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Industrial buildings could host gigawatts of shared solar to deliver low-cost power to underserved urban communities — if states and utilities allow it to scale up.
Natasha Keefer is not a fan of heights. But on June 5, Keefer, who heads the Energy Solutions team for the Americas for Prologis, one of the world’s largest logistics companies, braved the ladder up to the roof of a 147,500-square-foot warehouse in Oakland, California, to take a look at the latest solar project her team had built.
The 720-kilowatt array will generate far more power than the company’s warehouse can use. In fact, the building in East Oakland is vacant right now. But that’s OK, because as a community solar project, it’s feeding electricity directly into the grid, Keefer explained to a group of state and local officials who had gathered to “flip the switch” on the array.
Ava Community Energy, a public energy provider serving Oakland and other East Bay and Northern California communities, will buy that power and make it available to low-income households, with a guarantee for subscribers of at least 20% savings on monthly utility bills.
Half of U.S. states and Washington, D.C., have adopted policies enabling some kind of community solar program. Many such projects are built on open fields. But as one of the country’s largest owners of logistics real estate, Prologis is “looking to deploy solar on as many rooftops as we can,” Keefer said.
In a sense, warehouse rooftops are like open fields in dense urban landscapes, with acres of flat space available for solar panels.
Ava has awarded Prologis a contract to build nearly 7.3 megawatts of solar on sprawling roofs across five sites, enabling about 3,000 residents to see lower bills. Keefer previously worked for Clean Power Alliance, another California community energy provider, which is building 9 megawatts of warehouse-rooftop community solar with Prologis.
“California has a huge need for power. I’m not claiming distributed generation is the answer for all our needs,” she said. “But you need all the tools in your toolbox.”
Similar logic is driving U.S. states from the mid-Atlantic to the Midwest to expand opportunities for community solar on warehouses and other commercial and industrial buildings. There’s certainly a lot of roof space to go around, said Peter Light, CEO of Lumen Energy, which brokers deals between real estate owners and solar developers.
His company’s analysis of federal data indicates U.S. commercial, industrial, and institutional rooftops could host 581 gigawatts of solar, enough to provide the lower bounds of the country’s overall electricity demand. Similar data from a 2023 study by the Environment America Research and Policy Center found that warehouses across the U.S. have nearly 16.4 billion square feet of rooftop space, capable of hosting enough solar to power more than 19 million homes.
Of course, not all of that space can be used to generate solar power. But Light thinks that rooftops should be considered as valuable as open land for utilities and policymakers desperate to meet booming demand for electricity.
“With surging power prices from data centers and AI, and general electrification, utilities and states are asking, ‘Where can we get capacity now?’” he said. In many cases, rooftop solar systems can come online more quickly than utility-scale solar, which frequently faces yearslong interconnection studies and hefty grid upgrade costs, he said.
But only a fraction of available roof space is being used for solar today. Community solar can be a “revolutionary” tool to unlock that rooftop potential, Light said. “What community solar does is turn energy complexity into rental income — and new rental income is what real estate people understand,” he said.
Susan Uthayakumar, Prologis’ chief energy and sustainability officer, agrees that community solar is a valuable option for real estate owners.
Prologis has deployed more than a gigawatt of solar and batteries across its global real estate footprint, largely to pursue its sustainability goals, she said. That includes more than 300 megawatts of solar at its U.S. properties, more than any other U.S. real estate owner.
Some of that power is being used on-site, where the demand exists. But when it comes to warehouses, most have relatively low power needs. “We usually need only 30 to 40% of the roof space for on-building demand,” Uthayakumar said. “We like to contribute the rest of the space for community solar.”
Black Bear Energy, a subsidiary of real estate efficiency and sustainability contractor Legence, has more than a gigawatt of on-site solar projects in its development pipeline, with customers ranging from apartment buildings to office parks. But relatively few building owners have the capital and long-term ownership commitment to invest in and own solar projects, said Victoria Stulgis, Black Bear’s president.
What’s more, buildings that are rented or leased face the split-incentive problem: The owner is less likely to pay for the solar installation when tenants will be the ones reaping the benefits with lower electricity bills.
That’s why Black Bear Energy and customer LBA Logistics pursued tens of megawatts of community solar projects on warehouse rooftops in Maryland and in Illinois. “Community solar structures are much more attractive to us because we’re basically monetizing our rooftops,” said Michelle German, a vice president at LBA.
So what’s preventing more warehouse rooftops from being harnessed for community solar? First of all, it’s possible only in states with programs that allow shared solar.
Right now, that’s limited to Colorado, Illinois, Maryland, Massachusetts, New Jersey, New York, and a few other states, according to the Coalition for Community Solar Access, a trade group. Prologis is planning to build about 116 megawatts of rooftop solar in New Jersey with developer Solar Landscape, and another 82 megawatts across 45 rooftop projects in Illinois.
Second, states that do offer these programs restrict how much can be built, forcing developers and site hosts to scramble to design and bid projects into a limited pool of opportunities. But those pools are getting bigger. Earlier this year, New Jersey expanded its community solar program to 3 gigawatts, and Maryland is set to establish a 2-gigawatt target for distributed solar, including community solar, later this year.
But in California, community solar policy is moving in the opposite direction, its advocates say. State utility regulators have rebuffed a multiyear effort to expand community solar, leaving tight restrictions on how much can be built. Ava Community Energy’s 7.3-megawatt project portfolio with Prologis maxed out how much solar it could build under an existing program based on the number of customers it served in Alameda County — although its recent expansion into other parts of California have opened the opportunity to increase its portfolio by another 11 megawatts.
California regulators and utilities have argued that community solar projects are more expensive than utility-scale solar, making them a bad bet for keeping the state’s rising electricity costs in check. That’s because of both the economies of scale that giant solar farms offer and the extra costs of installing arrays on rooftops rather than on open land.
But that simple cost comparison doesn’t capture other benefits, Prologis’ Keefer said. “This is local to the community it serves,” she said. “It’s utilizing the existing built environment.” And because the power flows directly to existing urban power grids, “you don’t have to build a transmission line from the desert” to get the power where it’s needed.
In some states, community solar programs prioritize rooftops over empty fields. New Jersey limits projects almost exclusively to commercial and industrial rooftops, said Charlie Coggeshall, mid-Atlantic regional director for the Coalition for Community Solar Access. Similar requirements and incentives meant to prioritize solar development on buildings or “brownfield” sites like landfills exist in Illinois, Massachusetts, Maryland, New York, and other states, according to CCSA data.
Adding batteries to community solar systems could help them further reduce peak power demands in urban centers, according to research from consultancy Brattle Group commissioned by solar developer Solar Landscape. The analysis found that community solar-battery systems at commercial and industrial buildings in California could lower energy and grid costs more than “remote, ground-mounted projects,” mainly because they are situated in more densely populated areas.
Warehouses also tend to be located in communities that suffer from higher than levels of poverty and air pollution. A 2024 report led by researchers at Stanford University found that widespread deployment of commercial solar could provide disadvantaged communities significant relief from rising utility bills.
These are the kind of impacts that make urban community solar worth doing, said Rowena Brown, an Oakland City Council member and Ava board member. Residents of the East Oakland neighborhood that surrounds the Prologis warehouse “are unsure whether they can really benefit from lower energy costs — and they face real barriers to the clean energy transition,” she said. “I think of this project as a clear opportunity to show we care about the families here.”
Utility-scale solar outproduced gas plants on 82% of all days from January through May, with batteries helping to extend solar’s reach into the evening hours.
This year has been full of dramatic rivalries. World Cup matchups, Knicks versus Spurs, One Battle After Another versus Sinners at the Oscars, and now California solar power versus natural gas.
For years, natural gas has dominated electricity production in the climate-conscious Golden State, just as it has nationally. In both cases, this fossil fuel delivered about 40% of annual generation for much of the last decade. But that started to change in California as solar developers and rooftop installers added more and more capacity, and big batteries joined the party, too.
Last year, the competition turned into a Knicks-Spurs–style nail-biter: California generated nearly as much from large-scale solar power as from gas. This year, it’s turning into a Super Bowl LX–style rout, with solar surging ahead of gas generation for the first five months of 2026, per federal data.
In fact, solar outperformed gas on 82% of the days in that five-month stretch in the California Independent System Operator’s wholesale market. That’s all the more striking given that the state still has more installed gas capacity (29 gigawatts) than utility-scale solar capacity (25 gigawatts), and that this larger gas fleet can operate whenever, while solar is constrained to sunny times. Nonetheless, the solar fleet overcame those structural limitations to beat gas overall so far this year.
California’s gas fleet is in free fall: Generation dropped by 60% from the same time period in 2024. Solar generation increased by 21% in that interval.
Solar didn’t beat gas on its own, though. Battery developers have built 16 gigawatts of capacity in CAISO to charge up on solar power and then compete with gas after sundown. This buildup has rapidly altered grid dynamics in the evenings, when batteries regularly become the top source of power for multiple hours. Meanwhile, wind imports recently jumped as the gigantic SunZia project came online, and that takes the fight to gas in the middle of the night, further depressing its output.
There’s one big player missing from the government figures. The U.S. Energy Information Agency does not have a direct line on rooftop solar production, since those units don’t report data the way large power plants do; the EIA makes an estimate based on various data streams but doesn’t include those numbers in its solar-versus-gas comparison.
Empirically, we know that California’s rooftop solar capacity nearly matches its utility-scale capacity, so a complete accounting of solar production would presumably look like more of a blowout. Data firm Ember, for instance, tallied small- and large-scale solar production to show that all California solar nearly beat gas for the full year of 2024, but it hasn’t yet released results for the whole of 2025 on its U.S. Electricity Data Explorer.
What we can say for sure, based on just the EIA data, is that utility-scale solar alone is off to a roaring start. Gas may rally this summer, if heat waves push demand from air conditioners beyond what solar production can feasibly meet. But in recent months, the scoreboard hasn’t even been close, so this is solar’s game to win.
When that happens, it will mean that the world’s fourth-largest economy has swapped out its biggest fossil fuel for solar, making the grid both cleaner and more efficient.
Trump and GOP lawmakers revoked lucrative tax credits for rooftop solar. The results are predictable.
With solar panels getting cheaper each year and utility bills soaring, you might expect rooftop solar to be booming in the U.S. That’s not the case.
Instead, thanks in large part to the Trump administration’s revocation of federal tax incentives, residential rooftop solar installations in 2026 are expected to fall to their lowest level since 2020, per new BloombergNEF data.
Nearly one year ago, President Donald Trump signed the One Big Beautiful Bill Act into law and eliminated a 30% federal tax credit for rooftop solar systems. It was a major blow to an industry that was already struggling because of high interest rates, tariffs, and a seismic policy change in California, the state that has led the nation on rooftop solar adoption. The legislation also eliminated the 30% tax credit that applied to battery backup systems, which homeowners increasingly pair with photovoltaics.
Yanking away tax credits makes it costlier to install rooftop solar, so it’s no surprise the move dampened sales. People who buy rooftop solar systems are mainly looking for relief from high utility bills, and solar installations are already more expensive in the U.S. than in many other countries. Residential solar costs $2.58 per watt, on average, compared with around $1 per watt in Australia, a global leader in the space.
The outlook isn’t great. BNEF analysts think it will take more than a decade for the industry to match the installations record it set back in 2023. To be fair, that record happened under some very specific circumstances: The Inflation Reduction Act, passed the previous year, had boosted the federal tax credit for rooftop solar, and, at the same time, Californians were sprinting to install systems before the state did away with its lucrative compensation scheme in April 2023.
Still, there are some glimmers of hope. In California, the residential solar market is set to rebound this year and grow by 17% from last year. Meanwhile, Florida, the No. 2 state for rooftop solar, is set to see its installations grow by a staggering 62% in 2026.
That suggests the biggest state markets for rooftop solar are fairly resilient. Some combination of ample sun, high awareness of solar, and rising utility bills has enabled the clean energy tech to keep growing even though a significant slice of homeowners already have their own panels.
Meanwhile, although its potential is much more modest, a far smaller and more accessible form of residential solar is sweeping the nation: balcony solar. Several states have passed legislation green-lighting these DIY plug-in solar systems. They can’t deliver the same wattage as a classic rooftop setup, but they’re relatively cheap and available to renters — not just homeowners. Maybe that emerging boom can help offset the bust for rooftop systems.
Sky-high fossil fuel prices drove people around the world toward clean energy. But even as the Strait of Hormuz reopens, they may not turn back.
America’s war with Iran is maybe, possibly, headed for resolution, but its impact on the global energy sector isn’t fading anytime soon.
The U.S. and Iran signed a deal on Wednesday to end their three-month conflict and reopen the Strait of Hormuz, a crucial oil and gas shipping lane. It’s still unclear what the agreement exactly entails, or whether it’ll even hold up, but fossil fuel markets are taking it as a good omen. Global oil prices have already fallen to their lowest level in months, and gasoline prices across the U.S. are starting to sink. Still, experts say it could take up to a year for oil and gas prices to stabilize, especially given that Middle Eastern fossil fuel infrastructure was damaged during the war.
Amid these past few months of uncertainty, much of the world turned to a common solution: clean energy. People swapped gas cars for EVs, turned to electric appliances for cooking, and took other big — and potentially permanent — steps away from costly and volatile fossil fuels.
When 2026 started, the EV market wasn’t in a great place. The end of federal tax credits had tanked the U.S. market, and global sales were sluggish, too. But with skyrocketing fossil fuel prices came a renewed interest: New EV sales rose through April and May around the world, and BloombergNEF anticipates sales will climb even further throughout 2026.
Outside of higher prices at the gas pump, the U.S. hasn’t felt much of an impact from the energy shock. But in Europe and Asia, people are grappling with higher fuel costs for cooking, heating, and power generation, and have turned to clean solutions in response.
Instead of following President Donald Trump’s call to buy more U.S. fossil fuels, European Union leaders called for a bloc-wide shift to renewables. In Britain, Germany, and the Netherlands, tons of households installed rooftop solar arrays to avoid high electricity prices. In India, a cooking gas shortage led residents toward induction stoves. The Philippines similarly saw a surge in rooftop solar installs, and a new International Energy Agency report suggests the country and its neighbors across Southeast Asia will keep the clean investments coming given the region’s reliance on Middle Eastern oil and gas imports.
Time will tell if the war and its fallout prove to be an inflection point for the clean energy transition, but analysts with think tank Ember argue it’s certainly a possibility. After all, the oil crises of the 1970s pushed the world to look beyond the Middle East for fossil fuel supplies, and to pursue more efficient uses of oil and gas. The same thing could happen this time around — only with cleaner, cheaper, and more secure energy as the alternative.
Hot spring: Clean energy had a record-breaking spring in the U.S., with solar generation beating out coal for the first time in May, among other wins for solar, wind, and battery storage throughout the season. (Canary Media)
Clean energy’s next hurdle: Most wind and solar projects under construction in the U.S. have secured “safe harbor” status, meeting the July 4 deadline to tap federal incentives, but now developers must race to complete those projects in four years. (Canary Media)
Courts deliver on climate: Clean energy groups and states continue to fight the federal government’s multipronged blockade on wind and solar development, scoring victories as the Trump administration abandons one anti-wind fight and is ordered to release millions of dollars in climate grants revoked from states that voted for Kamala Harris in 2024. (E&E News, Utility Dive, New York Times)
Transmission disconnect: The New England Clean Energy Connect transmission line was supposed to bring tons of clean hydropower from Canada into the Northeast U.S., but energy imports have increased only a tiny bit since the line began running in January. (Canary Media)
Solar funding unplugged: The DOE has redirected tens of millions of dollars that the Biden administration allocated to Puerto Rico for a resilient network of solar panels and batteries toward building a gas pipeline and other fossil fuel infrastructure. (Grist)
Double-edged grid upgrades: Making much-needed upgrades to the U.S. grid could result in a $1 billion payout to American utility executives, as publicly traded utilities’ stock valuations are directly tied to their spending. (Reuters)
A yearslong project has finally started producing ammonia with wind power. If the process can be scaled up, it could help ensure farmers have cheap, reliable fertilizer.
In the shadow of a wind turbine on a low rise just outside the western Minnesota town of Morris, a cluster of tanks, pipes, and sheds holds what some believe is the key to a more self-sufficient future for the region’s agriculture and heavy industry.
When the wind is blowing — and it often is, out here — the turbine powers two electrolyzers that cleave hydrogen from water, another system that separates nitrogen out of the air, and a third that binds the two elements to form anhydrous ammonia, a critical input for corn farming. The University of Minnesota West Central Research and Outreach Center commissioned the plant earlier this spring and can produce hundreds of kilograms of homegrown ammonia daily.
As a stable, efficient carrier of hydrogen, the homegrown ammonia could eventually supply raw material for other types of fertilizers, transportation fuels, and high-temperature industrial processes like ironmaking.
“It’s about 100 times cheaper to store and transport ammonia than hydrogen … so this is a gateway for other hydrogen-based industries,” Michael Reese, green ammonia research lead at WCROC, said on a tour of the facility this spring.
“Gateway” is the operative word here. Reese said WCROC plans to add a third electrolyzer to the project in a “future phase,” bringing daily production capacity to about 1 metric ton and annual production between 300 and 400 tons. That sounds impressive, but it’s a rounding error in a highly consolidated industry that produces around 250 million tons of ammonia annually. Minnesota alone imports up to 900,000 tons per year.
That’s a minimum $500 million annual transfer from Minnesota farmers to out-of-state fertilizer suppliers, most of which synthesize the stuff from cheap natural gas at sprawling facilities on the U.S. Gulf Coast, Brandon Isakson, managing director for industry with the St. Paul–based environmental nonprofit Fresh Energy, said in an interview. When prices are high, as they are this year, the outlay can exceed $1 billion, he said.
Anhydrous ammonia and its chemical cousin, ammonium (NH4), join nitrate (NO3) and urea (CO(NH2)2) as the three main nitrogen-derived fertilizers used in modern agriculture — often in combination. All three, along with nonnitrogenous fertilizers like potash and phosphate, are produced in massive “world-scale” plants that put out hundreds to thousands of metric tons daily. They depend on complex global supply chains to reach end users.
Right now, those supply chains are under intense pressure due to the U.S.-Israeli conflict with Iran. About one-third of the world’s urea and one-fifth of its ammonia pass through the Strait of Hormuz, which has been effectively closed to cargo traffic since the beginning of March. While the U.S. has plenty of domestic production capacity, U.S. Department of Agriculture data shows it still imported nearly 40 million tons of various fertilizers in 2025, including nearly 8 million tons of solid and blended urea. Prices for imported urea spiked when the shooting started earlier this year, underscoring domestic farmers’ tenuous relationship with global commodities markets.
Though WCROC has plans to grow the Morris facility, production likely won’t expand there in time to matter for the Hormuz crisis. Nor would it reach the kind of scale that could make a meaningful difference for Minnesota farmers, let alone other hydrogen-hungry industries.
“You’d like to be at 50,000 tons per year to be cost-effective,” Reese said.
But Reese added that he’s optimistic about a not-too-distant future where scaled-up ammonia production facilities dot the Minnesota countryside.
So are others involved with the project. Sameer Parvathikar, senior director of sustainable energy solutions at RTI International, an independent research institute that collaborated with WCROC, said at an April event celebrating the Morris system’s commissioning that it was an important milestone in a multiyear effort to stand up a new, cost-competitive industry from scratch.
“For those of us trying to push this forward from a technology perspective, you realize we have done stuff that actually matters,” he said, noting turnout that included higher-ups in the University of Minnesota system and a North Carolina–based developer looking at commercial applications for an ammonia production pathway that uses clean electricity instead of fossil gas.
At least some farmers here and elsewhere across the Corn Belt see the potential in local ammonia production, too.
In March, a southern Minnesota farming cooperative said it would partner with a Texas-based infrastructure company, a Minneapolis-based carbon credits registry, and the local power and water utility on a project that could produce most of the ammonia its farmers need within a few years. Located in Blue Earth County, the modular plants could pump out as much as 12,000 tons of ammonia annually, the companies said.
It would be one of the first larger-scale deployments of a “modular, green ammonia system that makes the local production and distribution of a critical raw material cost-competitive and more reliable,” according to Talusag, the company behind the technology.
Talusag says its approach lowers ammonia costs by up to 50% by freeing production from fragile global supply chains and using no raw materials other than abundant sun, air, and water. In theory, its plants can locate anywhere with an adequate power supply, whether that’s the middle of farm country or a remote mine site.
KC Graner, president and CEO of Truman-based Central Farm Service, agrees. He told AgWeek in March that farm prices have fluctuated by more than 300% in recent years. Prices can swing several hundred dollars per ton in a single season.
“Local production gives our member-owners a level of control and predictability they’ve never had before,” he said.
Talusag, Central Farm Service, and CleanCounts — the Minneapolis clean energy credits registry — are among more than a dozen members of the Minnesota Made Ammonia Coalition, which pushes for “policy and practical steps” to leverage the work being done at WCROC into commercial-scale green ammonia production.
The coalition’s top priority this year was securing an $8 million legislative grant that the Blue Earth County project’s backers said was needed to move forward. That didn’t happen, leaving its near-term fate uncertain. Tristan Peitz, Talusag’s head of business development, told the House Finance and Policy Committee in April that the facility would have ammonia ready for use in 2028 if it began construction in 2027.
Talusag already operates one green ammonia facility in the Upper Midwest, near the central Iowa town of Boone. Commissioned last spring in partnership with Iowa-based farming cooperative Landus and capable of producing 1 to 2 tons daily, it’s North America’s first “commercial, modular” green ammonia plant, Talusag cofounder and CEO Hiro Iwanaga said at the time. The company is building a plant in Eagle Creek, Iowa, about 50 miles north, that can put out 20 tons daily.
The Boone facility is registered with CleanCounts, which issues a bit more than 40 percent of all renewable energy certificates in North America, chief commercial officer Rob Davis said in an interview. Each certificate, or REC, equals 1 megawatt-hour of electricity, roughly what a typical Minnesota home consumes each month.
To qualify for the federal clean hydrogen tax credit today, producers have to prove that they procured enough renewable power to offset their energy consumption each year. Beginning in 2030, they’ll need to show the power was generated in the same hour it was consumed — a much stricter standard.
“You need a tech-forward registry to be able to meet these requirements,” Davis said.
CleanCounts has dozens of software developers working on a system that can accurately match hour-by-hour output from solar and wind farms across “the vast majority of corn country” by later this year, Davis said.
It’s a big job that’s worth the effort for CleanCounts, which Davis said earns 1 cent when a REC is created and another cent when it’s retired, or claimed by the end user. For cooperatives like Landus and Central Farm Service, the RECs themselves are worth buying because they lower the carbon intensity score, or CI, of their harvests. Biofuels produced from low-CI feedstocks have an easier time qualifying for the federal clean fuels tax credit, state incentives like Minnesota’s sustainable aviation fuel tax credit, and state blending mandates like California’s low-carbon fuel standard.
Lower CI is the impetus for other emissions-reducing investments across the agriculture sector, from pipelines to divert carbon dioxide captured during biofuels production to thermal batteries to replace gas- or coal-powered equipment at ethanol plants. In May, a POET ethanol plant on the Minnesota–South Dakota border commissioned a thermal battery system that charges off the area’s wind-rich power grid, significantly reducing the plant’s reliance on fossil fuels.
Like POET’s battery, and unlike traditional fossil-fueled ammonia factories, green ammonia plants easily flex their output to match variable wind and solar production on the power grid. The WCROC plant can go from 10% to 100% production in about two hours, according to Reese.
Flexible sources of demand on the grid could help Minnesota and surrounding states use renewable power more efficiently. Federal data shows the region’s grid operator curtailed nearly 6 gigawatts of wind power on blustery days — equivalent to six large nuclear reactors — for lack of local demand and transmission capacity.
Minnesota alone would need about 5 gigawatts to produce all its ammonia locally with current technology, according to a 2024 analysis by RMI, an environmental nonprofit. That’s a lot, but maybe not too much. Davis said some projections have curtailment doubling across the region by 2035.
Beth Soholt, executive director for Clean Grid Alliance, a Minneapolis-based nonprofit advocating for clean energy development across the Midwest, said that’s one reason why the region’s policymakers, electric utility leaders, and economic development boosters were enthusiastic about localized green ammonia production just a few years ago.
“Ammonia was the low-hanging fruit, people thought … and you hear every day how expensive the farming inputs are,” Soholt said.
Former President Joe Biden signed legislation authorizing generous tax credits for clean hydrogen production and approved seven regional “hydrogen hubs” to scale and match supply and demand for the stuff. Minnesota was one of several states in the Heartland Hub, where the administration saw abundant wind power supporting a thriving low-carbon fertilizer industry.
The Trump administration has been much less supportive. It ultimately spared the Heartland Hub and four others after earlier moving to dismantle the program, albeit with a shift in focus toward fossil-based production methods. In the meantime, green ammonia boosters’ enthusiasm has been tempered by what Soholt said were “sticky” questions about the cost of electricity and other inputs.
“It just comes down to economics — do these [facilities] pencil out?” she said. “But people have done a lot of work on them.”
For many rural communities and the electric utilities serving them, hope for a green ammonia boom has been replaced by hype around another seemingly endless source of power demand: data centers. Huge computing facilities like the ones Google has proposed near Rochester and Duluth can consume hundreds of megawatts of electricity, many times more than the WCROC and Talusag ammonia plants draw.
Data center loads are less flexible than ammonia plants, however, and they’re attracting increasingly stiff pushback from rural residents concerned about noise, air pollution and other quality-of-life impacts. In addition to being better at soaking up excess renewable power, ammonia plants may be better neighbors, Davis said.
“People are beginning to realize it’s a lot harder to build data centers near wind farms … but there are a lot of farmers growing a lot of corn out near wind turbines, and they definitely need fertilizer,” he said.
While farmers will claim the first batches of homegrown Minnesota ammonia, they’re not the only potential customers. At scale, the industry could provide secure, local supply of a critical input for advanced steelmaking.
Today, most steel plants in the United States use high-grade coal to purify iron in giant, superhot blast furnaces. But those facilities are aging, and eye-watering construction costs mean the U.S. is unlikely to build a new one. So steelmakers are looking ahead to direct reduction, a newer, more flexible process that doesn’t require coal. Most present-day direction reduction plants use natural gas as the reducing agent, but experts say the process can be adapted to run on pure hydrogen.
That could happen here in Minnesota — eventually. Mesabi Metallics, the company behind Minnesota’s first new iron mine in 50 years, says making direct-reduced iron is part of its long-term vision for integrated “green” steelmaking. It’s focused on getting its Iron Range mine open later this year and hasn’t given a firm timeline for a direct-reduction plant, but the prospect is tantalizing for Iron Range boosters hoping to keep the region’s primary industry competitive well into the future.
Reese said that would mark a more sustainable return to form for a state whose early economy was closely tied to the land.
“We have an opportunity here in Minnesota to follow the model we followed in the late 1800s — to take these natural resources and transform these industries,” he said.
Editor’s note: This story is the second in a four-part series on clean energy innovations within Minnesota’s industrial sector. The series is underwritten by Fresh Energy, which like all MinnPost funders does not weigh in on editorial decisions.
Editor’s note: This story was updated on June 9, 2026, to clarify the service provided by CleanCounts, which issues and tracks energy attribute certificates such as renewable energy credits.
This article first appeared on MinnPost and is republished here under a Creative Commons Attribution-NoDerivatives 4.0 International License.
In California, Texas, and other places, solar, wind, and batteries hit new highs. Here are the big takeaways from this year’s shoulder season.
As spring gives way to summer, many parts of the U.S. are already feeling the heat. It’s a good moment to take stock of the energy breakthroughs that transpired this past “shoulder season.”
That’s the period of time between the chill of winter and the high temperatures of July and August, when renewable energy systems tend to perform best. With the milder weather and longer daylight hours, total demand stays relatively low while wind and solar ramp up, covering greater shares of grid consumption.
Here are four ways clean energy set new records this spring — and what these feats tell us about where the energy system is headed. While records reflect momentary successes amid ideal conditions, they’re worth noting because they push the boundaries of what’s possible, and lay the groundwork for similar success across broader swaths of the year.
Coal used to make more electricity than any other source in the U.S. Then it fell behind natural gas, and eventually dropped below nuclear. In May, the country’s coal power production slipped behind solar generation, making sunshine the third-biggest source of electricity for the month for the first time.
The U.S. isn’t building more coal plants, though the Trump administration has elected to stop any from closing down, whether or not they can physically operate. Solar, on the other hand, has led the nation in new capacity construction for five years running. When the sun emerges from its wintry slumber, that ever larger fleet shows what it can do.
This upset is all the more striking because, as renewables skeptics love to repeat, solar doesn’t produce all the time. Coal plants can run 24/7, if they aren’t broken or hobbled by uncompetitive operating costs. But even with that structural limitation, solar produced more gigawatt-hours in the daytime than coal did throughout the whole month of May. And this is true not just for a particularly sunny region, or a state with aggressive solar-friendly policies, but across the country.
Solar might not beat coal production for all of 2026, but it’s only a matter of time before it outperforms coal for an entire season, and then eventually for a whole year.
California has entered the execution phase of its energy transition, when the long-promised potential of solar and batteries has turned into empirical breakthroughs in the power markets. The records came at a dizzying pace this spring.
On the evening of March 29, batteries covered 44% of demand (and 42.8% of the supply mix) in the grid managed by the California Independent System Operator (CAISO), which serves about 80% of the state. That was a mild Sunday, so batteries could meet a higher portion of demand than, say, on a blistering hot workday with everyone’s air conditioning turned on. But the absolute numbers speak for themselves: Batteries discharged over 12 gigawatts at 7 p.m. That’s more than New York City consumes on a hot summer day. Not bad for a battery construction spree that largely transpired over the last five years.
On May 16, batteries held gas plants to a shockingly marginal role in the grid for a four-hour period after 7 p.m. Gas never made it above 3% of demand during that time, according to an analysis by the Institute for Energy Economics and Financial Analysis.
The batteries active in California typically can sustain maximum discharge for four hours. This is visible in the daily pattern of grid activity: Batteries surge around sunset to become the single biggest power source in the CAISO grid. Some of them save their energy for later in the night or the early-morning hours before solar produces again. This dynamic leaves a gap in the middle of the night, when gas shows its value.
One way to extend the clean energy success story would be to build longer-lasting batteries. The first major battery with eight hours of duration came online on June 1 in Southern California, and it will offer a sneak preview into what happens when batteries can serve a longer swath of the day.
In the near term, California is tapping more wind power for nighttime supply. The multi-gigawatt SunZia wind farm in New Mexico started shipping power to California this spring, instantly setting new records for wind power’s contribution in the CAISO grid. The Institute for Energy Economics and Financial Analysis compared the grid activity for May 16 of 2025 and 2026. On that day last year, from midnight to 6 a.m., gas generated 3.6 gigawatts, keeping the system going through the night. This year, for that same time period, gas contributed a paltry 560 megawatts. The cheap wind power rushing in from SunZia was pushing gas out of its last redoubt.
One could say these observations are cherry-picking in favor of clean energy. But such ripe cherries simply didn’t exist a year ago, much less five years. California’s clean energy plants should be able to replicate or beat these records in the fall shoulder months. The more challenging test will be whether solar, wind, and batteries can steal market share from gas in the midst of a heat wave, when the fossil fuel has historically hit its maximum output. This El Niño cycle promises to deliver the requisite conditions for that test.
New York state hasn’t built the kind of batteries California has, but it did set a new solar production record on June 3. Solar of all sizes delivered 5.6 gigawatts, serving a record 29% of demand at noon that day, according to the New York Independent System Operator.
The details are more revealing: Almost all of that generation came from small-scale, customer-sited systems, while utility-scale contributed only 530 megawatts. That’s less than the output of individual solar projects out West.
Even the regions that struggle to build much solar are breaking records for themselves. And where you don’t have wide open desert to build sprawling installations, small ones on rooftops and in yards can add up to a meaningful surge.
This spring, Texas set just about every clean energy record you could ask for, as helpfully documented by data firm Grid Status.
Batteries shipped the most power to the grid on March 13, at 7:30 p.m., with 10.4 gigawatts, which satisfied a record 20% of evening demand at that moment.
Wind and solar served a record 79% of demand (and 76.9% of supply) on the afternoon of March 14; along with baseload nuclear, the zero-carbon power plants limited fossil-fueled power to just 13% of the fuel mix for a five-hour swath of midday.
The Texas grid produced more solar power than ever before on May 13, a stunning 34.4 gigawatts at 12:40 p.m. It produced more wind power than ever before on May 17, nearly 29 gigawatts at 11:50 p.m. The highest combined renewable output came on May 14 at 3:15 p.m., almost 48 gigawatts.
Again, these are mild shoulder months, when Houstonians aren’t sweltering too much yet and when gas plant operators take their machinery offline for maintenance. In these favorable conditions, we’re seeing what happens when a society unleashes the trifecta of solar, wind, and batteries. The solar peaks at midday; the wind often kicks up after sunset. When a particular day gets both sunny and gusty, the two resources alone now cover most of the midday consumption. And batteries are carving deeper into the evening peaks, corroborating the trend that California pioneered.
No one source of clean energy can run the whole grid on its own, but none has to. The portfolio effect is on stark display as Texas delivers a deregulated version of clean energy abundance.
It’s the first time that’s happened across an entire month, and it comes despite the Trump administration’s efforts to reinvigorate coal and hamper solar.
The U.S. just hit a big milestone: It got more power from solar panels than from coal plants in May.
It’s the first time that has ever happened across an entire month, and all the more notable given the Trump administration’s all-out push to revive the moribund U.S. coal industry.
Solar produced 12.8% of the nation’s electricity in May, a sun-soaked month that’s often among the best-performing for the clean energy source, per new data from think tank Ember. Coal power made up just 12.2%, a near all-time low, while natural gas dominated the mix at 37%.
For years, the power sector was the single biggest source of planet-warming pollution in the U.S., which is itself responsible for more historical greenhouse gas emissions than any other nation. America’s heavy reliance on coal, an especially dirty fossil fuel, drove those dubious distinctions.
In the late 2000s, facing hotter competition from increasingly abundant natural gas and a burgeoning renewable energy sector, coal-fired electricity output peaked in the U.S. It’s been all downhill from there for coal, which slipped from providing nearly half the country’s electricity needs two decades ago to just 17% last year. Emissions from the power sector have fallen accordingly, and now it’s the second-largest source in the U.S., after transportation.
President Donald Trump, who has insisted that the words “beautiful, clean” precede “coal” in all instances, is trying his best to stem the sector’s terminal decline. His administration has issued a slew of controversial emergency orders requiring aging coal plants to stay online — even those that are broken or otherwise unable to run. Earlier this month, it announced it would plow $700 million into the industry, both to patch up old plants and to build two new ones.
Coal actually did produce a bit more electricity last year than in 2024, but mostly because a combination of high power demand and elevated natural gas prices made the fuel momentarily more attractive.
Still, that doesn’t reverse the long-term trend. Every year, gigawatts of new clean energy come online in the U.S., because it’s cheap and comparatively easy to build. For several years running, over 90% of new electricity capacity built in the U.S. has been in the form of solar, wind, or batteries.
Meanwhile, the last new coal plant in the U.S. was completed back in 2013.
Take those two facts together, and it’s clear that solar is going to outperform coal many more times in the near future, and by wider and wider margins each time.
The company’s Cartersville, Georgia, factory is the largest of its kind in the nation — and it just started producing the key solar panel component.
Qcells has officially begun commercial production of silicon solar cells at its factory in Cartersville, Georgia, the company said Tuesday. That factory is the largest of its kind in the country — and a long-awaited boost to the U.S. solar supply chain.
For five years straight, the U.S. power sector has built more solar farms than any other kind of power plant. In 2022, the Biden administration crafted industrial policy to ensure as many of those solar panels as possible were made in America. Previously, the U.S. solar manufacturing base had withered in the face of stiff competition from China — but the industrial revival effort worked. In just a few years, the U.S. has opened up enough factories to assemble nearly 70 gigawatts of finished solar panels, according to the Solar Energy Industries Association.
That’s well beyond what the U.S. installs in a year, but production of the cell — the high-value component that converts sunlight into electricity — has lagged far behind.
Previously, just three other companies made the component in the U.S.: Suniva can produce 1 gigawatt at its cell factory in Georgia, and ES Foundry and Silfab each can make 1 gigawatt in South Carolina. In a few months, Qcells will be able to manufacture 3.3 gigawatts at its cell factory, which would more than double the current operational U.S. solar-cell capacity.
“It’s a great achievement for an industry that had zero active cell capacity in the last couple of years,” said Scott Moskowitz, vice president of market strategy and public affairs at Qcells.
Qcells, once a German solar-cell maker and now a subsidiary of Korean industrial giant Hanwha Group, first announced the Cartersville project in early 2023, pledging to colocate production of four components of the solar supply chain: silicon ingots, wafers, cells, and modules. The module lines went live in 2024. The full facility was originally supposed to open that year, but it took longer to calibrate those more complicated processes. Currently, the full 3.3-gigawatt production of the four solar components is slated for the third quarter.
Another 22 gigawatts of cell capacity is under construction across the U.S., per the Solar Energy Industries Association, though that figure is constantly evolving. On Monday, Japan-headquartered Toyo said it would spend $357 million to add 1.5 gigawatts of cell production at its Houston module-assembly plant. ES Foundry is working to expand its factory to 3 gigawatts by year’s end. T1 Energy is building a cell fab outside Austin. Additionally, First Solar’s U.S. factories produce up to 14 gigawatts of cadmium-telluride thin-film panels, which generate electricity without needing silicon-based cells.
Crucially, potential manufacturing capacity does not equate to production. Silfab, for instance, temporarily closed its cell factory after it accidentally released potassium hydroxide and hydrofluoric acid in rapid succession in March. (State authorities found no impact to the surrounding community, including a nearby elementary school.) Compared with the largely mechanical work of robotically assembling all the pieces into a finished panel, etching silicon wafers into cells is heavy industrial work that involves potent chemicals and other cleanup concerns.
“You’re leveraging complicated science to create a solar cell that generates electricity,” Moskowitz said. “There are more steps to the process, and the steps are more intensive.”
The giant, L-shaped Cartersville site houses “four factories in one,” he noted. At one end, polysilicon gets melted into ingots, and the pieces move sequentially through the discrete steps until complete panels roll off the line at the other end of the building. Between this factory and the module assembly operation about 30 miles north in Dalton, Georgia, Qcells expects to employ 3,800 people in the region doing high-tech, robot-assisted manufacturing.
Developers who use domestically produced cells can more easily qualify for the domestic-content tax credit bonus. Qcells also earns a higher manufacturing tax credit for each cell that it makes. These policies arose in the Biden-era Inflation Reduction Act, which was intended to spur a U.S. manufacturing renaissance for clean energy. The Trump administration subsequently phased out the credit for installing solar projects after July 4, but projects can still claim the credits for four years under “safe harbor” rules.
Once the safe-harbored projects get built or fall through, developers will lose the major financial incentive to buy American cells and panels rather than look for the cheapest imports that can get past the U.S. tariff regime. Domestic production does, however, offer a potentially winning story for developers to tell to skeptical communities or political leaders. It also insulates their project timelines from disruptions in foreign trade, as seen during Covid, or the current surge in shipping costs linked to the U.S. war with Iran.
The future is hard to predict, but for now, demand for electricity production is higher than it has been in a generation. The tech giants building AI have become obsessed with “speed to power,” and it’s hard to imagine a faster way to achieve that than to order solar panels that arrive on a truck straight from the factory.
The clean energy projects thwarted by state lawmakers could have gone a long way toward meeting spiking energy demand, lowering bills, and eliminating pollution.
Last week, the Ohio Supreme Court blocked a permit for what would be the state’s largest solar installation. The 800-megawatt Oak Run Solar Project still has a pathway to completion — the court reversed only one part of the state siting board’s prior approval — but it remains unclear how things will play out.
This is just the latest example of how state lawmakers and other officials have obstructed renewable energy development in Ohio. In total, they have thwarted more than 5.3 gigawatts of solar and wind projects over the last dozen years.
So says a recent analysis released by Save Ohio Parks, which opposes fracking and oil and gas extraction from public lands.
“It’s a lot of inexpensive power that we don’t have available to us. And it means fewer choices for consumers,” said Tom Bullock, executive director for the Citizens Utility Board of Ohio. “Boy, would that come in handy right now when electricity prices keep going up, up, up.”
Ohio, like many other states, is facing rising utility bills as well as massive new energy demand due to a wave of proposed data centers. The Save Ohio Parks report contends that clean energy could have helped rein in those energy costs while meeting a huge chunk of data centers’ demand if Ohio had allowed more development. The 5.3 GW of blocked clean energy would have also avoided large amounts of greenhouse gas emissions and local air pollution.
The state stepped up its pushback on wind and solar as each of those clean energy sources became more cost-competitive with fossil fuels and nuclear power.
A 2014 law that more than doubled property-line setbacks for wind turbines effectively blocked over 3.3 GW of utility-scale projects in the state, the report notes. Efforts in 2017 to roll back those restrictions failed, leaving Ohio among the nation’s most restrictive states for wind power.
“The economics of a wind farm don’t work when you need that amount of setback from a property line,” said Rachel Kutzley, a Save Ohio Parks board member who worked on the report.
Seven years later, Gov. Mike DeWine signed Senate Bill 52, which lets counties ban new solar projects above 50 MW of capacity and “economically significant” wind farms able to produce more than 5 MW of electricity. SB 52 doesn’t let counties ban power plants that use fossil fuels or nuclear power.
Neither the Save Ohio Parks report nor a February 2026 paper in the journal Frontiers in Sustainable Energy Policy quantified how much clean energy generation the bans by Ohio counties have prevented.
Projects that were already in grid operator PJM Interconnection’s queue are not subject to outright bans under SB 52. The Ohio Power Siting Board, however, can deny permits for individual projects — and since 2021 it has rejected eight installations, making Ohio one of the toughest states for developing clean energy. The board has routinely referenced local government opposition when rejecting projects.
Those eight rulings alone have killed more than 1.1 GW of solar generation.
Developers withdrew five other applications for projects that would have added roughly another 1 GW, after adverse recommendations from the Power Siting Board’s staff or significant local pushback made it likely the full board would deny permits. The Kingwood Solar case, which challenges the board’s deference to local government opposition, is due to be decided soon.
Matt Schilling, a spokesperson for the Ohio Power Siting Board and Public Utilities Commission of Ohio, said he did not have a comment on the report from Save Ohio Parks. “However, I will observe OPSB has approved 49 solar projects across Ohio with nameplate capacity totaling 9,250 MW,” he added.
Only about one-third of those approvals were for permit applications filed after SB 52’s effective date.
It’s not just solar and wind — Ohio has also stymied energy-efficiency efforts over the years, which would have additionally cut down on pollution and saved money for residents. The Save Ohio Parks’ report doesn’t consider the effects of the state’s infamous House Bill 6, which eliminated utilities’ energy-efficiency requirements after 2020.
Those impacts would have been quite sizable, said Mike Specian, a utilities manager with the American Council for an Energy-Efficient Economy, who shared his separate analysis with Canary Media.
If utilities had continued to achieve energy savings for customers after 2020, the cumulative savings could have been as much as 70 terawatt-hours, or 70 million megawatt-hours, Specian said. That high number is partially because energy-efficiency investments provide benefits, on average, for nearly a decade. “Those savings deliver year over year over year,” he said.
The mix of thwarted solar and wind projects alone likely would have displaced 7.1 million metric tons of carbon dioxide emissions from fossil fuel plants, said Ben King, a director with research firm Rhodium Group’s energy and climate practice. Carbon dioxide is a major greenhouse gas that drives human-caused climate change.
King based that estimate on results from the Environmental Protection Agency’s Avoided Emissions and Generation Tool. Ohio’s lost clean energy generation could have cut millions of metric tons of pollution from sulfur dioxide, nitrogen oxides, and other pollutants with harmful health effects as well, the EPA tool shows.
The lost clean energy opportunities are also impacting consumers’ finances, although it’s hard to tell exactly how much because electricity prices reflect multiple components.
Ohio gets about 7.5% of its electricity from wind and solar, compared with 80.6% from coal and gas, according to federal data for 2025.
When it comes to the electricity dispatch market, “the generation we have less of is the least expensive in Ohio,” said Ashley Brown, a former member of the Public Utilities Commission of Ohio. Solar and wind have no fuel costs, so their marginal costs for producing energy are very low. That competition also reins in bidding by producers of other forms of electricity, particularly fossil fuels, whose prices have soared even higher because of the Trump administration’s war on Iran.
“It really does force enormous price pressure on other forms of generation,” Brown said.
Less solar and wind generation has some effect on the capacity market, the mechanism PJM uses to ensure it will have enough energy producers available to meet future demand spikes. Last year, capacity made up about 16% of the wholesale cost of electricity, noted Jeff Shields, PJM’s senior manager for external communications. Even though renewables count less toward capacity than other types of energy, “we can use all the capacity we can get,” he said.
Renewables’ ability to come online more quickly than other sources could do a lot to curb inflation, said Bullock at the Citizens Utility Board of Ohio. “Unless Ohio takes action, consumers are locked on this escalator. We’re strapped to the escalator that keeps going up.”
Nevertheless, some Ohio lawmakers seem intent on making it harder — not easier — to build new clean energy projects in the state.
SB 294, reported out of the Senate Energy Committee on June 2, would further cement the state’s preferences for natural gas and nuclear power — and potentially make it even harder to get approval from regulators for solar and wind.
Led by New York, the attorneys general argue that the administration’s agreement to reimburse the energy giant for abandoning its offshore wind leases is illegal.
New York and six other Democratic-led states are challenging the Trump administration’s controversial efforts to pay private energy firms to abandon their U.S. offshore wind projects.
On Tuesday, the coalition of blue states sued the U.S. Department of the Interior over its March agreement with French oil giant TotalEnergies. Under the deal, TotalEnergies forfeited its lease for a large offshore wind area near New York and New Jersey. In exchange, Interior said it would “reimburse” the company for the $795 million it paid in lease fees, money that TotalEnergies promised to put toward fossil fuel projects.
At the time, former Interior employees and offshore wind experts questioned whether the department could legally carry out its unprecedented payback plan. Now, attorneys general from seven states are calling it an “unlawful” agreement that misuses taxpayer dollars. The action came after the government tried repeatedly and ultimately unsuccessfully to block construction of offshore wind farms along the East Coast.
“The Trump administration is once again trying to kill clean energy projects and destroy good-paying jobs for New Yorkers,” Letitia James, the New York attorney general, said on Tuesday in a statement.
New York is joined in the lawsuit by Connecticut, Maine, Massachusetts, New Jersey, Rhode Island, and Vermont, which claim that the lease cancellation harms the states’ economies, power grids, and climate targets. State leaders and utility regulators in the region had been anticipating a massive influx of offshore wind power from projects like TotalEnergies’ to meet their soaring electricity needs in the coming years, especially during fierce winter storms and heat waves that threaten sweeping blackouts.
“New Jersey needs more power supply,” Jennifer Davenport, the New Jersey attorney general, said in a statement to Canary Media. “The federal government’s lawless attack on clean energy development is bad for the grid, for our economy, and for ratepayers.”
In 2022, a subsidiary of TotalEnergies, called Attentive Energy, won a lease for over 84,000 acres off the coast of New York and New Jersey through a competitive federal auction, which drew the highest bids in the nation’s history. TotalEnergies said it aimed to develop over 3 gigawatts of offshore power in the large, shallow swath of ocean and provide clean electricity for more than a million homes across the two states.
The five New England states joining the lawsuit were also slated to benefit from the wind farm, since they regularly import energy from New York through a high-voltage interconnection, according to their filing with the U.S. District Court for the District of Columbia.
Interior officially canceled Attentive Energy’s lease in April, saying it was acting in the public interest.
TotalEnergies signed an identical but separate deal with Interior this spring to cancel the $133 million lease for its planned 1-GW Carolina Long Bay wind farm near North Carolina. Another developer, Ocean Winds, has also inked agreements to relinquish offshore wind leases near California and in waters off New York and New Jersey, which totaled nearly $900 million.
This week’s lawsuit could provide a “roadmap” of sorts for other states looking to fight the Trump administration’s lease-cancellation deals, said Tony Irish, a former Interior attorney who now works for the organization Public Employees for Environmental Responsibility.
“I’ve been hoping for this day, and I’m glad that it’s here,” he said, adding that the New York–led lawsuit “brings a phenomenal array of valid claims” against the agreement with Attentive Energy.
In their suit, the attorneys general argue that the Trump administration’s arrangement violated the Outer Continental Shelf Lands Act, which limits Interior’s ability to cancel offshore wind leases and requires the department to hold a hearing weighing the pros and cons. The coalition also maintains that Interior violated the Judgment Fund Act because of how it paid back TotalEnergies’ $795 million in lease fees. The fund uses taxpayer dollars to settle lawsuits and claims against federal agencies, but the two parties aren’t settling any active litigation.
The attorneys general are asking the D.C. court to strike down the agreement, vacate the lease cancellation, and stop the Trump administration from taking further steps to implement the deal.
Interior, for its part, defended its actions with the offshore wind developers.
“Let’s be clear: these were voluntary agreements,” a spokesperson said by email on Tuesday. “No one was forced to sign them. Moreover, these settlements were reviewed and approved by the Department of Justice, underscoring that they went through the appropriate channels.”
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