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A new policy in China could ramp up the nation’s production of green hydrogen for use in airplanes, ships, and other heavy industries, potentially eclipsing output of the fuel in the United States and Europe.
Earlier this month, the National Development and Reform Commission — the high-ranking executive department in charge of economic planning — released what analyst Jian Wu called China’s single “most important low-carbon policy for 2025.”
Until now, China has encouraged provincial governments and state-owned companies to develop hydrogen technology by providing lower electricity prices and loans and by setting production quotas. But unlike the United States and the European Union, the national government in Beijing had no overarching policy to directly subsidize low-carbon hydrogen projects.
While the document published on Oct. 15 does not specify hydrogen by name, the policy change makes Chinese industries that depend on the clean fuel eligible for direct grants.
For the first time ever, the rules outlining which types of industrial projects qualify for national grants list green methanol, carbon capture, sustainable aviation fuel, and zero-carbon industry parks — “paving the way for rapid development of these applications in China,” Wu wrote in his China Hydrogen Bulletin newsletter. Of the hundreds of clean-energy directives China issues at its various levels of government each year, Wu emphasized, the latest policy is “absolutely” the most significant, particularly for heavy industry.
By designating those sectors for direct grants under Beijing’s central budget, “the government is effectively establishing its first national funding mechanism for some of these hydrogen-adjacent technologies,” said Amy Ouyang, a hydrogen associate at the Clean Air Task Force, a Boston-based environmental group.
“China’s hydrogen sector has relied heavily on private capital, so this guidance marks a potential shift toward a more coordinated, state-backed effort to turn policy ambition into on-the-ground deployment,” she said, adding that “the inclusion of these adjacent technologies could reinforce its growing role in China’s broader industrial decarbonization strategy.”
The move comes as the United States turns away from its nascent efforts to develop a clean-hydrogen industry. The landmark 45V federal tax credits meant to spur production and use of clean hydrogen, once slated to last until 2033, are now set to phase out in two years as a result of President Donald Trump’s One Big Beautiful Bill Act. The Trump administration, meanwhile, is poised to use funding meant for hydrogen-based steel projects to bolster production of steel made with fossil fuels instead.
China is already the world’s largest hydrogen market, by far. At about 33 million metric tons of demand per year, the industry is roughly three times the size of the American market. In the United States, 95% of hydrogen is produced with natural gas, primarily through a process that involves using steam heated to temperatures as high as 1,832 degrees Fahrenheit to separate the molecule out of methane. America’s reliance on natural gas is no surprise, given that it has vast reserves and the world’s largest drilling industry.
By contrast, China imports much of its natural gas, so the fuel is used to generate 25% of the country’s hydrogen. A significant share of China’s hydrogen is a byproduct of other industrial processes, such as heating coal to make purified “coke” for steel mills.
Since a portion of that byproduct hydrogen is vented into the atmosphere as waste, the new national grants could include projects that capture and repurpose more of that gas. But China’s world-leading deployments of solar, wind, hydro, and nuclear power plants also generate an ample supply of clean electricity to produce green hydrogen — the version of the fuel made by blasting distilled water with enough electricity to separate hydrogen molecules from the oxygen ones. Already, in July, China agreed to sell a historic debut shipment of green steel made with hydrogen to buyers in Italy.
Despite China’s clean-energy advantage, the U.S. and European Union had, until now, boasted stronger national policies for developing domestic green hydrogen.
While China’s government-owned businesses invested in green hydrogen, “there was nothing at the national level,” like the 45V tax credits in America’s Inflation Reduction Act or the European hydrogen bank, said Anne-Sophie Corbeau, a hydrogen researcher at Columbia University’s Center on Global Energy Policy.
For example, Beijing backed fuel-cell vehicles, but the support came primarily as a reward for reaching manufacturing targets, not as direct subsidies, she said. The central government might give an annual reward of 1.6 billion yuan ($225 million) per city based on progress toward certain deployments of fuel-cell infrastructure, but “if you are underperforming, you may get nothing,” Corbeau said.
“Broadly, that means no state support for industrial applications like what we may have seen in other countries,” she said.
This month’s policy shift will direct Beijing’s funding hose at heavy industries that transition from coal and gas to hydrogen, including “power, steel, nonferrous metals, building materials, petrochemicals, chemicals, and machinery,” said Xinyi Shen, the China team lead at the Centre for Research on Energy and Clean Air, a Finnish research nonprofit.
“This policy sends a strong signal of China’s commitment to accelerating its green transition,” she said. “Given China’s current clean-energy momentum and industrial policy direction, the country may ultimately achieve deeper [emissions] cuts than it has formally committed to.”
Still, Shen warned, “green hydrogen remains costly.” But China’s capacity to swiftly scale industries that the government makes a priority has a history of sending prices plunging, as happened with solar panels and batteries. And China’s hydrogen sector “is expanding rapidly,” Ouyang said.
Between 2021 and 2023, she said, roughly 100 to 200 new hydrogen-related companies launched each year in the country. Today, China dominates manufacturing of the most popular type of electrolyzer, the machine used to make green hydrogen, representing roughly 60% of the global market. Thanks to that scale, a Western company buying a Chinese-made electrolyzer would pay one-third the price of a locally made counterpart.
If central government funding accelerates in the next year or two as expected, “China could solidify its leadership in the industry and achieve some of the world’s lowest-cost green hydrogen,” Ouyang said.
That could put the U.S. and Europe at risk of lagging behind China, just as they have with other steps in the clean-energy supply chain, experts say.
Corbeau said the conditions are already there for China to dominate the industry. Once the federal tax credits expire, she said, “nothing much will happen” beyond “a few projects” in America.
She noted that in Europe earlier this year, the regional hydrogen bank’s second offering of a public subsidy for hydrogen tried to limit funding for projects that had too many Chinese components. But “the scheme does not give much money, and some projects told me they are better off with Chinese technology because of the cost advantage,” Corbeau said.
“It’s almost too late already,” she added.
Eavor, an advanced-geothermal startup, says it has significantly reduced drilling times and improved technologies at its nearly online project in Germany — milestones that should help it drive down the costs of harnessing clean energy from the ground.
On Tuesday, the Canadian company released results from two years of drilling activity at its flagship operation in Geretsried, Germany, giving Canary Media an exclusive early look. Eavor said the data validates its initial efforts to deploy novel “closed-loop” geothermal systems in hotter and deeper locations than conventional projects can access.
“Much like wind and solar have come down the cost curve, much like unconventional shale [oil and gas] have come down the cost curve, we now have a technical proof-point that we’ve done that in Europe,” Jeanine Vany, a cofounder and executive vice president of corporate affairs at Eavor, said from the Geothermal Rising conference in Reno, Nevada.
Eavor is part of a fast-growing effort to expand geothermal energy projects beyond traditional hot spots like California’s Salton Sea region or Iceland’s lava fields. The company and other firms — including Fervo Energy, Sage Geosystems, and XGS Energy — are adapting tools and techniques from the oil and gas industry to be able to withstand the harsh conditions found deep underground.
The industry wants to produce abundant amounts of clean electricity and heat virtually anywhere in the world, and it could serve as an ideal, around-the-clock pairing to solar and wind power. But geothermal companies are only just starting to put their novel technologies to the test.
Eavor began drilling in Geretsried in July 2023, shortly after winning a $107 million grant from the European Union’s Innovation Fund. For its first “loop,” the company drilled two vertical wells reaching nearly 2.8 miles below the surface, then created a dozen horizontal wells — like tines of a fork — that each stretch 1.8 miles long. Once in place, the wells are connected underground and sealed off so that they operate like radiators: As water circulates within the system, it collects heat from the rocks and brings it to the surface.
Operations on the first of four loops are nearly complete, and the startup plans begin construction on its second loop in March 2026. All told, the system will supply 8.2 megawatts of electricity to the regional grid and 64 MW of district heating to nearby towns, operating flexibly to provide more heat during chilly winter months and produce more electricity in summer.
In its new paper, Eavor said it encountered significant challenges in drilling its first eight of twelve lateral wells, which took over 100 days to complete — a major expense in an industry where drilling rigs can cost about $100,000 a day to run. But the company said it improved its techniques and adapted its equipment in ways that reduced the drilling time for the remaining four wells by 50%.
For example, Eavor said it successfully deployed an insulated drill pipe technology, which can actively cool drilling tools even as they encounter increasingly hotter conditions underground and helps to increase drilling speed. The adjustments also enabled Eavor to triple the length of time its drill bit could run before wearing out, further reducing downtime during the operation.
On top of cutting drilling time and costs, these improvements should also pave a path to boosting Eavor’s thermal-energy output per loop by about 35%, Vany said.
The Germany project will be the first commercial system of its kind when it starts producing power later this year. But other next-generation approaches — like the enhanced geothermal systems that Fervo is building in Utah and operating in Nevada — are also scaling up.
Enhanced geothermal involves fracturing rocks and pumping down liquids to create artificial reservoirs. The hot rocks directly heat the liquids, which return to the surface to make steam. This approach is relatively more efficient at extracting heat from the ground, but it can also raise the risk of inducing earthquakes or affecting groundwater — though experts say that’s unlikely to happen in well-managed projects. In places that ban fracking, like Germany, closed-loop systems can still move forward.
But the closed-loop design has trade-offs of its own, said Jeff Tester, a professor of sustainable energy systems at Cornell University and the principal scientist for Cornell’s Earth Source Heat project. Namely, the pipes can limit the transfer of heat from the underground rocks to the fluids inside the pipe, which in turn limits how much energy a system can produce.
“While companies developing closed-loop systems can make them work, the main challenge they face is for fluid temperatures and flow rates to be high enough to pay off economically,” Tester said. “You can get energy out of the ground; it’s just, how much can you sustainably and affordably produce from a single closed-loop well connection?”
Vany said that Eavor’s modeling shows its technology is already in line with the “levelized cost of heat” in Europe, which estimates the average cost of providing a unit of heat over the lifetime of the project. That figure can fluctuate between $50 and $100 per megawatt-hour thermal in the region’s volatile energy market, she said.
“After we’ve drilled those first four loops, we will be at the bottom of the learning curve,” Vany added. “And that’s the purpose of the Geretsried project.”
In the early 2000s, the owners of the Mammoth Pacific geothermal station proposed expanding the plant into an area just east of California’s Yosemite National Park. The project boasted on its website in 2004 that the potential new wells, which would be located in one of the state’s richest heat resources, had been “carefully chosen to reduce or avoid potential environmental impacts.”
By 2009, the company had produced a study on how the development could impact plant life. The power station had been running since the 1980s, so the decades of data on its safe operation seemed to bode well for a swift approval at a moment when, much like today, rising electricity demand and concern over climate change were converging to bolster development of carbon-free power. The prospects looked so good that, in 2010, geothermal giant Ormat Technologies bought the company that owned Mammoth. In 2013 — a decade after the expansion was first conceived — federal regulators gave the project the green light.
Yet that was just the start of Mammoth Pacific’s permitting saga.
An environmental group and local opponents quickly accused regulators of failing to properly consider how the geothermal project could release organic gases into the atmosphere and groundwater, and filed a lawsuit under the California Environmental Quality Act. The litigation took years to resolve. By the time Ormat finally completed the expansion in 2022, the so-called Casa Diablo IV project had been in the works for nearly two decades.
“People in the industry know it took 17 years to expand an existing facility,” said Joel Edwards, the cofounder and chief technology officer at the geothermal startup Zanskar. “And that’s the last facility that’s been built in California.”
Building a new geothermal plant from scratch on an undeveloped site, he said, would presumably “be an even bigger lift.”
A bill that California lawmakers passed almost unanimously last month promised to change that calculus for the geothermal industry. AB 527 would have provided geothermal developers with categorical exemptions to CEQA reviews, clearing the way for companies to carry out the most expensive part of the process — drilling wells to identify viable hot-rock resources — without the costly burden of lawsuits and ecological assessments the state’s landmark environmental law imposes. A companion bill, known as AB 531, gives geothermal energy projects the same special “environmental leadership” status as solar, wind, energy storage, and hydrogen facilities.
But, in a move that has mystified the industry, Gov. Gavin Newsom (D) vetoed AB 527. In his letter explaining the rejection, Newsom said the legislation would have required state regulators to “substantially increase fees on geothermal operators to implement the new requirements imposed by the bill.”
Of more than half a dozen industry executives and analysts that Canary Media spoke to, however, none believed that argument.
“Something doesn’t add up,” said Samuel Roland, a research fellow at the Foundation for American Innovation who has tracked the bill. “It was a political play for him.” The foundation is a right-leaning think tank that advocates for speeding up energy deployments.
While Roland said it’s difficult to determine exactly which groups may have persuaded the governor to block the legislation, “the only people who were objecting were environmentalists,” a dynamic that echoes the fight against Mammoth Pacific’s expansion.
“It does seem like it was a giveaway to environmental groups,” Roland said.
Izzy Gardon, a spokesperson for Newsom, declined to comment. “The Governor’s veto message speaks for itself,” he wrote in an email to Canary Media.
California’s unique geology has made it the destination for the geothermal industry for decades. The Western Hemisphere’s first commercial geothermal power station opened in California in 1960. That plant — The Geysers geothermal complex, located in a valley of the Mayacamas Mountains north of the San Francisco Bay Area — remains the world’s largest electrical station powered by the planet’s heat.
The state has enormous untapped potential — and a growing need for electricity. California has shut down all but one of its nuclear power plants over the past few decades. In recent years, persistent drought has made the state’s hydroelectric stations less dependable. Solar generation has soared, and a growing fleet of batteries has helped steady the supply when sun-soaked days threaten to overwhelm the grid with electrons and dark nights send panels’ production plummeting. But the state remains reliant on natural gas and power imports from neighboring states to meet surging demand. To achieve its carbon-cutting goals and bring down electricity rates that are more than double that of nearby states, California needs to increase its supply of clean, firm generation.
Burning biomass, such as dry wood cleared from California’s forests to help prevent wildfires, could provide one option — but that still generates carbon dioxide, and the demand for wood might encourage logging of healthy trees. Despite the state’s reversal of its plan to shut down Diablo Canyon, its final atomic station, building new nuclear reactors is still banned in California. Hydropower is dogged by water scarcity. That makes geothermal a particularly attractive choice.
It’s not without some drawbacks. Conventional geothermal, which involves drilling down into underground reservoirs warmed by volcanic heat, is limited to easily accessible areas and comes with the challenge of maintaining the subterranean water source over time. Next-generation geothermal companies are rapidly advancing drilling techniques that the oil and gas industry perfected in recent years to go deeper and harvest heat from dry, hot rocks, vastly expanding the locations with potential to generate energy. In a seismically active state, that carries some risk since the version of next-generation geothermal that uses hydraulic fracturing, or fracking, technology to drill could trigger earthquakes.
But every energy source comes with challenges, and neighboring states such as Utah, Nevada, and New Mexico are aggressively pursuing next-generation geothermal projects.
In theory, the best place to develop those first-of-a-kind plants would be California, with its energy-affordability woes and status as a major global economy.
“Utah has low prices, and geothermal is still expensive,” said Thomas Hochman, director of infrastructure and energy policy at the Foundation for American Innovation. “If you want to bring geothermal down to cost parity with other technologies, you have to sell it to Californians. As a result, geothermal scaling runs through California.”
For the most part, however, developers are steering clear of the Golden State. Companies such as Fervo Energy, XGS Energy, and Sage Geosystems — three of the biggest next-generation startups — are based in Houston and are pursuing debut projects in Utah, New Mexico, and Texas itself. Zanskar, a developer using modern prospecting methods to tap conventional geothermal resources, is headquartered in Salt Lake City. States such as Arizona, Colorado, Idaho, and Oregon are “really exciting” as potential next areas for development, Edwards said.
“If California ever fixes CEQA,” he added, “it could be huge.”
The regulatory hurdles represent “the only real barrier” to geothermal taking off in the Golden State, said Wilson Ricks, a Princeton University researcher who focuses on geothermal.
“You can find projects pretty much all across the Western states but very few, if any, in California, despite it being the biggest potential market,” Ricks said.
“It’s stark. People are exploring projects in Texas, which has far, far worse-quality resources than the ones in California,” he added. “That’s because of the regulatory environment there. So the fact that regulatory barriers are going to remain in place doesn’t give me a lot of confidence that California’s going to be leaping ahead on geothermal anytime soon.”
In response to emailed questions, Fervo said it maintains leases near the Salton Sea region, an area with vast geothermal potential. But those parcels aren’t currently under development since the state’s permitting regime makes investing in drilling too risky.
“With the right legislative and permitting reforms, similar to those that were proposed in AB 527, the state could better position in-state resources for development and unlock the enormous economic benefits that come with local clean energy development,” said Sarah Harper, Fervo’s senior policy and regulatory affairs associate.
Not everyone is so bearish. Ormat, the nation’s largest geothermal operator of conventional sites, said the fact that the vetoed bill passed in the Legislature without a single no vote, just a handful of abstentions, shows there’s political support for geothermal “like we haven’t seen in the past.”
“It’s like a revolution for geothermal,” said Marisol Collons, Ormat’s manager of communications and government affairs. “We’re still highly optimistic about the future and ready to kickstart all our next legislative sessions across the country.”
While Fervo lamented that a small number of green groups fought the bill, the company said the fact that there were “more environmental groups in favor than there were ones opposed, or even neutral,” left it feeling hopeful about the possibility of future legislation.
For XGS, a next-generation company whose technology forgoes fracking and minimizes its water usage by keeping the fluid for its operations contained in a closed tube, California remains “the highest-priority market.”
“We feel that California provides a unique combination from both a resource perspective and a market perspective,” said Lucy Darago, chief commercial officer at XGS. “It’s a high-demand market that really needs the attributes that geothermal brings.”
The company backed the bill and said categorical exemptions from CEQA permitting for drilling would have shaved anywhere from six months to two years off its development efforts.
“It’s disappointing, but I’m optimistic that a future iteration of the bill will pass,” Darago said.
The key, she said, is time. Geothermal will grow in California no matter what — of that, Darago said, she’s certain. The question is whether that happens in time to stave off blackouts and slash emissions on the trajectory the state has set for its electrical system.
“The industry is going to happen. It will get there,” she said. “But if it’s going to get there on a timeline that’s meaningful for California’s resource-adequacy challenges and climate goals, we’ll need some of these changes.”
When Connecticut Gov. Ned Lamont, a Democrat, first nominated Marissa Gillett to the Public Utilities Regulatory Authority in 2019, he praised the “outsider’s perspective” she would bring to the state’s energy challenges. This September, just months after a bruising reconfirmation process, she stepped down, citing a tangle of acrimonious disputes with investor-owned utilities and lawmakers who bristled at her novel approach to regulation and accused her of inappropriate, even unlawful, bias.
Public utility commissions are essential but largely invisible forces regulating and shaping electricity, gas, and water services at the state level. Traditionally, these boards have been thought of as working in tandem with utilities, rarely challenging their proposals and claims. Recently, though, the tides have shifted, as more states and advocacy groups look at ways for commissioners to advance state energy policy.
The need for decisive action from utility commissions is becoming more acute as electricity prices climb almost everywhere in the country and many states push to meet decarbonization goals. The regulatory status quo just doesn’t lend itself to the systemic changes needed to fight these battles.
Gillett has been hailed by some as an exemplar of the assertive regulator, bringing a decidedly proactive sensibility to her work on the Connecticut commission, commonly called PURA. Following her resignation from the board, Gillett sat down for a conversation with Canary Media about what that involved regulation should look like as states face down a crucial moment for consumers and climate alike.
“Regulators need to roll up their sleeves and figure out how to provide continuous, sustained rigorous oversight,” she said.
The traditional model for investor-owned utilities guarantees them a set rate of return on every dollar spent building new distribution lines, upgrading substations, and other such projects. This dynamic has led to criticism that utilities are prone to overspending on infrastructure that might not be in the interest of customers or the environment, for the simple reason that it will bolster their earnings and please their investors.
A key job of leaders like Gillett is to weigh these utility requests against the need for adequate, reliable infrastructure, and the needs of consumers and the state’s energy policy goals. But for too long, critics say, commissioners have functioned more as umpires calling balls and the occasional strike, approving most utility requests.
Before coming to Connecticut, Gillett worked for seven years at the Maryland Public Service Commission, contributing to the development of initiatives including the state’s electric vehicle programs and its offshore wind plan. After a brief stint with the Energy Storage Association, a trade group, she threw her hat in the ring for the Connecticut commissioner position.
Gillett came into the job ready to be the “change agent” the governor said he wanted. Her aim was to reform an entrenched system that had led to some of the country’s highest electricity rates and mixed progress on climate goals — and to move away from the “balls and strikes” mentality that she found unrealistic and limiting.
“I acknowledge you have to make decisions based on the evidence and record in front of you,” she said.
But she was not willing to accept that the only evidence available was what was contained in utility filings and the responses to them. She offered this analogy: If one party came before PURA saying the sky was green, and another argued it was purple, the board should not be forced to choose between those two options.
To dig deeper into the issues before the commission, she assembled a staff of 80 “who are the best in the business and are very passionate about the work,” a group she hopes stays in place despite her departure.
“It is important who sits in the commissioners’ seats, but it’s also important who staffs them,” she said.
Right from the beginning, she and her staff led PURA in several controversial decisions that left utilities and Republican lawmakers claiming she was creating a hostile and uncertain environment for the state’s two major investor-owned utilities — Eversource and United Illuminating — and their shareholders.
After the utilities struggled to restore power following Tropical Storm Isaias in 2020, PURA ordered Eversource to return $28.4 million to customers in the form of bill credits. In 2023, the commission reduced United Illuminating’s requested $123 million rate increase by $100 million. The utility challenged this move in court, but PURA’s decision was upheld.
Gillett argues she always just applied rules that were on the books but rarely enforced. She points to her track record in court cases: Five times utility challenges have made it to the Connecticut Supreme Court, and five times the court supported PURA’s rulings, she said.
“For years we heard in public that I was acting illegally, making decisions that were arbitrary and capricious,” she said. “I was now holding them to standards they had not been held to. I viewed myself as somebody tasked with implementing state policy.”
While the financial penalties and rate reductions Gillett’s PURA imposed garnered headlines, she also made changes that were less widely noticed, with the goal of prepping the grid to handle more renewable energy. Within Gillett’s first year, the board launched the Equitable Modern Grid initiative, a series of investigations into 11 topics, including advanced metering, energy storage, and affordability. The process yielded ongoing action, including a battery incentive for homeowners and businesses and a program to fund pilots trying out innovative grid technologies.
“Considering how slowly regulatory processes usually work, I think designing and launching those programs in that amount of time was very impactful,” Gillett said.
It’s difficult to assess the effect of Gillett’s philosophy on Connecticut’s energy and climate landscape quite yet: Changes to the utility industry are notoriously slow-moving, and the pandemic added an extra level of disruption to her tenure.
Electricity prices remain high there, as they are throughout the entire Northeast, but Gillett leaves behind programs intended to reduce the energy burden on low-income households. During her tenure, the state implemented its first discount electricity rate for such families and launched an outreach program to help disadvantaged households access assistance offerings.
Gillett does not yet have her next move mapped out, but she does have a degree of optimism that utility regulation is evolving toward the sort of goal-driven, engaged model she brought to her time in Connecticut.
More states are already taking seriously the need to seek out “competent, qualified” regulators with a background relevant to the work, she said. She pointed to a Brown University study that found, nationwide, the share of commissioners with previous work on environmental issues grew to 29% in 2020 from 12% in 2000. States like Maine and Colorado have taken steps to direct their utility regulators to consider emissions, equity, and environmental justice when making decisions.
“As electricity affordability becomes more front-and-center, and folks are looking to who is supposed to be watching out for them, there will be a moment when regulators embrace that philosophy more,” she said.
CEOs of artificial-intelligence companies want to spend hundreds of billions of dollars building their energy-gobbling data centers, but that can’t happen without the necessary electricity supply. And they want to move way faster than electric utilities are used to.
One idea gaining traction is to allow data centers to come online more quickly if they agree to occasionally pull less power from the grid when demand is high, a concept endorsed by none other than Energy Secretary Chris Wright in a rulemaking proposal filed Thursday. The massive computing facilities could accomplish such flexibility with the help of on-site renewables and batteries, but precious few projects using this model have materialized. That’s about to change.
On Wednesday, Aligned Data Centers announced it would pay for a new 31-megawatt/62-megawatt-hour battery alongside a forthcoming data center in the Pacific Northwest. The battery, developed by energy-storage specialist Calibrant Energy in partnership with the local utility, is now entering the construction phase and should be operating sometime next year. The kicker is, this deal will let Aligned get up and running “years earlier than would be possible with traditional utility upgrades,” per the companies.
If the plan works, would-be AI leaders will be jumping all over this battery-first strategy. In fact, many already are, they just haven’t publicly acknowledged it yet.
“There’s so much chatter right now about the potential to use energy storage in this manner to facilitate the connection that large power users want from the grid. But there hadn’t really been evidence of that theory being reality,” said Phil Martin, CEO at Calibrant, which is owned by Macquarie Asset Management. “It is possible, and it is being done — not as a proof of concept in a lab somewhere, but really a commercial project.”
Batteries aren’t, at first glance, a tool well matched to the needs of AI computing.
Lithium-ion chemistries have become quite competitive for short-form activities: First, it was managing second-by-second frequency fluctuations on the grid; now, in places like Australia, California, and Texas, batteries are shifting solar generation to compete with gas plants in the evening when demand rises.
Data centers, though, use energy around the clock — not literally at full blast 24/7, but a lot closer to it than current batteries can keep up with. Data-center developers have chased new gas, hydropower, and an exotic array of nuclear power plants in hopes of feeding the beast. But those options will take several years to come online, if they ever get built. The headlong rush into AI demands nearer-term solutions.
As a lot of exceedingly well-funded firms contemplated this conundrum, some thinkers started focusing on grid flexibility as a way to accelerate the computing-infrastructure buildout. Earlier this year, Duke University researcher Tyler Norris made waves in the AI-energy world with research that found today’s grid could handle quite a lot more data centers if the facilities could simply dial back their consumption for a couple hours at a time during moments of maximum demand.
The Aligned battery offers a concrete example of that kind of research. The utility studied just how big the battery would need to be to compensate for challenges imposed on the local grid by the data center. Aligned and Calibrant had their own calculations, Martin said, “but the validation of that, and the actual specification of that, came out of the interconnection study done on the utility side.”
Due to the local nature of the power constraint, the battery had to be built close to Aligned’s facility; the company ultimately provided the land to host the grid storage installation. In other cases, where a proposed data center runs up against a system-wide capacity constraint, a battery solution could be further away.
Another glimpse of the battery-enabled future came this summer when Redwood Materials, a richly funded battery-recycling startup, unveiled a new business line that repackages old EV batteries to serve data-center demand. The first installation, at Redwood’s campus near Reno, Nevada, fully powered a very small, modular data center using a solar array and a field of former EV battery packs laid out on the desert floor.
Redwood just got its own vote of confidence in that concept: On Thursday, it raised another $350 million from investors including AI-chip leader Nvidia.
Aligned’s commitment to paying for the battery itself could serve as a model of socially responsible AI-infrastructure development.
Some utilities around the country are jumping to build new power plants to support the projected data-center buildout, and charging their regular customers for the investment, hoping the AI titans eventually become paying customers. But this approach risks saddling consumers with unnecessary costs if the AI hubs don’t materialize.
Because Aligned is footing the bill, the utility’s other customers won’t be forced to pay for the data-center firm’s growth ambitions. But, though this one large customer will provide the land and funding, the battery will sit on the utility side of the meter. That means the utility can leverage the tech for other grid uses, like frequency management and capacity, when it’s not maintaining the flow of power to the data center during otherwise scarce hours.
In this case, Martin said, the permitting and buildout could move faster with the battery connecting to the utility grid instead of directly to the data center. In other situations, bigger batteries on the customer side of the meter might make more sense. Calibrant is already working on more and even larger batteries for the AI sector, he added.
“Whereas right now, we think this is unique, I think over a relatively short time horizon it’s going to be much more common,” Martin said. “It’ll start to look surprising if we don’t see projects like this at the largest loads as they connect [to the grid].”
A clarification was made on Oct. 25, 2025: This story originally stated that the local utility studied how many times per year the local grid could run out of electricity if the data center got built. The piece has been updated to clarify that the utility studied how big the battery would need to be to compensate for challenges imposed on the local grid by the data center.
Energy affordability has become a flash point over the past few months. It’s a key issue in this year’s gubernatorial races. It’s something President Donald Trump has promised to fix by boosting fossil-fuel production. And of course, it’s showing up in the bills that arrive in mailboxes every month.
Three-quarters of Americans count electricity costs as a source of stress in their lives, according to a new Associated Press-NORC survey. But a recent study from the Lawrence Berkeley National Laboratory provides more nuance to the conversation. When adjusted for inflation, 31 continental states actually saw their power prices decline from 2019 to 2024, while the other 17 states experienced increases.
One reason why some states saw prices jump? Utility spending on disaster recovery and preparedness. Take California, where utilities have added billions of dollars in wildfire-recovery costs and mitigation programs to retail electricity prices in recent years, the national lab found. It’s a bracing fact as the planet warms and disasters become more frequent and destructive.
But the report also tempered fears that the growth of data centers and other power-hungry industries will jack up electricity prices. Grid maintenance has been a top driver of increased electricity costs over the last few years, but spreading these expenses among more customers — like data centers and manufacturers — has helped lower retail electricity prices, researchers found. One caveat: That dynamic tends to benefit large, commercial consumers more than residential ones.
The Trump administration has elevated fossil fuels as a solution to rising electricity bills, positing that more coal and gas power can cut prices. But building a new gas-fired plant is increasingly expensive and takes years, and the U.S. is preparing to ship more liquefied natural gas out of the country anyway.
If you look at two rare examples of power utilities reducing their rates, it’s clear that falling back on coal isn’t the answer either. In Oregon, Idaho Power Co. has asked regulators to lower electricity prices by nearly 1%, saying the closure of a coal-fired power unit and demolition of another coal plant have brought down costs. And in Virginia, where a state law is pushing the electricity sector to lower emissions, Appalachian Power cited the addition of renewable power in its request to lower rates. West Virginia is meanwhile pushing to keep its coal plants running — a move that Appalachian Power said would raise prices for its electricity customers in that state.
But putting the national lab’s inflation-adjusted numbers aside, it’s clear that rising utility bills are reaching a fever pitch across the country — and it’s going to take both more clean energy and smarter utility regulation to rein them in.
Trump sinks a global shipping-decarbonization plan
Until a few weeks ago, the International Maritime Organization was on track to approve a global shipping-decarbonization strategy. That is, until the Trump administration launched a last-minute offensive and got the United Nations body to delay adoption of the plan, Maria Gallucci and Dan McCarthy reported late last week.
The tens of thousands of shipping vessels that travel the oceans are responsible for about 3% of the world’s annual greenhouse gas emissions. But as Maria points out in her follow-up dive into shipping decarbonization, the industry doesn’t currently have much incentive to replace dirty diesel-powered vessels with lower-carbon alternatives.
Some good news, some bad news for U.S. battery startups
The U.S. Department of Energy slashed another wave of federal funding this week, targeting $700 million in grants for battery and other clean manufacturing projects. Nearly half of that funding had been awarded to Ascend Elements, which had already canceled a portion of its planned battery-recycling facility in Kentucky earlier this year. A smaller portion was going to American Battery Technology Co., which said it will carry on with its lithium mine and refinery project in Nevada.
But it wasn’t a bad week for every battery company. Redwood Materials raised $350 million, which it’ll use to expand its unique energy-storage business that packages together used EV batteries into grid-scale resources that can power data centers and other industrial users. And Pila Energy raised $4 million to keep building batteries that provide backup power to large appliances, but are more affordable and portable than whole-home systems like the Tesla Powerwall.
Losing the reactor race: China has a clear head start on the U.S. when it comes to nuclear power, as China has figured out how to produce reactors cheaply and quickly, while the U.S.’s last project went billions of dollars over budget. (New York Times)
What whales? The Trump administration has repeatedly blamed offshore wind farms for whale deaths but just canceled funding for research meant to protect the marine mammals in an increasingly busy ocean. (Canary Media)
Drill here, drill there, drill everywhere: The Trump administration opens 1.56 million acres of the Arctic National Wildlife Refuge’s coastal plain to new oil and gas leasing, and reportedly plans to open significant swaths of the East and West coasts to offshore drilling as well. (New York Times, Politico)
Testing the grid: Xcel Energy is taking different approaches to building out distributed energy resources depending on the state, installing batteries at local businesses in Minnesota while pursuing a more complicated, legislatively mandated model in Colorado. (Latitude Media)
Battling battery blazes: California passes a new law to strengthen fire-safety standards for grid battery systems after a devastating blaze in Moss Landing earlier this year, though new storage-facility designs have already made similar fires unlikely. (Canary Media)
Flagged and forgotten: The United Nations says governments and oil and gas companies are ignoring nearly 90% of leaks that methane-tracking satellites have detected for them. (Reuters)
A winding road to decarbonization: Rondo Energy’s “heat batteries” could be key to decarbonizing heavy industry, but the company’s first industrial-scale test is at a controversial site: a California oil field. (Canary Media)
If you thought the world built a lot of renewables in the past few years, just wait for the next half of this decade.
Between 2025 and 2030, the world is expected to build nearly 4,600 gigawatts — or 4.6 terawatts, if you please — of clean power, according to a new report from the International Energy Agency.
That’s nearly double the amount built over the previous five-year period, which was in turn more than double the amount built across the five years before that. Put differently, the growth has essentially been exponential.
Solar is the driving force behind this expansion, which is key to transitioning the world away from planet-warming fossil fuels. It accounts for more than three-quarters of the expected increase in renewables between 2025 and 2030 — the result, IEA says, of not only low equipment costs but also solid permitting rules and a broad social acceptance of the tech.
This solar boom will be almost equally split between utility-scale installations and distributed projects, meaning panels atop roofs or shade structures in parking lots, for example. Just over 2 TW of large-scale projects will be built compared to 1.5 TW of the smaller, distributed stuff, IEA predicts. The latter category is increasingly popular both in countries with rising electricity rates and in places with unreliable grids, like Pakistan, where residents are taking refuge in the affordable and stable nature of the tech.
China is installing most of the world’s solar, but the technology is a global phenomenon at this point. At least 29 countries now get over 10% of their electricity from the clean energy source, per a separate report released by think tank Ember earlier this month.
Other types of clean energy are set to grow, too, just not at anything close to solar’s scale.
Installations of onshore wind will leap from 505 GW over the previous five-year period to 732 GW between 2025 and 2030. Offshore wind will more than double from 60 GW to 140 GW. Hydropower will rebound modestly from a down couple of years, but still won’t expand at the levels seen in the early to mid-2010s.
Still, renewables are not gaining enough ground to triple clean capacity by the end of this decade compared with 2023 — a goal countries around the world set two years ago at COP28, the annual United Nations climate conference. In just a few weeks, global leaders will reconvene in Brazil for COP30. The IEA figures, while a sure sign of progress, underscore the steep climb ahead.
The Trump administration has repeatedly blamed offshore wind farms for whale deaths, contrary to scientific evidence. Now the administration is quietly abandoning key research programs meant to protect marine mammals living in an increasingly busy ocean.
The New England Aquarium and the Massachusetts Clean Energy Center, both in Boston, received word from Interior Department officials last month stating that the department was terminating funds for research to help protect whale populations, effective immediately. The cut halted a 14-year-old whale survey program that the aquarium staff had been carrying out from small airplanes piloted over a swath of ocean where three wind farms — Vineyard Wind 1, Sunrise Wind, and Revolution Wind — are now being built.
Federal officials did not publicly announce the cancellation of funds. In a statement to Canary Media, a spokesperson for the New England Aquarium confirmed the clawback, saying that a letter from Interior’s Bureau of Ocean Energy Management dated Sept. 10 had “terminated the remaining funds on a multi-year $1,497,453 grant, which totaled $489,068.”
The aquarium is currently hosting the annual meeting of the North Atlantic Right Whale Consortium, a network of scientists that study one of the many large whale species that reside in New England’s waters. News of the cut to the aquarium’s research project has dampened the mood there. And rumors have been circulating among attendees about rollbacks to an even larger research program, a public-private partnership led by BOEM that tracks whales near wind farm sites from New England to Virginia.
Government emails obtained by Canary Media indicate that BOEM is indeed shutting down the Partnership for an Offshore Wind Energy Regional Observation Network (POWERON). Launched last year, the program expanded on a $5.8 million effort made possible by the Inflation Reduction Act, deploying a network of underwater listening devices along the East Coast “to study the potential impacts of offshore wind facility operations on baleen whales,” referring to the large marine mammals that feed on small krill.
POWERON is a $4.7 million collaboration, still in its infancy, in which wind farm developers pay BOEM to manage the long-term acoustic monitoring for whales that’s required under project permits. One completed wind farm, South Fork Wind, and two in-progress projects, Revolution Wind and Coastal Virginia Offshore Wind, currently rely on POWERON to fulfill their whale-protecting obligations.
With POWERON poised to end, wind developers must quickly find third parties to do the work. Otherwise, they risk being out of compliance with multiple U.S. laws, including the Marine Mammal Protection Act and the Endangered Species Act. Dominion Energy, one of the wind developers participating in POWERON, did not respond to a request for comment.
BOEM officials made no public announcement of POWERON’s cancellation and, according to internal emails, encouraged staffers not to put the news in writing.
“It essentially ended,” said a career employee at the Interior Department who was granted anonymity to speak freely for fear of retribution. The staffer described the government’s multimillion-dollar whale-monitoring partnership as “a body without a pulse.”
The grim news of cuts coincided with the release of some good news. On Tuesday, the North Atlantic Right Whale Consortium published a new population estimate for the North Atlantic right whale, an endangered species pushed to the brink of extinction by 18th-century whaling. After dropping to an all-time low of just 358 whales in 2020, the species, scientists believe, has now grown to 384 individuals.
Concern for the whale’s plight has been weaponized in recent years by anti–offshore wind groups, members of Congress, and even President Donald Trump in an effort to undermine the wind farms in federal court as well as in the court of public opinion.
“If you’re into whales … you don’t want windmills,” said Trump, moments after signing an executive order in January that froze federal permitting and new leasing for offshore wind farms.
This view stands in stark contrast with conclusions made by the federal agency tasked with investigating the causes of recent whale groundings.
A statement posted on the National Oceanic and Atmospheric Administration’s website reads: “At this point, there is no scientific evidence that noise resulting from offshore wind site characterization surveys could potentially cause whale deaths. There are no known links between large whale deaths and ongoing offshore wind activities.”
Climate change has made it difficult for researchers to discern the impacts of wind turbines on whales’ food supply. A government-commissioned report released by the National Academies in 2023 concluded that the impacts of New England’s offshore wind farms on the North Atlantic right whale were hard to distinguish from the effects of a warming world.
For much of the past month, since the aquarium got word of its funding being cut, its researchers have not been able to conduct whale-spotting flights. During this time, construction on Vineyard Wind and Revolution Wind in the southern New England wind energy area plowed forward.
Developers are required to have dedicated observers keeping watch for marine mammals from all construction and survey vessels. But, when it comes to spotting elusive leviathans, nothing quite beats a birds-eye view. The aquarium’s work surveying whales is important for several reasons, according to Erin Meyer-Gutbrod, an assistant professor at the University of South Carolina, who called the clawback “disappointing.”
The project has generated America’s longest-running dataset tracking whale movements near planned and active wind farm areas, she said.
The aquarium’s aerial monitoring dates back to 2011, when the footprints of today’s wind projects were first being sketched out. Historically, North Atlantic right whales were known to feed near southern New England during the winter and spring seasons. In 2022, the aquarium’s dataset allowed researchers to make a remarkable discovery: Unlike in most places on the East Coast, a small number of whales were appearing there year-round. The scientists believe that warmer waters driven by climate change have made the area an “increasingly important habitat” for these whales.
Meyer-Gutbrod said the species’ newly established presence should be a reason for the government to better scrutinize wind farm plans and adapt construction activities.
“Monitoring in and around the lease sites is critical for characterizing right whale distribution. The whales often have seasonal patterns of habitat use, but these patterns are changing. We can’t rely exclusively on historical surveys to guide future offshore development projects,” said Meyer-Gutbrod.
She stressed the importance of continued monitoring to better understand the well-documented hazards to these whales — vessel strikes and rope entanglement from fishing activities — which carry on along the margins of New England’s wind farms. Life-threatening entanglement has been documented in the zone long monitored by aquarium staff. For example, in 2018, aerial researchers were the first to identify that a male right whale, known to scientists as #2310, was caught in fishing rope. A rescue team was unsuccessful at dislodging the rope.
The Interior Department’s cuts come at a time when its own leader is expressing concern for whale populations.
“I’ve got save-the-whale folks saying, ‘Why do you have 192 whale groundings on the beaches of New England?’’” said Interior Secretary Doug Burgum, at an event on Monday hosted by the American Petroleum Institute. He said he was paying attention to people claiming that humpbacks, rights, and other whale species started stranding en masse when “we started building these things,” referring to turbines.
No evidence supports these claims. In fact, Tuesday’s news that the North Atlantic right whale population grew by about 2% from 2023 to 2024 may be the strongest rebuke of Burgum’s statements. That time period coincided with the busiest time for U.S. offshore wind farm construction to date.
Since 2017, the imperiled whale has in fact experienced an annual “unusual mortality event.” Between 10 and 35 whales have shown up dead or seriously injured each year, many displaying injuries consistent with a boat strike. Vineyard Wind 1, America’s first commercial-scale offshore wind farm to get underway, didn’t start at-sea construction until 2022.
Remarkably, there’s been no right whale deaths documented in 2025 — even as five massive wind projects press on with construction in their home range. Heather Pettis, a scientist with the New England Aquarium, attributed this milestone to ongoing “management and conservation efforts,” which include the kind of close monitoring just scuttled by federal cuts.
The aquarium’s spokesperson told Canary Media that its aerial survey team conducted a flight over the southern New England wind energy area on Saturday “using other funding.” It’s unclear how long the program can survive without federal support.
On Monday, an aquarium staffer emailed a group of external scientists, welcoming “any suggestions that you might have for how to continue these surveys.”
From AI to Facebook to Google Maps, the nation’s demand for computing power is growing, with households in the U.S. now averaging a whopping 21 devices — think smartphones, TVs, and thermostats — all connected to the internet.
That was one of many statistics lobbed at North Carolina utility regulators last week as they gathered to grapple with the coming onslaught of data centers, the immense buildings filled with hardware that make our around-the-clock connectivity possible but could strain the state’s electric grid, raise utility bills, and increase pollution.
Over the course of a two-day discussion on how to avoid these downsides, one simple solution came up again and again: Data centers could commit to limiting their electricity consumption slightly for a handful of periods during the year, formalizing the practice of modulating energy use that’s already standard across the industry.
“One of the issues that the commission is particularly interested in is load flexibility,” Karen Kemerait, the commissioner presiding over the technical conference, said to more than one presenter last week, before pressing them on the concept.
In response to Kemerait, experts from Google and other tech giants, along with North Carolina’s predominant utility, Duke Energy, all voiced degrees of support for the notion.
Yet how and whether regulators move to actualize load flexibility remains unclear. The Utilities Commission isn’t required to take action following its Oct. 14 and 15 meeting. And unlike other reforms repeatedly mentioned, such as a special tariff for data centers, the policy doesn’t easily translate to a rate case or other dockets before the panel.
That’s part of why Tyler Norris, a former solar developer and a thought leader on load flexibility who presented last week, hopes it will become a choice for data centers if nothing else.
“At minimum, why not have a voluntary service option that enables a large load to connect faster in exchange for bounded flexibility?” Norris told Canary Media. “In every conversation I’ve been in, I’ve heard no objection to the idea. Obviously, it’s at the discretion of the commission — whether they want to encourage it.”
Data centers aren’t the only new large customers driving ever-growing electricity demand forecasts in North Carolina, which Duke used to justify a massive new fleet of gas plants in its most recent proposed long-term plan. But the centers are the most voracious consumers by far, accounting for over 85% of the energy demand in the economic development pipeline, the utility said last week.
Not all of these facilities in the pipeline will come to fruition: It’s not uncommon for tech companies to request grid connections in multiple locations before deciding where they’ll actually build. But many will materialize, posing thorny issues for the utility and its regulators.
What if Duke can’t build generation quickly enough to serve the energy-hungry centers? Can the company do so while still zeroing out its carbon pollution, as required by state law? How can regulators assure that tech giants, not residential customers, pay for new power plants and associated upgrades to the grid?
Load flexibility could provide an elegant answer to these vexing questions.
The idea is rooted in a counterintuitive reality: Data centers don’t run at maximum tilt 100% of the time — they routinely adjust processing power even as we can post videos to Instagram or EMS responders can transmit lifesaving patient data in the middle of the night.
That’s true for a number of reasons, Norris wrote on his Power and Policy site, including the fact that computer chips could overheat if stretched to their maximum theoretical processing speeds 24/7 and also that data centers plan for redundancy.
“Many facilities are overbuilt to ensure uptime, with servers periodically taken offline for routine maintenance, software upgrades, or hardware replacements,” Norris explained in the August post.
Information on data centers’ exact electricity use is scant, and it appears to vary based on type, but research suggests the facilities’ peak consumption is about 80% of what they could pull from the grid.
Yet utility planners typically assume otherwise, categorizing data centers as “firm loads” that need “firm capacity,” such as an on-demand power plant with an ample supply of fuel, plus an extra reserve margin — in Duke’s case, 22% — in the event of emergency.
In the simplest terms, while Duke might build 122 megawatts of generation to serve a data center that can draw a maximum of 100 megawatts of electricity, the center may never use more than 80 megawatts.
But if prospective data centers were transparent about their electricity-utilization plans and committed to them on paper, utilities could adjust how they anticipate new power capacity — averting the construction of massive amounts of fossil-fuel infrastructure as well as expensive grid improvements.
In September, analytics groups GridLab and Telos Energy published a report finding that Nevada’s biggest utility could delay the need for hundreds of megawatts of new power plants if data centers committed to modest flexibility terms that allow “uptimes” of 99.5%.
Similarly, Norris, a Ph.D. student at Duke University — which has no connection to the utility — is the lead author of a February paper showing that if data centers shaved just 0.5% off their use over the course of the year, 4.1 gigawatts of power capacity in Duke’s territory in the Carolinas could be avoided.
The figure “isn’t everything in terms of their load forecast,” Norris told regulators last week, “but it is arguably a meaningful share.”
While enlisting data centers to curtail their own energy use is still more theory than practice, that’s slowly starting to change. Pacific Gas and Electric in California, for instance, has piloted flexible service agreements that could get data centers online more quickly.
In August, Google announced voluntary flexibility agreements with Indiana Michigan Power and the Tennessee Valley Authority. The following month, the tech giant revealed a similar arrangement with Entergy in Arkansas.
The company vaunted those agreements, along with its plans to self-generate carbon-free electricity, at last week’s meeting. “Google is leaning in,” Rachel Wilson, a representative for the company, told commissioners.
The Data Center Coalition is an alliance of Google, Microsoft, Meta, Amazon, and dozens of other companies that own, operate, or lease data-center capacity. The coalition listed “voluntary demand response and load flexibility” as a recommendation to regulators last week, so long as data centers could get something in return — such as a quicker connection to the grid.
“There has to be some reciprocal value for data centers,” said Lucas Fykes, director of energy policy for the coalition.
Still, the AI race, a lack of transparency about data-center electricity use, and a genuine inability of anyone in this space to predict the future could complicate efforts around load flexibility.
“Not even the most sophisticated data center owner-operators” know what their load will look like in “a rapidly shifting competitive landscape,” Norris wrote in August. “Amid such uncertainty, their preference is generally to maintain maximal optionality.”
Indeed, though Duke expressed openness to load flexibility last week, the company advised caution for the long term.
“Looking at these [load-flexibility agreements] as temporary is important,” said Mike Quinto, the company’s director of planning analytics. “A well-designed voluntary program, that’s great. It’s not something we think should be mandated on a long-term basis.”
And while utilities are well-practiced in demand response for large industrial customers, Public Staff, the state-sanctioned customer advocate, voiced worry last week about scaling the same concept to data centers.
“We haven’t seen these magnitudes trying to interconnect and … potentially drop off the system,” said Dustin Metz, director of the agency’s energy division. “From an academic standpoint, if we can shave off some of those peaks, then that could potentially reduce some of the generation assets that we need to build out,” he said. But enforcement would be essential, and North Carolina is still new to data-center growth. “We’re a little bit of a living lab,” he said.
Utilities tend not to be big fans of rooftop solar, which eats into their revenues by reducing customer reliance on the power grid. A new Ohio lawsuit spotlights the tension between utilities and customers over the clean-energy technology.
The case deals with a monthly charge imposed by the city of Bowling Green’s municipal utility on its few customers with solar panels on their rooftops. Customers who use batteries to store surplus solar power pay even more.
Residents Leatra Harper and Steven Jansto claim the charge, which for them amounts to roughly $56 per month, is an unlawful “tax or penalty.” When combined with the city’s partial payment for power fed back into the grid, it almost doubles the payback period for their $37,000 solar system, the couple said.
The city argues the fee is needed to make sure other customers don’t subsidize those with rooftop solar. As households that produce some of their own electricity buy less from the utility, they pay less for fixed costs built into its retail rates, such as staffing, grid equipment, and maintenance. The utility would then look to other customers to make up the difference.
The situation echoes “cost-shift” arguments that have dogged rooftop solar around the nation. It could also be a preview of a statewide battle to come as the Public Utilities Commission of Ohio gears up to review and revise its net-metering rules, which determine how solar owners are compensated for the energy they send to the grid. Municipal utilities like Bowling Green are not subject to these rules, but the dynamics around the fairness of rooftop solar rates are similar in either case.
For their part, Harper and Jansto installed rooftop solar panels and battery storage at their home in 2019 and 2020 with hopes of lowering their electric bills and cutting their carbon footprint. The investment will eventually pay for itself because they now buy less electricity from the utility while getting some credit for excess fed back to the grid.
“We could get to near net-zero with a cost up front, but with a payback,” said Harper, who is managing director of the FreshWater Accountability Project, an environmental group.
Residential solar doesn’t just help those who invest in it.
“Rooftop solar helps to provide electricity locally. It reduces overall demand,” said Mryia Williams, Ohio program director for the nonprofit group Solar United Neighbors. That means less wasted energy because the power doesn’t need to travel as far as imported electrons, and it lowers stress on the transmission system as climate change exacerbates extreme weather and energy demand grows.
Energy fed into the grid from homeowners’ renewable energy systems can save other customers money, too.
“The highest demand periods on the grid tend to coincide with times when residential solar power is producing at its peak,” said Tony Dutzik, an associate director and senior policy analyst for the Frontier Group, a sustainability-focused think tank. “Those tend to be the times that utilities spend the most money to provide power for their customers.”
The health and environmental benefits of rooftop solar are “pretty obvious,” especially when excess energy offsets purchases from inefficient gas-fueled peaker plants, Dutzik continued. Less consumption of fossil fuels lowers greenhouse gas emissions and other pollution that is linked to multiple illnesses and more than 8 million deaths per year worldwide — problems that could worsen in the U.S. as the Trump administration rolls back climate policy.
Policymakers have “oftentimes undervalued the benefits that rooftop solar can bring, and when you fail to really account for the benefits, you tend to wind up in the situation where people think it’s not fair,” Dutzik said.
Along those lines, Brian O’Connell, utilities director for Bowling Green, said via email that the city adopted its $4-per-kilowatt monthly charge for installed renewable capacity “to ensure rooftop solar customers were paying for the electric service they were receiving, and that the rooftop solar customers were not being subsidized by non-solar customers.”
The rationale resembles an argument promoted by ALEC, the American Legislative Exchange Council, since 2014. The Center for Media and Democracy has long criticized the group for coddling the fossil-fuel industry while working to suppress the vote and stifle dissent.
Consumer advocates and some academics have made similar cases in California, whose solar capacity leads the nation for both rooftop and overall.
But Harper and Jansto were surprised when they learned Bowling Green adopted its “Rider E” charge roughly six months after work on their home’s renewable energy system wrapped up.
The utility had seemed friendly toward solar: Its website touts the significant share of its power that comes from renewables. Yet while the city aims to reduce greenhouse gas emissions, it does have a long-term “take-or-pay” contract to get about half of its electricity from the Prairie State coal plant in Illinois.
Legal and constitutional claims in the couple’s Sept. 19 complaint include unlawful and irrational discrimination. The City of Bowling Green filed its answer on Oct. 14, denying liability and asserting governmental immunity and other defenses.
O’Connell said the $4/kW rate for the charge resulted from a cost-of-service analysis by the municipal utility’s consultant, Sawvel & Associates. The city charges a general retail rate of about 13 cents per kilowatt-hour for any electricity it sells to customers. However, it credits rooftop solar owners just 7.5 cents per kilowatt-hour for whatever they supply to the grid.
O’Connell responded to Canary Media’s request for information about how the Rider E rate was calculated by sharing two spreadsheets. Each lists total savings or costs for the utility from a rooftop solar customer’s energy production, including what the utility saves by not paying other sources for capacity, transmission, and wholesale energy when customers feed excess power onto the grid.
But the documents don’t detail how the utility spends the solar surcharge. It’s unclear whether the rooftop solar fees are helping pay for the Prairie State coal plant: O’Connell’s response to Canary Media’s question merely noted the city still has to purchase energy from the electric market.
Harper and Jansto’s case will move through legal motions and pretrial fact-finding, called discovery, during the coming months. Meanwhile, advocates worry about the broader questions the case raises.
“We can look at it both ways with who’s supporting whom whenever rooftop solar is installed,” said Williams of Solar United Neighbors. In her view, “it’s hard to believe that it’s some sort of subsidized rate,” especially if solar customers get only partial credit for letting others use their excess energy.
Ultimately, Dutzik said, rate systems still should not discourage people from investing in renewable energy for their homes. Indeed, if high fees delay recovery of investments for too long, “fewer people are going to get solar,” Dutzik said. “And that is going to drive up costs for other consumers.”
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