $15 million commitment from Intersect Power, the initial developer of the Darden Clean Energy Project (the project is now owned by IPX Power).
Intersect also committed to community benefits plans that will make $2 million in direct investments in the next 10 years and $5 million over the project’s lifetime. The initial $2 million has gone to support affordable housing, provide grants to small businesses, bolster school programs, plant trees, and give away about 250 window air-conditioning units, among other benefits.
“We want to build strong partnerships, and we want to bring the community into the project, whether that’s supplying concrete or getting a union job and working on-site,” said Elizabeth Knowles, head of community engagement at Intersect Power. The Darden project is expected to create more than 1,600 all-union construction jobs, generate more than $70 million in state and local sales tax revenues during its construction, and provide more than $200 million in property taxes in the first 10 years, she said.
Still, some people say the Darden project’s original community benefits agreement didn’t direct money to the most pressing needs. They want to make sure the process for VCIP, which will be more than 15 times larger than Darden, doesn’t leave them out of the loop.
“We understand the project will take at least 10 years to build out. But we want residents to be part of conversations before decisions are made,” said Mariana Alvarenga, a senior policy advocate with the nonprofit Leadership Council for Justice and Accountability.
The challenge is that most of the economic impacts of clean energy projects are tied to “jobs and spillover work for local businesses” during construction, said David Adelman, a professor at the University of Texas at Austin School of Law who studies local opposition to clean energy developments. Beyond that, “virtually all of the benefit is in increased local property taxes,” he said. “Most of that impact gets buried in county and school district budgets” that are “not very visible to the local community.”
These facts could bolster arguments for larger up-front community benefits payments, he said. But that might be hard for clean energy developers already struggling with the looming loss of federal tax credits, rising equipment and labor costs, and other economic headwinds. Nor do solar project developers want to be held responsible for repairing past harms to communities and to the environment that were caused by others.
County tax revenues from clean energy projects could be directed to helping the communities near those projects. But that requires commitments from county politicians and administrators to ensure those revenues aren’t redirected elsewhere — and like many other rural counties, Fresno County is facing major budget pressures.
Justin Diener, controller of Red Rock Ranch, understands these concerns. He grew up on his family farm in Five Points, which has won recognition for its sustainable water and soil management. After graduating from Stanford University, he was employed in agriculture finance for 12 years, then returned to work with his father in 2016. He won his seat on the Westlands board of directors in 2022 as part of the change coalition — and unlike most Westlands farmers, he lives on the land that his family farms.
“I love to be out here,” Diener said on a stroll outside the modest one-story building that houses his family’s farm operations. “I grew up out here, across the street. But you know, it’s not a walk in the park, either.” It’s a half-hour drive for him or his wife to take their daughter to and from school. Last fall, crops left rotting in nearby fields because they were unsuitable for market caused a fly infestation that plagued the area for months.
Diener has also seen the decline in Fresno County services over the decades. “When I was younger, the roads got paved more frequently,” he said. “The potholes were taken care of.” He’d like to see VCIP money coming into the district prioritized for critical needs. “Do you have shelter? Do you have food? Do you have water? Is where you live safe?”
He thinks that long-term funding from Fresno County and municipal governments, rather than one-time community-benefits dollars, is the logical source for supporting those kinds of fundamental services. “I’d look to ongoing community benefits dollars to be an enhancement to government dollars, rather than a replacement,” he said. It’s also important that community benefits be ongoing, rather than one-off donations.
Still, Diener says VCIP could be “transformational” for Westlands. “The district’s not going to see the benefits today or tomorrow,” he said. “But five to 10 years down the road, I think things are going to be very different.”
A correction was made on March 25, 2026: This story originally misstated the expiration date of California’s property tax exemption for solar projects. It expires at the end of 2026, not the end of 2027.
Geothermal energy is rapidly advancing in the U.S. and globally, thanks to the arrival of next-generation technologies and skyrocketing power demand from data centers. Yet as more companies drill down deep to harness Earth’s heat, the industry is poised to hit a major snag on the surface.
Geothermal power plants rely on “turbomachinery” — turbines, heat exchangers, and other components — to generate and deliver electricity. But the limited supply chain and high cost of that equipment threaten to delay the industry’s efforts to supply huge amounts of clean electricity around the clock, according to Project InnerSpace, a geothermal research and advocacy organization.
On Tuesday, the group announced a new initiative with the nonprofit foundation XPrize to tackle that above-the-crust challenge.
XPrize will run a global competition to incentivize researchers and companies to design power-plant systems that not only require less time and money to produce than today’s, but that also can be more readily installed across a wider range of geothermal projects.
Project InnerSpace will fund initial efforts to design the competition, though the full prize amount won’t be announced until it officially launches this summer. The partners said they’re talking with industry players at the ongoing CERAWeek energy conference in Houston to develop key criteria for the contest.
The idea is to “unlock innovation that markets alone are too slow or too constrained to deliver,” David Babson, XPrize’s executive vice president of energy, climate, and nature, said in a news release. XPrize has spearheaded nine climate-related competitions to date, including a $100 million challenge for carbon-removal technologies that was funded by Elon Musk’s charitable foundation.
In the U.S., geothermal energy produces just 0.4% of total utility-scale electricity generation. Conventional geothermal technologies rely on naturally occurring reservoirs of hot water and steam that are found in only a handful of places, like California’s Geysers area and Nevada’s Great Basin.
However, recent innovations are breathing new life into the industry after decades of slow growth. Enhanced drilling techniques honed from oil and gas development, novel closed-loop systems, and more sophisticated mapping tools are making it possible to access heat in deeper, hotter, and drier locations than traditional systems can go.
“The subsurface solutions that will drive scaled development of next-generation geothermal energy are well on their way,” said Jamie Beard, executive director of Project InnerSpace. “We now need to match that momentum aboveground.”
That includes developing more “modular, integrated, and high-performance” geothermal surface plants than currently exist, according to the prize announcement.
Today, the global market for organic Rankine cycle technology and other equipment that geothermal plants use is concentrated among a small set of manufacturers based in Israel, Turkey, and parts of Europe. Until very recently, those companies had little reason to scale production or revamp designs, owing to the sector’s limited growth. Most geothermal equipment is highly customized, and in the U.S., it can take over 18 months to bring it stateside.
As the cost of drilling geothermal wells declines significantly, topside systems are expected to account for up to 50% of total project expenses and much of the risk of delays, Project InnerSpace wrote in a March report.
The turbomachinery supply chain will soon “be the bottleneck standing between next-generation geothermal and the gigawatt-scale deployment the world needs,” Beard said.
Supply chain constraints are hardly unique to geothermal. For fossil-gas power plants, the waitlist for new combustion turbines can stretch three to five years — and that was before the war now raging in the Middle East began disrupting global flows of critical materials.
Geothermal suppliers, for their part, aren’t sitting on their hands. Turboden, an Italian turbine-maker owned by Mitsubishi Heavy Industries, said it is preparing to boost production capacity in Italy and make more parts through its U.S.-based subsidiary to meet demand from next-generation geothermal and other sectors, including waste-heat recovery. Last fall, Turboden America was picked to supply equipment for three organic Rankine cycle units at Fervo Energy’s flagship Cape Station project in Beaver County, Utah.
“The volume of this business is growing significantly,” Paolo Bertuzzi, CEO of Turboden, said of geothermal.
The U.S. pipeline of pilot-scale and commercial projects is expanding in Western states like Colorado, Nevada, Utah, and Oregon. The sector is seeing a surge of support from private investors and government agencies that view geothermal as a timely and carbon-free way of meeting the nation’s soaring electricity demand.
Most recently, Fervo said it closed $421 million in new debt financing last week for the first phase of its 500-megawatt Utah project. The startup’s enhanced geothermal system uses fracking and horizontal drilling to create artificial reservoirs that circulate water and generate steam. Experts said the deal, led by major global banks, is a vote of confidence in the potential for enhanced systems to generate utility-scale returns.
As funders pile on, the Trump administration has protected key tax credits and accelerated permitting timelines for geothermal testing and exploration activities — in stark contrast to its efforts to block new wind and solar projects. In Congress, a bipartisan bill introduced last week would allow the Department of Energy to offer “innovative financing approaches” to advance next-generation geothermal in new states and regions.
Given the favorable conditions, an enhanced geothermal system of up to 500 megawatts in the western U.S. could enter into commercial production within roughly three to four years of active development, down from the timeline of seven to 10 years that’s frequently mentioned for conventional geothermal projects on federal land, according to recent research by the Center for Public Enterprise, a nonprofit think tank.
“That’s an incredible reduction,” said Mitchell Smith, a senior associate at the center, particularly for utilities looking to quickly bring clean power on the grid.
Still, the center’s report assumes that geothermal developers don’t encounter any “serious failure modes” when building their power projects. That can include lengthy interconnection queues as well as big delays in securing power-plant turbines — the very problem the XPrize competition aims to solve.
Ohio regulators have blocked yet another major solar project because of local pushback, even though a significant number of public comments opposing the array appear to be fabricated. It’s the latest blow to solar in a state that defers to local governments on renewable energy, but not on fossil fuels.
The Ohio Power Siting Board decided last Thursday to deny a permit for the 94-megawatt Crossroads Solar Grazing Center, which would combine solar panels with sheep grazing in central Ohio. Although the project otherwise met all legal requirements, the board concluded that it “fails to serve the public interest.”
Regulators acknowledged that Crossroads Solar would have statewide benefits, create jobs, and increase local tax revenue. But they said the project’s merits are outweighed by the existence of “consistent and substantial opposition” from local governments and nearby residents.
Critics of the decision are troubled that the regulators basically shrugged off the fact that a substantial number of public comments filed in opposition to Crossroads Solar were duplicative, anonymous, or seemingly faked. A recent Canary Media review found that dozens of comments contained apparent lies about people’s names or residence in Morrow County, where the project site is located. The board acknowledged those concerns in its ruling but asserted that substantial public opposition existed regardless of the potentially fabricated comments.
The controversy about those false comments, along with anonymous or multiple submissions, feeds into broader criticism that the board has reduced renewable energy siting to a local popularity contest.
“When the volume of public input is prioritized over its substance, it weakens trust in the process and makes it harder to build the energy system Ohio needs,” said Nathan Rutschilling, managing director of energy policy for the Ohio Environmental Council.
Like many states, Ohio faces soaring electricity demand and rising power bills. Clean energy could help address those challenges — provided it can get built.
“If we’re going to deny solar the ability to compete in Ohio’s marketplace, I think that’s going to result in an artificially high price for Ohio consumers,” said Democratic state Sen. Kent Smith, who is a nonvoting member of the siting board. He described the board’s Crossroads Solar denial as “a dangerous thing for the state in terms of both affordability and reliability.”
State and local restrictions on renewable energy have proliferated across the country in recent years, and Ohio is no exception. The state’s wind and solar developers face hurdles that fossil fuel companies do not, thanks to a 2021 law that lets counties ban renewable energy developments — an authority they do not have over oil, gas, and coal projects.
Morrow County instituted such a ban across half its townships last year. But because Crossroads Solar was in the regional grid operator’s queue before the 2021 state law took effect, it is exempt from the blanket prohibition.
However, for the past few years, the Ohio Power Siting Board and its staff have denied or recommended against permits for solar farms when all nearby local governments have been against a project. The Ohio Supreme Court has not yet ruled on a legal challenge to that practice, even though oral argument was held more than a year ago.
Initially, it seemed as if Crossroads Solar might escape this fate. Although Morrow County commissioners and the boards of trustees in two townships where parts of the project would be built were against it, the board in a third township — Cardington — remained neutral. Since opposition wasn’t unanimous, the siting board’s staff recommended in early December that regulators deem the project in the public interest.
But shortly after that recommendation, meeting minutes show that one Cardington township trustee changed his position because the staff report “did not set well with him.” That led the Cardington trustees to pass a 2–1 resolution opposing Crossroads Solar. The switch-up ultimately resulted in the siting board staff reversing its stance, filing testimony in January that encouraged regulators to rule against the project.
The Power Siting Board relied on that reversal to declare that Crossroads Solar was not in the public interest. It also asserted that there was “strong, united opposition to the project” by people in the area. It’s worth noting, however, that many locals supported Crossroads Solar. Its developer, Open Road Renewables, found that nearly half the public comments from people in nearby towns approved of the project, once the duplicate, anonymous, and unverifiable submissions were removed.
The Crossroads Solar case exposes deeper flaws in Ohio’s renewable energy siting process, some say.
It’s problematic that a single person’s vote on a town council “essentially derailed the whole project,” said Heidi Gorovitz Robertson, a professor at Cleveland State University’s College of Law. She argued that instead of reciting objections, regulators should evaluate whether those concerns have a factual basis and whether a developer’s plans already address them — and then decide whether any remaining issues actually justify denying a permit.
In the case of Crossroads Solar, Open Road Renewables agreed to address specific concerns about the project. In a late December settlement with the Ohio Environmental Council, the Ohio Chamber of Commerce, and various landowners, the company promised to follow best practices to keep roads clear and clean, use panels with an antireflective coating, minimize impacts to agriculture during construction, file a sheep-grazing plan to manage vegetation, work with a landscaping company to screen the panels from public view, and more.
But the Power Siting Board wasn’t swayed by the compromise, noting that the local governments and individual opponents who intervened in the case didn’t take part in the settlement negotiations, despite being invited to do so.
The board also appeared to buy into several obviously unfounded objections to Crossroads Solar, said Craig Adair, vice president of development at Open Road Renewables. For example, its ruling cited community skepticism about the company’s intention to graze sheep around the panels, since no contracts for such an arrangement had yet been signed. The board also noted opponents’ fears that the permit would later be transferred to another firm that wouldn’t make good on Open Road Renewables’ promises.
But the application’s commitment to use sheep would become part of the permit conditions, Adair noted. And, as a matter of basic contract law, any company that acquired the project would be subject to the same conditions as Open Road Renewables regarding permits, leases, easements, and other agreements.
The board also didn’t examine whether local governments’ objections to Crossroads Solar were based on misinformation, such as a laundry list of concerns about fires, contaminated drinking water, heat islands, and stray voltage.
“It’s taking fact and truth out of the equation, and it’s truly about concerns and politics,” said Doug Herling, a vice president at Open Road Renewables.
Instead, the board “denied a project that has no fuel requirements while we’re in the middle of an oil and gas crisis,” Herling continued, referencing the current supply disruptions caused by war in the Middle East. He also pointed out that solar can be built faster than gas plants, which face yearslong supply chain backlogs, and it doesn’t emit planet-warming and health-harming pollution.
Herling and Adair said the company plans to ask the board to reconsider its ruling.
Meanwhile, the permit denial “sends a dangerous signal to investors,” Adair said.
“I wish the state of Ohio luck in meeting its power needs and keeping power prices from going through the roof,” he said. For renewable energy developers, “it’s now a game of Russian roulette as to whether you would get a permit and what those criteria are.”
Big batteries have begun reshaping the U.S. grid. Now, the country has made surprising strides in making those energy storage systems itself, rather than depending on imports from China.
Batteries were always crucial for the effort to scale up renewable energy production, but they have taken on even more significance as AI leaders look for quick-to-build power sources to supply their headlong data center expansion.
That’s why batteries will account for some 28% of new U.S. power plant capacity built this year. For the first time, the country will be able to produce enough grid batteries to meet that surging demand on its own, according to new data from the U.S. Energy Storage Coalition, an industry group.
The onshoring began in earnest when President Joe Biden signed the Inflation Reduction Act in 2022, creating incentives both for domestic battery producers and for storage developers who use Made-in-America products.
Already, the U.S. has enough capacity to meet demand for finished grid battery enclosures. That involves connecting battery cells to power electronics, controls, and safety equipment in weatherproof steel containers that are ready to install. By the end of this year, the U.S. will also achieve self-sufficiency in a higher-value part of the supply chain: the battery cells themselves. It’s a major industrial coup that is bringing thousands of high-tech manufacturing jobs to communities across the country.
“For the first time, the United States now has the capacity to supply 100% of domestic energy storage project demand with American-built systems,” said Noah Roberts, executive director of the U.S. Energy Storage Coalition, on a Wednesday press call. “That is a fundamental shift from where we were just a year and a half ago, when the majority of battery storage systems were imported.”
This success outstrips the country’s considerable progress in solar panel manufacturing, too. The U.S. is self-sufficient in assembling solar modules, but that finished product still often depends on high-value components imported from far away — namely, solar cells. U.S. solar cell production remains a tiny fraction of its solar panel capacity.
By the end of 2025, U.S. factories had mustered the capacity to produce about 70 gigawatt-hours of finished grid storage systems each year, according to the coalition’s survey. Roberts expects that number to rise to 145 gigawatt-hours by year’s end. U.S. storage developers are likely to install about 60 gigawatt-hours annually this year and next, he noted, so the country will actually have a sizable surplus in manufacturing capacity.
As for the underlying cells, it’s a similar story with a slight delay. By the end of 2025, 20 gigawatt-hours of dedicated storage cell lines had opened, and the industry is on pace to hit 96 gigawatt-hours by the end of this year.
Now, the question the industry faces is not whether it can keep up with domestic demand — but whether it can export enough batteries to maintain that mismatch between manufacturing potential and domestic installations.
The development of U.S. grid-battery manufacturing has happened at a dizzying pace. Roberts called it “one of the fastest industrial scale-ups in recent American history.”
At the close of 2024, the U.S. had “effectively zero” factory capacity for battery cells designed for grid usage, which have different specifications than those in electric vehicles and which typically use the lithium iron phosphate chemistry.
LG Energy Solution Vertech, the grid-storage subsidiary of the Korean industrial giant, started turning things around last summer when it completed a dedicated cell production line for grid storage in Holland, Michigan. The company originally envisioned 4 gigawatt-hours of production, but quickly expanded that to 16.5 gigawatt-hours, said Chief Product Officer Tristan Doherty. Now LG plans to hit 50 gigawatt-hours of cell production capacity across North America this year.
“If you had told me that 10 years ago, that this is where we would be, I never would have believed it,” Doherty said.
The upstream supply chain, it must be said, still needs work. U.S. factories can only build the lithium-ion battery cells by importing the high-value battery materials, and China runs the show in that arena.
It’s also worth noting that this scale-up was accelerated by an unintentional nudge from the Trump administration, a sort of collateral benefit.
When the Trump administration passed its budget legislation last summer, it maintained Biden-era incentives for domestic energy manufacturing and grid battery projects even as it removed them for electric vehicle purchases.
The outlook for EV sales in America suffered as a result, and that prompted some manufacturers to repurpose their EV-battery facilities for the red-hot grid storage market. In just the last year, car companies like Ford and General Motors have retreated from their earlier EV ambitions and pivoted their battery lines to storage.
Just last week, LG said it and partner GM would retool an EV battery plant in Spring Hill, Tennessee, to make grid batteries instead; this will bring 700 people back to work after earlier layoffs. LG is also converting a plant in Lansing, Michigan, to make grid batteries instead of EV batteries, and will sell them to Tesla as part of a $4.3 billion supply deal.
It’s a stark reversal. In earlier years, grid battery developers had accepted surplus EV batteries as a sort of hand-me-down from the more mature supply chain; now, struggling EV battery producers are turning to grid storage in their moment of need.
Other companies have made their own direct investments in grid storage in recent years, including Tesla, Samsung SDI, Fluence, and SK On.
Even as the White House fights clean energy broadly, it’s showing interest in strengthening battery supply chains to reduce the upstream dependence on China. Just this month, the Department of Energy rolled out $500 million in funding for processing or recycling battery materials domestically.
The localization of grid storage supplies does more than stroke the national ego. As data center customers ravenously seek immense power supply as quickly as possible, domestic supply chains shorten the time it takes to add storage to the grid, argued Pete Williams, chief supply chain and product officer for Fluence, a major grid storage vendor.
“To deliver this ‘speed to power’ you need a resilient and a responsive supply chain, and that’s been certainly a challenge in the international markets,” he said. “With U.S. manufacturing, we can improve delivery certainty. We can also shorten project timelines for our customers.”
In the past, analysts framed industrial reshoring as a way to protect against the vagaries of geopolitical adversaries. These days, with the White House itself regularly upending global trade through tariff declarations and military interventions in crucial waterways, a local supply chain protects against U.S.-led disruptions as well.
This story was originally published by Grist. Sign up for Grist’s weekly newsletter.
When Krystal Steward started knocking on her neighbors’ doors in Ann Arbor, Michigan, in 2021, to discuss energy efficiency and sustainability upgrades, she was met with a lot of blank stares.
She was new to the issues herself, she said. But the longtime social worker kept at her new job doing outreach for Community Action Network, a local nonprofit dedicated to serving under-resourced communities. She slowly started getting people in her neighborhood to take part first in home-energy assessments, then in a city program to swap out appliances, make structural fixes, and more.
“In the beginning, it was kind of hard — a lot of people were reluctant. If someone is knocking on your door and telling you they can fix up your home for free, most people don’t believe that,” Steward said. But, she added, “Once one person tried it out, they’d tell their neighbors, and others would jump on board.”
Now, the neighborhood, Bryant, is set to pilot a first-in-the-country program that officials hope will speed the city’s transition to renewables — and offer a new model for how local governments can control their energy future.
The idea is technical, but has sparked enthusiasm across Bryant and Ann Arbor: a new city-created Sustainable Energy Utility, known colloquially as the SEU. Rather than replacing the privately owned utility that serves Ann Arbor, the plan is for this city agency to run in tandem, offering a supplemental service that residents can opt into.
If they do, they’ll stay connected to the regular grid, but will be outfitted with solar panels, battery backup systems, or other infrastructure, drawing on that power for their home use and opening up the prospect of selling any excess. The city, meanwhile, would pay for the installation and maintenance of these systems, which Ann Arbor would continue to own — a vision of energy generation and storage distributed across the city.
The plan begins in the coming months in Bryant, a 1970s-era community with about 260 homes, many of which are officially considered “energy burdened.” A quarter of residents pay more than a third of their incomes on utilities, in a neighborhood that is one of Ann Arbor’s only areas of unsubsidized affordable housing, according to Derrick Miller, Community Action Network’s executive director.
The SEU is a major step in a yearslong process to address Bryant’s energy affordability and sustainability concerns — and then expand the approach across the city.
“When we started having a conversation about how to decarbonize the neighborhood about four years ago, it felt outlandish. Now, it doesn’t feel like anyone can stop us,” Miller said.
The appeal of the SEU became clear in November 2024, when a ballot measure on the proposal was approved by nearly 80 percent of Ann Arbor voters. A little over a year later, city officials are ready to implement the vision, said SEU Executive Director Shoshannah Lenski.
In late February, the city announced that it was accepting expressions of interest from residents and businesses to take part, accompanied by a flurry of community meetings, animated videos, and ads in local theater playbills.
Customers who opt in will get two utility bills — one for the power supplied by these new city-owned clean energy systems, and one for any power they’re still drawing from the regular grid — which Lenski and her colleagues say will add up to less than they currently pay.
“Just like customers don’t own a power plant, the city owns and finances the system upfront, and they pay for that electricity through a monthly bill,” Lenski said. She noted that the model could prove particularly helpful for renters, who often get left out of green energy incentives. Signing up large multifamily buildings will be important to quickly expand the SEU’s size, she said.
In addition to installing clean energy systems at participants’ homes, the SEU could build its own microgrids, something that would set it apart from other municipal clean energy programs. For instance, the agency could install solar panels on a school to supply power when students and teachers are in the building, and that power could go to other SEU customers when classes are out.
Backers say the strategy allows Ann Arbor to build out its green energy system with lower financial risk — and lower potential for political or industry pushback.
“When coupled with DTE’s planned investments in clean energy, these voluntary, fee-based programs help accelerate economy-wide decarbonization while maintaining reliability and affordability,” Ryan Lowry, a spokesperson for DTE Energy, which currently supplies energy to the city, said in an email.
It might seem surprising that DTE, Michigan’s largest electric utility, is supportive of the SEU. But industry experts noted that many investor-owned utilities are struggling under the unprecedented new demands for power. Having a local government try to help manage power needs could be seen as an asset, they suggested — though DTE will have no formal role in the SEU.
So far, more than 1,500 people across Ann Arbor have indicated that they want to sign up. The SEU plans to serve around 100 to 150 customers in Bryant this year, expand out to reach 1,000 next year, and then grow by several thousand annually after that.
The approach answers a question prompted when Ann Arbor adopted an ambitious climate plan in 2020.
That framework included an electrical grid powered completely by renewable energy within a decade, but a city analysis in 2023 warned it was likely to miss that goal by more than 40 percent. In order to reach it, the city would need to push DTE to accelerate its renewable energy buildout, or lean on state officials to do so — or detach from DTE entirely and create a separate city-owned utility, an idea that does have some support in Ann Arbor.
But from the city’s perspective, these options seemed too risky or uncertain, Lenski said — until officials realized that the Michigan Constitution allows municipalities to create and run their own utility, even if there’s another present.
“That’s where the idea of the SEU was born,” she said.
When University of Michigan researchers compared the four options, they found the SEU model had the greatest potential to lower energy prices and emissions, boost reliability, and help low-income communities.
“Overall, it came down to having some benefits of local control without some of the costs,” said Mike Shriberg, a professor who led the research, noting a similar model should be possible in every state.
Still, some worry the strategy does not go far enough. Advocates who want the city to break with DTE and replace its services with a utility fully owned by Ann Arbor are seeking a November ballot measure to set that process in motion. (Organizers are currently collecting signatures.)
Brian Geiringer, executive director of the advocacy group Ann Arbor for Public Power, said the SEU plan still leaves too much responsibility for the city’s energy transition with DTE.
But if voters do approve creating a fully public utility, he said, it would not mean an end to the SEU: The two approaches could work together, with the SEU focused on generation within Ann Arbor, and a publicly owned utility able to make its own decisions on purchasing power.
“If you draw a circle around Ann Arbor, the SEU is doing stuff inside the circle. And we’re interested in having the city control what comes in from outside of the circle,” Geiringer said.
Like Ann Arbor, hundreds of cities are working to implement climate goals — and running into similar gaps between ambition and practicality, especially when it comes to control over energy sources.
“Cities have set these goals, and the utilities aren’t obligated to follow those,” said Matthew Popkin, manager for U.S. cities and communities at RMI, an energy think tank.
“So Ann Arbor’s SEU is an example of cities taking more control of their future without dismantling or acquiring existing utility systems,” said Popkin. “That’s a really interesting model.”
Other models also exist. In Washington, D.C., for instance, a program called the D.C. Sustainable Energy Utility has been operating for 15 years, overseeing the city’s efforts to help residents use less energy.
The initiative is far narrower than the Ann Arbor vision, functioning not as a utility but rather as an organization contracted by the city to boost energy efficiency and increase access to clean energy through subsidies and rebates.
The program is a central part of the city’s goals to reduce its greenhouse gas emissions, said managing director Benjamin Burdick, and has helped cut some 10 million metric tons of emissions while saving residents more than $2 billion from reduced energy use.
Nationally, “the conversation that we’re hearing is around how do you continue to talk about climate with affordability,” he said. “Programs like the D.C. SEU are going to continue to be the way that we double down.”
The work in Ann Arbor is now receiving its own attention across the country.
“What caught my eye about Ann Arbor’s efforts were the references to citizen involvement and co-investment in their own grid,” said Jim Gilbert, a retired medical product designer in Boulder, Colorado, who is now helping that city assess the Ann Arbor model.
Boulder has dealt with recent power outages due to worsening climate impacts and aging infrastructure, and Gilbert said an SEU could offer a way forward.
Back in Ann Arbor, as the city prepares to launch the initial pilot of its SEU, the plan is to reach half of the Bryant neighborhood by the end of the year — and local residents are “all in,” said Krystal Steward.
Older members of the community are particularly excited, she said, noting that many are on fixed incomes and will particularly benefit from lower energy bills.
“It’s hard for me to keep up,” Steward said. “Now it’s not me reaching out to residents to sign up — they’re blowing up my phone.”
Illinois could soon follow in the footsteps of Utah and Virginia with a law allowing plug-in solar arrays, often called “balcony solar.”
A bill that would make it simpler to install plug-in solar passed out of the state legislature’s Senate Energy and Public Utilities Committee on March 12. It’s now scheduled for a hearing in the full Senate, and a House committee on utilities is also considering the bill. Advocates are hopeful that the measure will pass both Democratic-controlled chambers this legislative session, which runs through the end of May, and then be signed by the state’s Democratic governor, JB Pritzker.
People are already plugging in these kinds of off-the-shelf small solar arrays to help power their homes, experts say. But legislation would ensure that more people can access the cost-saving clean power. Illinois’ bill would mandate that utilities allow people to plug in solar systems of up to 1,200 watts, without interconnection agreements, fees, or other barriers. That’s about enough energy to run a refrigerator and a few other appliances.
In Illinois, such units could save households up to $400 a year, according to an analysis by the advocacy group Solar United Neighbors, which notes that plug-in solar currently costs about $3 per watt, or about $2,000 for a typical model. Advocates predict that the cost will come down quickly if more states pass plug-in solar laws and the market expands.
More than two dozen other states are considering such bills. The concept has enjoyed bipartisan support across the country, with Utah’s Republican-dominated legislature passing the first law in March 2025. The Virginia legislature passed its law by a unanimous vote on March 11. Illinois’ red-state neighbors — Indiana, Iowa, and Missouri — have also introduced bills.
The momentum comes as affordability concerns mount nationwide. Electricity prices have spiked in many parts of the country, driven by factors including extreme weather and wildfires, natural gas price fluctuations, and the cost of infrastructure to get power where it’s needed. In Illinois, customers are seeing their bills rise sharply because of increasing electricity demand that is driven in part by data centers.
Illinois’ plug-in solar measure would go a step further than most by stipulating that homeowners’ associations and landlords could not enact rules, fees, or insurance requirements around arrays of 391 watts or less, proponents say. This would ensure that renters and condominium owners could take advantage of the option.
Despite the fast-growing enthusiasm for plug-in solar, some bills, like one in Wyoming, have failed. Utilities have raised safety concerns, such as danger to lineworkers if the arrays don’t shut off during power outages and continue sending electricity onto the grid, or a home’s electric system becoming overloaded.
Plug-in solar proponents note that safety concerns can be managed, especially through legislation that requires specific certification, as the Illinois bill does.
“This is a disruptive technology to the American market, and all disruptive technologies are good for the consumer and bad for the power structures,” said Cora Stryker, who co-founded the nonprofit organization Bright Saver last year to sell affordable plug-in solar kits. “We believe these are strategic efforts to confuse legislators and the public, but the real motivation is the threat to the business models of very powerful entities.”
The Illinois bill would mandate that plug-in solar systems not send any electricity into the home when the larger grid has an outage. That means the panels wouldn’t help during a blackout unless paired with a battery, but they would avoid harming lineworkers. Arrays that are commercially available already typically include such safeguards as part of the built-in microinverter.
The Illinois bill would also require that plug-in units be certified by UL Solutions (formerly Underwriters Laboratories) or an equivalent entity.
Hannah Birnbaum, co-founder and chief of advocacy at the nonprofit Permit Power, which focuses on reducing the bureaucracy involved in getting rooftop solar, said that it’s crucial to pass laws that include these sorts of safety provisions. Otherwise, people will continue to install unregulated systems, she said.
In California, for example, customers are already “quietly” using portable solar panels — even though the state has yet to pass the plug-in solar bill it’s considering.
“The real risk is inaction,” Stryker said. “Now there’s so much enthusiasm for plug-in solar, people are buying whatever systems they can get. It’s a regulatory gray area.”
In Illinois, utilities have thus far not raised opposition. ComEd spokesperson David O’Dowd said the utility does not have a position on the bill. Ameren did not respond to a request for comment.
Should the bill pass in Illinois, it would add to the state’s already robust incentive program encouraging residents, businesses, churches, schools, and other nonprofits to get rooftop solar. Clean energy advocates say plug-in solar provides a more affordable and convenient option, and one that’s accessible to both renters and those whose homes aren’t conducive to rooftop solar.
“It’s an untapped resource” in meeting larger clean-energy goals, according to Nick Johnson, an associate professor of sustainability and economics at Principia College in southwestern Illinois. Johnson was among over 100 residents who filed witness slips with the legislature in support of the bill.
“It’s a drop in the bucket for what we need, but every little bit helps,” he added.
In Germany, more than a million households have plug-in solar — a fact often underscored by advocates trying to popularize the technology in the U.S., where it’s still in the early stages. Even in Utah, only a few thousand households have plugged in the devices since they became legal.
Advocates expect the systems will take off once more states make it simpler for people to adopt them.
For her part, Kavi Chintam, Illinois campaign manager for the advocacy group Vote Solar, said she plans to put a plug-in solar array in her yard after the law passes. Her mother wants a solar array on her balcony, to power her TV.
“At a time when electricity prices are rising and rising, it gives an option for people to shave off some of that cost,” Chintam said. “There is something really empowering about seeing a panel you installed on your home. As the market expands, there will be more opportunities for people just to see these things out and about.”
See more from Canary Media’s “Chart of the Week” column.
Clean energy is on a tear. In China and India, it’s growing so fast it’s starting to unseat king coal. In the European Union, solar and wind now produce more electricity than do all fossil fuels combined. Even in the U.S., amid the Trump administration’s attacks on clean energy, nearly all new power capacity comes from renewables and batteries.
But who, exactly, is making all of the solar panels, wind turbines, battery packs, and electric vehicles enabling this transition?
In a word: China. Let’s look at the latest numbers from the Clean Investment Monitor by Rhodium Group and the Massachusetts Institute of Technology. Right now, over 90% of the world’s solar manufacturing capacity is in China. So is 83% of the planet’s battery production capacity, and nearly three-quarters of wind technology manufacturing capacity. China’s grip on the EV sector almost looks measly in comparison, at just two-thirds.
China’s lead is explained by several factors. For one, the country itself uses way more clean energy tech than does any other, due not only to its massive population but also Beijing’s concerted effort to make the nation more self-sufficient on energy. Last year, more than half of the solar and wind installed worldwide plugged into China’s grid. The country dominates global EV adoption, too.
But China also exports enormous amounts of these technologies. The country’s expansion of manufacturing to meet its own domestic energy goals has allowed it to produce super-cheap solar panels, batteries, wind turbines, and EVs. That’s made clean energy more attractive to buyers in other countries.
But China’s investment in these factories is contracting, hard. Last year, it invested $60 billion in cleantech manufacturing overall — less than half of what it put in the year before. In 2023, it spent $50 billion on clean energy manufacturing in a single quarter. Investment in clean energy manufacturing has been sluggish in the U.S. and Europe, too, for what it’s worth, but it’s not crashing at anywhere near the same rate.
China is pulling back for a pretty intuitive reason. It’s already built more clean energy manufacturing capacity than the world wants to use at the moment. The Clean Investment Monitor team expects this mismatch to get even worse by 2030, so as it stands, it makes little sense for China to continue speeding ahead on new factory construction.
Overall, the clean-energy manufacturing picture could look a bit different by the end of this decade — but only by a little. Even with the U.S., Europe, India, and others expected to make some headway in the battery and EV markets, China’s lead ultimately isn’t expected to go anywhere.
Nuclear energy developers have historically operated by a simple principle: Go big.
Reactors cost a lot of money to build, so the logic has been that it’s easier to recoup that investment if the project produces more electricity. Of late, a new generation of companies has made waves by bucking that conventional wisdom and instead aiming to build smaller reactors that can be made cheaper through bulk orders and mass production.
But with few advanced reactors built to date, that argument remains theoretical — and a new report shared exclusively with Canary Media suggests the path to proving it out is harder than many in the industry acknowledge.
It’s a chicken-and-egg situation. Next-gen nuclear startups must establish supplies of rare and legally sensitive types of fuel while also competing for a small pool of skilled workers and a limited output of valves, pumps, heat exchangers, and other equipment. Manufacturers are hesitant to ramp up production without a clear signal that advanced reactors will pan out. Investors, in turn, are leery of reactors meant for mass production that rely on unprepared supply chains.
That’s the core takeaway from the new analysis by the Nuclear Scaling Initiative, a campaign by the nonprofits Clean Air Task Force, the EFI Foundation, and the Nuclear Threat Initiative. The Nuclear Scaling Initiative launched in 2024 and aims to promote fleet-scale construction of reactors in a bid to start bringing at least 50 gigawatts of atomic power capacity online worldwide every year at some point in the 2030s.
The study, conducted by the nuclear consultancy Solestiss, highlights two paths it says are promising for the industry: either sticking to proven designs or simplifying supply chains to tap into the traditional nuclear business’ existing materials and know-how.
It comes as the Trump administration pumps billions of dollars into advanced reactors while also courting developers of more conventional large-scale reactors — and amid a high-stakes debate over which approach is best.
Earlier this month, the Bill Gates-backed TerraPower won the Nuclear Regulatory Commission’s approval to begin construction on the country’s first commercial plant with sodium-cooled fast reactors in Wyoming. In December, the decommissioner-turned-developer Holtec International won a $400 million Department of Energy grant to build its first 300-megawatt small modular reactors in Michigan, using a pressurized-water-cooled design. The DOE awarded another $400 million grant to help American-Japanese joint venture GE Vernova Hitachi Nuclear Energy build its first 300-megawatt SMR in Tennessee, based on a traditional boiling water design.
The Trump administration, meanwhile, is trying to get developers to commit to building more AP1000s — the flagship large-scale reactor from Westinghouse Electric Co. The only two nuclear reactors designed and constructed in the U.S. this century used the Westinghouse design. (A third came online in 2016 but first started construction in 1973.)
The variety of designs racing to become the nation’s fourth new reactor in decades calls into question the feasibility of rapidly scaling up production of any one model.
“We can do any one of these first projects all at once. But can we sustain a build-out of TerraPower, GE, Westinghouse, and Holtec? All the ones that are just moving forward right now? The answer to that is not yet,” said Dillon Allen, president of the advisory services division at Solestiss, who started his career working on nuclear propulsion in the U.S. Navy before moving into the utility business. “Once you’re building four to eight AP1000s and a handful of SMRs of other sizes, you start to run into smaller component bottlenecks.”
Those bottlenecks would worsen if microreactor companies succeed in their objective of securing dozens and dozens of orders for their designs.
“While small reactors have been tried before, mass-manufactured small reactors have not,” Aalo Atomics CEO Matt Loszak, whose 10-megawatt reactors also use liquid sodium as a coolant, wrote in a post on X this week. “Small is more expensive than large, if you only make one reactor. But if you make 1000s per year, small could be cheaper than large. This is what Aalo is setting out to prove.”
One major obstacle to this plan is transportation. To build something and send it without prior testing is no problem, since a reactor that hasn’t been fired up and irradiated “is just a big hunk of metal,” Allen said. But once it’s irradiated, it’s subject to different considerations.
National laboratory researchers have started to discuss a framework for a U.S.-wide transportation network with established logistics and safety standards, the report notes, but no such rules have yet materialized.
The biggest barrier for next-gen nuclear, however, is likely to be the fuel supply. Some small reactor companies have been proactive here. Aalo, for example, has opted for the most commonly used reactor fuel on the planet, low-enriched uranium, so it can tap into the existing global supply chain.
But most advanced nuclear startups are banking on what’s known as fourth-generation reactors. These designs rely on coolants other than water and mostly aim to use one of two types of fuel: high-assay low-enriched uranium, commonly known as HALEU (pronounced HAY-loo), or tristructural isotropic fuel, for which HALEU is typically an input. Tristructural isotropic fuel is also known as TRISO.
HALEU, which firms like TerraPower and microreactor developer Oklo plan to use, is only really produced at a commercial scale by Russian and Chinese state-owned companies. Efforts to bring new centrifuges online in America are slow-going. Meanwhile, the TRISO fuel that startups such as Valar Atomics or Radiant need requires not only securing HALEU but also separating that enriched uranium into ceramic-coated pellets the size of poppy seeds. Manufacturers admit that TRISO may never cost less than low-enriched uranium.
The complications don’t stop there. Because HALEU is up to four times more enriched than traditional reactor fuel, it comes with stricter regulations. On the Nuclear Regulatory Commission’s security-clearance scale of category one, which allows for handling normal reactor fuel, to three, which includes military-grade enrichment levels, facilities with HALEU need to be rated at a category two. No such facilities exist in the U.S. today, though the commission just issued its debut permit for one last month.
As for traditional fuel, the existing supply of low-enriched uranium falls short of what would be required to meet the U.S. goal of quadrupling the nation’s nuclear capacity to 400 gigawatts by 2050.
“The supply chain is pretty well suited to support a fleet of 100 operating reactors,” Allen said, referring to the 94 commercial reactors in service in the U.S. “But then you can have 150, then 180, and pretty soon 200 after that. If you double that demand on the LEU supply, it’s not just the enrichment” that’s a limiting factor.
It’s also, he said, the production of raw uranium and the facilities to carry out conversion, where purified uranium ore is turned into a gas, and deconversion, where it’s solidified once again.
Expanding these upstream operations may be challenging, but it isn’t impossible. In fact, Allen said he came away from writing the report with the impression that supply chains are more capable of scaling up than he previously thought. But his team’s work demonstrates the steep obstacles faced by the entire industry — not only advanced reactor firms — as it attempts to bolt into action following decades of anemic construction in America.
The biggest impression the research left on Allen, he said, is that the AP1000 has a good shot at becoming the next reactor built in the U.S. Its costs are more predictable — and thus easier to finance — thanks to the lessons learned during construction of the two units that came online at Southern Co.’s Alvin W. Vogtle Electric Generating Plant in central Georgia in 2023 and 2024.
“I’m more bullish on the AP1000 than I was when I started this effort,” he said. “I’m broadly bullish on the supply chain.”
The DOE is considering alternatives to the AP1000 to satisfy President Donald Trump’s order to facilitate construction on at least 10 large-scale reactors by the end of the decade. In response to the news that the administration held talks with its rivals, Westinghouse said the AP1000 is“the only construction-ready, gigawatt-scale, advanced modular reactor that is fully licensed and operating in the U.S.”
The U.S. ultimately should focus on designs it can scale up rather than spreading its efforts in many different directions, said Stephen Comello, the executive director of the Nuclear Scaling Initiative. At that point, nuclear power will become cheap enough to be “boring.”
“Once you start accumulating that knowledge from repetition, nuclear construction becomes boring — just like natural gas combined-cycle plants, just like all other complex megaprojects and energy infrastructure that’s out there,” he said.
There’s little doubt that the AP1000 has a well-established supply chain and data showing it runs well, he said.
The question is, “Can you do it in a repeatable, cost-effective way? That’s where the risk lies with the AP1000,” Comello said. “It runs, the technology is great. But we have to prove to investors that we can overcome the execution risk. But here’s the thing: All reactors share execution risk to some extent. Others have a technology risk because they are still not proven at scale.”
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