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Now the legislature must hammer out the differences between the Senate text and the House version, which includes major cuts to energy-efficiency funding.
The Massachusetts Senate yesterday passed a sweeping energy-affordability bill that aims to save residents $14 billion over 10 years in a state that has some of the country’s highest utility costs.
The legislation includes measures that would change the state’s energy procurement process, put guardrails on the activities of third-party electric suppliers, and allow utilities to securitize certain spending, essentially lowering the cost they pay to borrow money. Other provisions aim to cut energy costs by decreasing residents’ reliance on fossil fuels. The bill would authorize the use of plug-in solar systems and phase out a major source of gas infrastructure spending.
“We believe if we can reduce our overdependence on gas … then we’ll be better off,” said Sen. Michael Barrett (D), chair of the Joint Committee on Telecommunications, Utilities, and Energy, and a major voice on climate and energy issues in the legislature, during yesterday’s debate. “These high bills are all fossil fuel–driven.”
Several amendments were approved during the debate. One specifies that data centers will not be eligible for state tax credits unless they meet requirements for clean energy procurement, energy efficiency, and load flexibility. Others call for an investigation into whether utilities’ guaranteed rates of return on investment are excessive, and would close a loophole that might otherwise allow a contentious wood-burning power plant to go forward in western Massachusetts.
The goal of the legislation was to dig into the complexities of the sprawling electric and gas systems to find and eliminate unnecessary fees and costly inefficiencies, Barrett said.
“You cannot save people money, fundamentally, without going after the status quo,” he said. “What we don’t want to see is legacy overcharges that you pay every month.”
The legislation, notably, would not lower spending for Mass Save, the state’s energy-efficiency program, in sharp contrast to the controversial $1 billion reduction the House version calls for. The House’s proposed cut would represent about two-thirds of the roughly $1.5 billion remaining in Mass Save’s three-year budget. Supporters say the move would quickly bring down customers’ bills, but opponents argue that these savings would be small — and that every dollar spent on energy-efficiency programs lowers overall costs for everyone.
The House and Senate now have to hammer out the differences between their versions, and each chamber will need to vote on the final legislation.
One year ago, President Donald Trump signed a massive bill into law and ripped away clean energy tax credits. Renewables have rolled with the punches.
One year ago, President Donald Trump got his Fourth-of-July wish. Republicans rammed a massive tax and spending bill through Congress before his preferred July 4 deadline, allowing Trump to sign it into law during a showy holiday ceremony at the White House.
Alongside huge cuts to Medicaid, food stamps, and other programs aiding America’s neediest residents, the One Big Beautiful Bill Act repealed large swaths of the Inflation Reduction Act — the only significant piece of climate legislation the U.S. has ever managed to adopt.
That law would have marshaled as much as $1.2 trillion to transition the U.S. economy away from fossil fuels and toward renewable energy, largely through tax credits that make it cheaper to build wind turbines and solar panels. But Trump’s big bill sunsetted those incentives; as of Saturday, they will no longer be accessible to clean energy developers unless they have already hit certain construction benchmarks.
Still, despite the tax credits’ looming demise, and the Trump administration’s myriad other attacks on clean energy, developers have continued building renewables at a stunning pace over the past year. More than 90% of the power plants brought online in America in 2025 were solar, wind, or battery farms, according to the U.S. Energy Information Administration. And the agency projects that these clean resources will account for 93% of new additions to the power grid this year.
There’s a simple reason for clean energy’s unstoppable rise: America needs more energy fast, and only renewables and batteries can deliver it.
After decades of staying flat, energy demand is surging. Big Tech firms are building new data centers that use as much electricity as small cities. Homeowners are switching to electric stoves and heating. People are swapping gas vehicles for electric ones.
Meeting this new demand requires building more supply: more power plants, batteries, poles, wires, and transformers that can produce, store, and transport more electrons. And as gas power faces yearslong supply-chain delays, clean energy is the only thing that can be built quickly and cheaply enough to keep up.
It’s not as if clean energy will escape unscathed from the One Big Beautiful Bill Act — or from the Trump administration’s continued clean energy onslaught.
Over the long term, the disappearance of tax credits will take its toll: One estimate suggests the U.S. will build less than half as much clean energy between 2025 and 2035 as it would have with the incentives in place, with the biggest hit happening in the latter years of that range.
In the near term, the Trump administration’s blockade on federal permitting for wind and solar projects, its payouts to cancel offshore wind leases, and other attacks are having a real negative impact.
This past year has proven that clean energy can roll with some punches — and also that the Trump administration is prepared to keep on taking swings at the industry.
Independence nay: The U.S. Supreme Court rules the president can fire regulators at independent federal agencies, including FERC and the Nuclear Regulatory Commission. (E&E News)
Another wind payoff: The Trump administration says it will pay Duke Energy $129 million to abandon its offshore wind project off North Carolina, which the utility says it will reinvest in gas and nuclear power projects. (New York Times)
Farming the sun: Solar opponents in Ohio have used alleged threats to agricultural land to derail projects, but a new report makes clear that arrays only take up a fraction of a percent of prime farmland both in the state and beyond. (Canary Media)
Permitting plateau: Trump administration policies holding back clean energy permitting are putting 92 GW of projects at risk, representing $121 billion in investments, a new Wood Mackenzie report finds. (Reuters)
Sunrise, sunset: Connecticut passed a law that authorizes the use of plug-in balcony solar panels, expands the state’s community solar program, and extends solar incentives, while also instituting new restrictions on solar development. (Canary Media)
Steel’s clean opportunity: It’s been a year since Japan’s Nippon Steel acquired U.S. Steel, but former steelworkers and other residents in Northern Indiana are still waiting to see if the acquisition turns into clean, job-creating investments. (Canary Media)
Grid funding disconnect: A Government Accountability Office audit finds Puerto Rico has only received about 25% of the $14 billion it was allocated for grid repairs and a solar and battery buildout after 2017’s Hurricane Maria destroyed much of the island’s energy system. (Associated Press)
Gov. Josh Green, a Democrat, wants to import LNG to slash energy bills. But the move might not lead to savings — and it could trip up the state’s climate goals.
On June 8, 2015, Gov. David Ige sat under the great seal of the state of Hawaiʻi and signed the nation’s first legal commitment to run an entire state’s grid system on 100% renewable electricity.
Ige, a Democrat, lamented that Hawaiʻi was “the most oil-dependent state” in the U.S.; unlike others, it relied on oil to produce nearly all of its electricity.
“Making the transition to renewable, indigenous resources for power generation will allow us to keep more of that money at home, thereby improving our economy, environment and energy security,” he said at the time.
Two months later, he shot down a pricey proposal to use another imported fossil fuel — natural gas — to reduce the islands’ dependence on oil imports. Ige’s reasoning was clear: “It’s time to focus all of our efforts on renewables,” he said.
Now, Ige’s successor, Gov. Josh Green, is abandoning that all-out focus on renewables — and throwing his support behind a natural gas import scheme that critics contend would threaten the state’s climate targets while delivering marginal savings, at best, to residents.
Green, also a Democrat, is backing a $2 billion bid by Japan’s largest energy company, JERA, to construct a floating liquefied-natural-gas import terminal called Longboard LNG. In May, the Federal Energy Regulatory Commission granted JERA’s request to begin the review process for the project.
This vessel would ride the surf near Barbers Point, an industrial zone in west Oʻahu that’s home to several power plants. LNG tankers would pull up every three to four weeks to unload the gas, which would flow via undersea pipeline to shore and then fuel a new 500-megawatt power plant to serve Oʻahu, the state’s most densely populated island.
The proposed plant could comfortably meet about 40% of the island’s highest recorded electricity demand and has a target commercial operations date of 2030. Green contends that natural gas can help the state wean off costly and polluting oil without undermining its legal mandate to fully decarbonize its electricity system by 2045. In June, he told Hawaiʻi Public Radio that while the state needs solar and other renewables, it also should have pursued natural gas a decade ago.
“We made a mistake not having a more balanced energy plan,” he said.
The state’s renewables buildout has been buffeted by a once-in-a-century pandemic, multiple global conflicts, and a catastrophic fire. A decade into the transition, utility customers in Hawaiʻi remain mercilessly exposed to the whims of the global oil market, which saw prices spike this spring after Iran cut off most shipping through the Strait of Hormuz.
To date, the energy transition has not sufficiently addressed the primary concern of many of Green’s constituents: Their energy rates are the highest in the nation. JERA, meanwhile, claims it can cut Oʻahu households’ electric bills by $500 a year on average.
But critics say that it makes no sense to tether the state to yet another internationally traded fossil fuel — one whose price also shot up thanks to the war in Iran.
“You can’t solve this problem of a reliance on imported oil by moving to another import that we don’t control,” said Chris Lee, a Democratic state senator who authored the 100% clean energy law and stood beside Ige as he signed it. “And that’s just very painfully obvious.”
This isn’t just a problem for the 50th state. Hawaiʻi started a trend with its 100% clean energy law; nearly half of all states followed with similar measures, and many of them have struggled to build renewables as fast as they hoped, too. Now, elected leaders of these states are also grappling with rising energy costs and, in many cases, a slower-than-expected buildout of renewables.
In New York, long a self-styled leader in the fight against climate change, Gov. Kathy Hochul (D) just eliminated binding interim carbon-reduction targets due to concerns about affordability. Several other Northeastern states considered weakening or undoing their own climate policies in spring legislative sessions, signaling a broader shift toward a less hopeful era of the clean energy transition.
While Hawaiʻi has not yet touched its marquee climate laws, the politics of affordability are clearly having an impact: The biggest energy conversation over the last year in one of the nation’s bluest states has revolved around a massive fossil fuel investment. If Hawaiʻi locks in this natural gas infrastructure, it would mark a significant change from the path it first laid out when it bet on the clean energy transformation.
Lee, who represents part of Oʻahu’s eastern coast, spent three years arguing on behalf of the 2015 climate legislation before skeptical colleagues, hesitant state agencies, and a reluctant utility. When it finally passed, Lee recalled it signaled a “paradigm shift.”
“We realized this is very possible, and not only possible, but inevitable,” he said recently from his office at the Hawaiʻi State Capitol.
Ultimately, advances in renewable energy technologies, like wind and solar, helped make the case for decarbonization, Lee said. The goal also tapped into a broad desire to make Hawaiʻi more self-sufficient.
“For a long time here in Hawaiʻi, we’ve been dependent on imports — food, energy, pretty much everything we consume — and that’s been one of our Achilles’ heels,” Lee said. “We spend billions of dollars that we send overseas every single year to import these things that we rely on, bare necessities.”
In 2018, Hawaiian Electric, the investor-owned utility that supplies power to 95% of customers in the state, awarded bids to four new large-scale solar projects to move Oʻahu toward the 2045 target. The utility mandated the projects come online by the end of 2022.
Only one of those projects, Clearway Energy’s Mililani I Solar, hit that deadline. The others stumbled amid COVID supply chain disruptions and the state’s notoriously slow permitting process. The last of the batch, Hoʻohana Solar, came online last year.
The utility was just beginning to move on from the challenges of the pandemic when a deadly blaze burned through the town of Lahaina on Maui on Aug. 8, 2023, killing 102 people and damaging or destroying thousands of buildings. A local and federal investigation implicated Hawaiian Electric’s equipment; the utility subsequently confirmed that broken power lines had ignited dry vegetation and started a fire, which later rekindled and spread out of control.
In the wake of the fire, Hawaiian Electric’s credit rating dropped to junk status, leading Clearway to cancel three major solar projects and other developers to raise their electricity prices.
Despite the sluggish large-scale solar buildout, Hawaiʻi is technically on track to meet its interim targets under the clean energy law. Hawaiian Electric hit 37% qualifying renewable generation in 2025, mostly due to broad adoption of rooftop solar. Hawaiʻi has the highest rooftop solar penetration of any state in the U.S.; around half of single-family homes on Oʻahu boast panels.
Rooftop solar delivers substantial savings for those with the means to install it, and has reduced the overall volume of oil the state needs to burn to meet electricity demand. But that progress isn’t translating into savings for most customers: Families without solar on their homes are still paying the highest electricity rates in the nation and remain susceptible to dramatic shocks in the global oil market. When Russia invaded Ukraine in 2022, for instance, power prices for average Hawaiʻi households jumped by more than 20%.
In May 2015, an Oʻahu residential customer who used 500 kilowatt-hours of energy in a month paid $140.48. In May 2026, that same customer using the same amount of energy paid $256.27, according to Hawaiian Electric’s estimates. In a state that also has some of the nation’s highest food and housing costs, Hawaiʻi’s most vulnerable residents are often burdened with more bills than they can reasonably pay.
At a local energy conference in May 2024, Green suggested publicly that LNG could reduce the state’s reliance on oil — and thus energy bills — while it worked toward the 2045 clean energy mandate. Last October, the governor’s office announced a strategic partnership with JERA.
“On the table, I have the offer of over $2 billion of private investment,” Green told Hawaiʻi Public Radio in March. “We have an opportunity, if I’m constructive and pragmatic, to help our next generation have a lower cost of energy.”
Aside from the governor, the loudest local champion of the JERA project has been the Hawaiʻi State Energy Office, led by Chief Energy Officer Mark Glick.
In March, Glick appeared before the state’s House energy committee to discuss a study his office conducted on alternative energy pathways for the state. The study, which came out in January 2025, concluded that switching to imported gas power could save residents hundreds of dollars a year on energy costs, or a total of $700 million in net present value compared to sticking with oil.
He was followed at the podium by Matthias Fripp, an electrical engineer who taught at the University of Hawaiʻi at Mānoa for a decade and now conducts energy policy analysis at Energy Innovation, a San Francisco–based think tank that advocates for decarbonization.
“It’s an honor to be here — it’s my first time speaking in front of a legislature, so I’m a little bit nervous, but thank you for having me,” said Fripp, sporting dark-frame glasses and an aloha shirt adorned with green leaves and orange flowers.
Fripp had pored over the spreadsheets the Energy Office had shared with him, and in doing so, he told the committee, he had uncovered a series of errors that collectively inflated the supposed benefits of LNG by $1.2 billion. Most glaringly, a spreadsheet formula left out the fuel cost of LNG in comparison to fuel oil, such that the projected benefits would only accrue if Hawaiʻi miraculously got LNG delivered for free. Removing those errors, Fripp said, reversed the administration’s top-line finding: Instead of saving money, LNG would actually cost consumers around $300 million.
Rep. Nicole Lowen (D), the committee chair, pressed Glick to acknowledge these errors. He initially called out “the way that this is transpiring,” adding that “we received no ability to even look and understand what the differences are, because we’re being delivered this in real time.”
Fripp then testified that he had emailed Glick’s team about the errors some three weeks prior, and never heard a response. Glick challenged that assessment, but under subsequent questioning, his colleague Monique Zanfes confirmed receipt of the email in question and acknowledged that the team had not followed up on it.
The next day, March 13, the Energy Office posted a defensive Instagram message calling Fripp’s assertions “INCORRECT” and stating “HSEO unequivocally stands by its work on the study.” Six days later, the office officially acknowledged an “unintentional algebraic syntax error” and retracted the scenario that had shown the greatest net benefits, to the tune of $700 million.
The Green administration and the Hawaiʻi State Energy Office continued to push for natural gas despite the collapse of their official case.
Within days of the committee hearing, administration officials coordinated the release of a sleek slide deck laying out JERA’s project proposal. Emails obtained by the environmental groups Earthjustice and Life of the Land through public records requests show that throughout that time, the governor’s office and the Energy Office collaborated on a media campaign to promote the LNG proposal with iQ 360, a public relations firm contracted by JERA.
One email chain from March 16 shows state press officers working alongside a rep from iQ 360 to craft responses to questions from a journalist with Bloomberg News.
“I think we do need to add something to the effect that this program aligns with our 2045 aspirations. Both Mark and Erik spoke to it tonight and national story must carry this aspiration,” wrote the Energy Office’s Strategy and Marketing Officer Yvonne Hunter, referring to an event in which Glick appeared alongside JERA Americas Vice President of Development Erik Montague.
Life of the Land, founded in 1970, regularly intervenes in regulatory proceedings involving new energy projects. Executive Director Henry Curtis said that with the JERA LNG project, the Energy Office has stepped well outside its usual role.
“We’ve never seen the State Energy Office handpick a specific technology and a specific company and throw their weight behind it,” he told Hawaiʻi Public Radio.
The Energy Office has since revised its non-retracted scenarios, which currently show more substantial benefits from LNG. In the scenario the state is leaning on now, net present values jumped from $150 million to $651 million in the republished study.
While that may sound impressive, experts at Hawaiʻi Natural Energy Institute, the state’s primary academic body researching and modeling the energy transition, say those savings are negligible. HNEI Director Rick Rocheleau said that after spreading $651 million out over the proposed 15-year timeline for burning gas and then breaking it down by the energy Hawaiian Electric sells, it boils down to less than a penny per kilowatt-hour in savings.
“We would effectively be breaking even,” Rocheleau said.
JERA has run its own calculations on what LNG could save customers and produced a figure higher than that in the Energy Office’s study: It claims that by burning gas instead of oil, it can lower energy costs by 20% and provide Oʻahu households with an average of $500 off their bills each year.
Rocheleau called those numbers a “mirage.” He said that JERA is calculating its savings per meter, not per household, and neglected to distinguish between commercial and residential meters. Large commercial customers will see higher savings, whereas residents would get a much lower return — closer to 2 cents per kilowatt-hour, or 5% of the average customer’s bill, according to Rocheleau’s calculations based on JERA’s assumptions.
“To put it in perspective, total fuel cost is only about 20% of our electricity costs now, so LNG and the infrastructure would have to be free for us to save 20%,” Rocheleau said.
Even if the case for savings was airtight, the JERA proposal makes other questionable assumptions. It has little margin for error in its projected timeline, especially if the LNG facilities will indeed comply with the 2045 clean energy deadline, as Green insists is the case.
JERA is offering to front roughly $2 billion to build the gas infrastructure, and plans to profit from this investment by charging Oʻahu residents for the gas-fired electricity. JERA hopes to have its LNG terminal and power plant fully constructed in 2030, an extremely optimistic timeline that would still allow only 15 years to make money burning gas before that becomes illegal.
But gas power plants are hefty investments, so developers or utilities typically run them for decades to recoup what they spent; JERA’s calculation for the supposed household savings assumes a 40-year power plant operating life, which would stretch into the 2070s.
“Once you build the infrastructure, unless you’re going to keep it for a very long time, anything you do to amortize it quickly is going to drive up the cost,” said Jay Griffin, who chaired the state utility regulatory commission from 2019 to 2022. “If you’re really intent on saying ‘We’ll only do this for 15 years,’ now it’s a 15-year mortgage on a $2 billion loan, versus 30 or 50 years.”
To hit that 2030 target date for commercial operations, JERA would have to make quick work of permitting this complex and multifaceted project, and shepherd the controversial plan swiftly through approvals at the Public Utilities Commission.
“That alone can take years because the PUC takes its job very seriously. These are very technical issues,” said Isaac Moriwake, the environmental attorney who leads Earthjustice’s Mid-Pacific Office.
Navigating PUC approval will also require some degree of buy-in from Hawaiian Electric, the electric monopoly that actually runs the Oʻahu grid. JERA needs the utility to either solicit bids for the project or request a waiver from the competitive bidding process on JERA’s behalf. Thus far, the utility has played no formal role in JERA’s proposal, and one of its press statements about LNG exuded a rare degree of saltiness for the typically bland genre of utility communications, noting how the state has zigzagged in its approach to LNG over the past quarter century. Hawaiian Electric confirmed to Canary Media and Hawai’i Public Radio that it has not formed a partnership with JERA.
Even after the PUC rules on the proposal, community members have a right to appeal up to the state Supreme Court, an eventuality Moriwake said was “almost guaranteed.”
And even if the project wins all the necessary approvals and deflects legal incursions, it still wouldn’t be out of the woods.
“We have an extensive track record of projects going over budget and taking too long,” Griffin said of construction efforts in Hawaiʻi. “After all the infrastructure, the build, and any delays, who’s going to guarantee those savings?”
JERA’s Montague acknowledged in an email that 2030 completion would be “an aggressive timeline,” but added that “we fully believe it can be accomplished.” The company’s slide deck stressed that it still expects savings for customers if the project is delayed by three years or its cost grows by 20%.
Crucially, though, its expected savings depend on “assuming thermal plants switch to renewable fuel at 2045.” JERA asserts that the power plant’s turbines could burn renewable natural gas, clean hydrogen, or clean ammonia with limited upgrades to comply with the clean energy law.
When asked to name power plants burning green hydrogen, Montague said that JERA upgraded a turbine in New Jersey to be capable of burning a 40% blend of hydrogen with natural gas, and noted that GE Vernova sells turbines it says can handle a 100% hydrogen fuel.
Testing is one thing, but power plants have not yet adopted hydrogen as a sole fuel for regular operations. Staking Oʻahu’s grid on clean fuels entails betting on specialized generator equipment not yet in widespread production and an uninterrupted supply of fuels that remain niche and expensive.
Renewable natural gas does exist — it can be siphoned off landfills and manure ponds so it doesn’t hit the atmosphere as unabated methane. But the Energy Office study, for instance, made clear that “RNG is not scalable or widely available enough to meet Hawai‘i’s energy demands.”
Should Oʻahu find itself in a position where the LNG plant eventually gets approved, but comes online years late due to the predictable community challenges or construction delays, or both, and then cannot actually deliver a quick and easy switch to burning hypothetical clean fuels by 2045, JERA would have to make its money back in that compressed timeframe, with the captive customers on Oʻahu footing the bill.
“This project’s a loser, and for it to make any kind of sense, they’re going to have to sprinkle some fairy dust on it,” Moriwake said. “If you sign up for this long-term fossil-fuel commitment, you’re going to be pushing back cleaner and cheaper renewable resources and forfeiting our clean energy and climate goals.”
JERA and the Green administration counter those unresolved questions with a sense of urgency. They paint a binary picture: the expensive, polluting, oil-burning status quo versus a cheaper, cleaner future powered by natural gas. On April 16, the 48th day of the Iran war, Green told listeners of Hawaiʻi Public Radio that the state’s dependence on oil had to change.
“Right now, the idea of continuing to rely on oil from places like Libya or worry about what happens in the Middle East when you have a war with Iran, it’s just insanity,” Green said. “And I’m just not going to be a governor that sits on my butt and doesn’t do something when I can try to make things more affordable.”
Of course, Iran’s blockade of the Strait of Hormuz didn’t just stop oil flows; it cut off shipping access for about one-fifth of global LNG supply, too. Iranian missiles damaged Qatar’s primary gas facility so badly it will take years to repair, creating a long-term constraint on gas markets in Europe and Asia.
Even if Green wasn’t pursuing gas import dependence at a historically volatile time for the commodity, his oil-versus-gas dichotomy overlooks another option: solar.
Clean energy advocates argue that the state should instead fast-track investment in solar and batteries to drastically reduce Oʻahu’s need for imported fuel. If anyone wanted to see receipts from a natural experiment that tested this exact strategy, all they’d have to do is hop on a 40-minute flight from Honolulu to Līhuʻe, Kauaʻi.
Neighboring Kauaʻi is the only island in the state served by an electric utility outside of Hawaiian Electric’s purview. Member-owned Kauaʻi Island Utility Cooperative (KIUC) built enough solar and batteries that it routinely runs solely on renewable power for portions of sunny days. Its leaders aren’t worried about hitting the 2045 deadline — they expect to entirely forgo fossil fuels by 2033, 12 years ahead of schedule.
When KIUC formed in 2002, electricity rates on Kauaʻi were 70% higher than on Oʻahu, according to KIUC president and CEO David Bissell. Today, the island has the lowest rates statewide, and Bissell said customers are far more insulated from the vagaries of the oil market.
Solar investments have been key to KIUC’s success. One-fifth of KIUC’s members have rooftop solar on their homes. Utility-scale solar currently accounts for roughly a quarter of Kauaʻi’s annual generation. Two recently approved solar and battery farms will bring that up to around 60%, each providing electricity at a rate of about 15 cents per kilowatt-hour, a steep discount compared to oil-fired generation.
These projects, together with KIUC’s other renewable facilities, will help Kauaʻi avoid more than 300 million gallons of fossil fuel use over the next 25 years.
“It’s helped our greenhouse gas emissions get radically reduced, and it uses Kauaʻi’s abundant resources to produce energy and benefit the island,” Bissell told state lawmakers in April.
Oʻahu has a much higher energy demand and more land constraints than Kauaʻi, but some experts say the island can overcome those hurdles. In that same April meeting, Fripp appeared alongside Michael Roberts, an economist and fellow at the University of Hawaiʻi Economic Research Organization, to discuss how Oʻahu might achieve comparable results to Kauaʻi.
Roberts and a Ph.D. student updated a model originally designed by Fripp and ran more than 100 scenarios comparing energy project and fuel costs to determine the most affordable path forward for Oʻahu utility customers. This analysis concluded that investments in solar, not natural gas, presented Oʻahu’s best bet at mitigating electricity costs. In late June, Roberts published a report on the Economic Research Organization’s website that built on the initial analysis.
That case for solar became muddied on July 7, when Roberts withdrew his study, noting errors made in the rush to publish, including one in a correction that relied on data points hallucinated by an AI assistant.
Roberts is conducting an internal audit of the report, which he plans to reissue soon. So far, his top-line takeaway stands: “Building no new fossil-fuel plant remains the least-cost path for Oʻahu in every corrected case,” he said in a statement.
Gov. Green, in an emailed statement, commended the Economic Research Organization for recognizing the “flaws and bias” in the research. “The faulty study and analysis, deeply compromised by vested interests, threatens to set back our collective opportunity to build a sane bridge to a fully renewable future.”
Prior to the retraction, the Energy Office had contested Roberts’ expectation that solar will maintain its cost advantage over other sources. The Energy Office had pointed out that Hawaiian Electric recently submitted power purchase agreements to the Public Utilities Commission for two new Oʻahu solar and battery farms, Puʻuloa Solar and Mahi Solar, at price points of about 21 cents and 23 cents per kilowatt-hour, respectively.
That’s double what grid-scale solar has cost in Hawaiʻi in the past. In the contract document, Mahi Solar developer Longroad Energy noted concerns about Hawaiian Electric’s tenuous financial position since the Maui fires and the rollback of federal incentives for solar projects. That price jump, though, is anomalous in the broader trend of solar costs, which have a long track record of declining over time, while the cost to build gas power plants has been rising amid roiling demand.
Griffin, who as a regulator sparred with Hawaiian Electric to pick up the pace of clean energy to avoid surging oil costs when the state’s last coal plant closed, maintains that much of the delay in Hawaiʻi’s renewables buildout “is self-inflicted.”
“Can we do things better here? One hundred percent,” he said. “Do we have more potential to improve the clean energy pathway? Absolutely.”
Amid these conflicting reports on Oʻahu’s energy pathways, state lawmakers have called on the Public Utilities Commission to step in. Lee, in the state Senate, and Lowen, in the House, introduced resolutions that their respective chambers approved requesting that the commission conduct its own analysis on how to cut costs for residents.
The commission has until the end of the year to return its preliminary findings to lawmakers. In the meantime, Lee said the state shouldn’t tether itself to yet another imported fossil fuel.
“Unless somebody can guarantee the price of an imported fuel at a rate that is far lower, or at least comparable to investing in local renewables, … then I don’t see how the math maths,” Lee said.
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.
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