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See more from Canary Media’s “Chart of the week” column.
Last year was fantastic for battery storage. This year is poised to be even better.
The U.S. is set to plug over 18 gigawatts of new utility-scale energy storage capacity into the grid in 2025, up from 2024’s record-setting total of almost 11 GW, per Energy Information Administration data analyzed by Cleanview. Should that expectation bear out, the U.S. will have installed more grid batteries this year alone than it had installed altogether as of 2023.
The U.S. grid battery sector has been on a tear in recent years — and California and Texas are the reasons why. Combined, the two states have installed nearly three-quarters of the country’s total energy storage capacity of over 26 GW.
California has long held the top spot on large-scale battery storage installations. Even last year, when the EIA forecast that Texas would claim the lead, California held on by a few hundred megawatts. This year EIA again expects Texas to outpace California, only now by an even wider margin than last year. The Lone Star State could build nearly 7 GW of utility-scale storage in 2025 compared to California’s 4.2 GW.
But the new state-level storyline to watch is the rise of Arizona. The state built just under 1 GW of storage in 2024, buoyed by massive new projects like the Sonoran Solar Energy Center and the Eleven Mile Solar Center that pair solar with batteries to soak up as much desert sun as possible. This year, EIA says Arizona is on track to nearly quadruple last year’s total and build 3.6 GW of storage.
It’s worth noting that EIA’s 2024 storage forecast overshot actual installations by about 3 GW — and developers didn’t have the Trump administration to contend with then. President Donald Trump has not outright targeted energy storage, but the uncertainty surrounding the future of clean energy tax credits could have a chilling effect on investment, as it has had on projects in adjacent sectors like solar and battery manufacturing.
Despite the political chaos, developers are barrelling ahead. Just over 12 GW of storage projects are either under construction or complete and waiting to plug into the grid. And, as Cleanview points out, the crucial tax credit for battery storage projects is already locked into the tax code for 2025, giving developers some measure of certainty — at least for the months ahead.
Two years after slashing compensation for rooftop solar owners who send power back to the grid, California policymakers are once again looking for ways to contain high and rising electricity rates — which means the accusation that rooftop solar pushes costs onto other utility customers is once again rearing its head.
Last month, representatives of the California Public Utilities Commission testified in a state legislative hearing that California’s system for compensating owners of rooftop solar is a primary cause of the state’s rapidly rising utility rates.
That testimony is backed by a CPUC report, issued last month in response to an October order from Democratic Gov. Gavin Newsom to find ways to reduce utility-rate increases. Among other potential cost savings, the report proposes further reductions to rooftop solar compensation that the CPUC has already cut for homes, businesses, farms, and schools in the past two years.
The CPUC’s rationale is that solar programs shift costs onto customers who don’t have solar. Linda Serizawa, director of the CPUC’s Public Advocates Office, which is tasked with protecting utility customers, told lawmakers that the state’s rooftop solar regime has led to non-solar-equipped customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric paying $8.5 billion more than they otherwise would have in 2024. That increase accounts for up to a quarter of those customers’ monthly bills, on average, according to the Public Advocates Office.
Solar advocates and environmental justice groups have long said this “cost-shift” argument is false. In fact, they say, California utility customers would be paying even higher electric rates if the state hadn’t launched policies back in 2006 that have incentivized California homes, businesses, schools, and other utility customers to install more than 2 million rooftop solar systems since then.
Last week, several pro-solar groups shared new analysis, expanding on research released last year by energy and environmental consulting firm M.Cubed Consulting.
The latest round in the “cost-shift” debate comes as the CPUC’s December 2022 decision to cut compensation for newly installed rooftop solar systems has decimated the country’s leading rooftop solar market, potentially putting the state’s carbon-cutting goals out of reach. About 45% of the state’s solar power now comes from rooftop and distributed sources rather than utility-scale projects, but new rooftop solar installations have fallen dramatically since the CPUC’s new compensation system went into effect in mid-2023.
Without more rooftop solar, “we’re going to have increasing electricity costs, and we’re going to fall short of our clean energy goals,” said Ken Cook, president of the nonprofit Environmental Working Group. The challenge, he said, is to agree on regulatory structures that allow the state to “harness rooftop solar and distributed energy to solve both of these problems.”
But the cost-shift argument has short-circuited that kind of policy discussion, said Brad Heavner, policy director for the California Solar and Storage Association, a solar-industry trade group that funded M.Cubed’s cost-shift analyses. “It was devised by the utilities as a way to reframe what rooftop solar is and to put a negative light on it. And it has worked.”
Now, with mounting pressure to reduce utility rates, rooftop solar advocates fear the argument will be used once again to justify further cuts to an industry they view as crucial not only to climate goals but as a net benefit — not cost — to utility customers.
The cost-shift argument was initially put forward by the Edison Electric Institute, a trade group representing U.S. electric utilities. Utilities pay for building and maintaining the power grid through the rates they charge customers. The cost-shift thesis argues that paying some customers for their rooftop solar power unfairly shifts the burden of covering the costs of keeping utilities running onto other customers.
But Richard McCann, a founding partner at M.Cubed, argues that California’s nation-leading rooftop solar resource has saved customers as much as $1.5 billion in 2024 through savings accrued over the past two decades. The reason, in his view, is simple: More rooftop solar means utilities need to buy less energy from other resources and build less power lines and other grid infrastructure to meet customers’ power demand.
Back in 2005, the California Energy Commission forecasted that the state’s peak demand for electricity — the primary driver of utility costs for generation and grid capacity that are passed on to customers — would grow from about 45 gigawatts to more than 60 GW by 2022 or so, McCann said.
But peak electricity demand on the statewide grid operated by the California Independent System Operator (CAISO) has grown far more slowly. The system has instead topped out at a record-setting peak of 52 GW in September 2022 — only about 2 GW over the previous record set in 2006.
Over that same time, the state’s net-metering policies have incentivized millions of customers of the state’s three big utilities to install solar panels, he said. Much of the state’s peak grid demand coincides with hot summer afternoons — the same time that rooftop solar produces the most electricity.
CAISO does not directly track how much power rooftop solar generates across millions of California homes and businesses, McCann noted. But the simultaneous trends of lower-than-forecasted peak demand and growing rooftop solar resource indicate that “rooftop solar has displaced the peak load demand in the CAISO system and kept the CAISO load flat over that same time period,” he argued.
If that’s the case, customers investing in rooftop solar have helped the state’s utilities avoid investing in new generation, transmission, and distribution, potentially saving ratepayers billions of dollars, he said. “Rates would be even higher than what they are now if rooftop solar had not been present.”
McCann’s view, supported by most environmental advocates, the solar industry, and some energy analysts, is hotly contested by utilities as well as independent analysts who have championed the cost-shift thesis.
In the latter group’s view, rooftop solar is a more expensive and less efficient alternative to building utility-scale solar power plants and transmission grids. Shifting money from those larger-scale alternatives not only pulls money from customers without solar to those with solar, they argue, but represents a lost opportunity for utilities to invest in more cost-effective clean power.
Severin Borenstein, head of the Energy Institute at the University of California, Berkeley’s Haas School of Business, is a key proponent of the cost-shift theory. In January, Borenstein published a paper challenging McCann’s take on the value of rooftop solar, citing “fundamental conceptual errors that undermine most of its points.”
Borenstein said that a proper analysis finds that in 2024 solar net-metering pushed about $4 billion in costs onto utility customers who don’t have solar. That’s not nearly as high as the $8.5 billion figure from the CPUC’s Public Advocates Office, but it’s still a net cost rather than a benefit to customers at large.
In February, McCann published a reply to Borenstein’s critique, delving into his point-by-point differences of opinion on how these costs should be calculated. Much of the dispute is highly technical in nature. And because these analyses rely on heavily varied assumptions — including what would have happened if the past 20 years of rooftop solar policy hadn’t played out the way they have — many of the conflicts between the two sides on precise numbers can’t be answered definitively.
That uncertainty has led both sides to accuse the other of using intentionally misleading data and methods. McCann acknowledged that his initial analysis last year miscalculated the benefits that he believes rooftop solar has delivered to customers of the state’s three big utilities. He originally calculated $2.3 billion worth of benefits in 2024, rather than the $1.5 billion that emerged from his latest analysis.
The in-the-weeds exchange between McCann and Borenstein reveals a deeper disagreement at the heart of their vastly different estimates — one that cost-shift foes say California regulators have failed to fully acknowledge. It centers on a simple question: When a household generates solar power at the same time as it’s using electricity from the grid, who owns that solar?
According to McCann, who cited legal precedents and the fundamental physics that determine the flow of electrons, solar power that customers generate and consume at their own homes and buildings is theirs by right. They paid for the solar systems, and they’re directly using the electricity those systems generate.
But according to both Borenstein and the Public Advocates Office’s analysis, solar power simultaneously generated at the time that power is being consumed on site should be considered as a cost to other utility customers.
As Borenstein states in his January rebuttal, “So long as a solar system is connected to the grid, there is no real distinction between self-consumption and grid supply. Despite this fact, if a customer’s aggregate rooftop solar production during an hour is equal to the household’s consumption, then some argue that the customer is ‘self-consuming’ and their consumption in that hour should not be obligated to make any contribution to grid costs or other costs that are part of the retail price.”
In other words, according to this logic, allowing solar-equipped customers to count the power they generate as offsetting their use of grid power undermines the fundamental structure of utility rates, which recover the costs of electricity delivery by charging customers for their hour-by-hour energy use.
These two different interpretations go a long way in explaining the chasm between McCann’s analysis and those from Borenstein and the Public Advocates Office. According to McCann’s analysis, this category of “cost” — self-generated solar power considered as the property of the utility and ratepayers at large, rather than belonging to the individual households using it — accounts for nearly $4 billion of the Public Advocates Office’s $8.5 billion cost-shift calculation.
But McCann believes that Borenstein and the Public Advocates Office’s perspective runs afoul of standing legal and regulatory precedent on such matters.
He cited a 2015 paper in which Jon Wellinghoff, former chairman of the Federal Energy Regulatory Commission, and Steven Weissman, a former CPUC administrative law judge and a founder of the energy law program at the UC Berkeley School of Law, state that “[p]roperty owners in the United States have the right to generate electricity onsite, for their own use. This understanding is so fundamental that legislatures have not bothered to spell it out.”
FERC has dismissed arguments that solar generated at homes and other buildings should be regulated by the federal authorities governing the bulk-electricity grid.
The bigger problem with the cost-shift numbers from CPUC and the Public Advocates Office is that they have never been subjected to the kind of regulatory process that could allow regulators, lawmakers, and the public at large to fully grasp and argue over the validity of the assumptions that have gone into them, Loretta Lynch, an attorney and energy policy expert who served as CPUC president from 2000 to 2002, said during a webinar led by M.Cubed last week.
Instead, the Public Advocates Office published a paper in August 2024 asserting its cost-shift figure, which has since been used to justify a range of policy decisions, she said. That’s not how regulators are supposed to do things, Lynch added.
“Before the CPUC goes and touts an unvetted report of dubious calculation and worth, perhaps it should put that report in an evidentiary hearing in a proceeding, along with Richard’s analysis,” she said, referencing M.Cubed’s latest paper.
Then, the CPUC could “have the expert analysts go toe-to-toe, under oath, with questions and cross-examination, so we can see the assumptions made, the data used, and whether or not the conclusions are valid.”
It’s important to note that these cost-shift analyses are looking at California’s rooftop solar past, not its future. In more recent years, as solar has grown to make up an increasing portion of California’s electricity-generation mix, peak grid demands have shifted from late afternoons when the sun is still shining to hot evenings after the sun goes down. Every new increment of solar power added to the grid is less and less useful on its own in reducing these new “net peak” demands.
Batteries that store power for use during these post-sundown peaks have thus become a vital addition to new solar installations, both at the utility scale and at homes and businesses.
The net-billing tariff the CPUC approved in late 2022 to replace its previous net-metering regime offers far lower payments for the electricity that newly installed rooftop solar systems inject onto the grid, except for a few hours per year when peak power is in dire need. That structure rewards customers who add batteries that can store and inject power during those valuable hours — a service that should reduce how much energy utilities need to secure and how much grid infrastructure they need to build to serve those peak moments.
But solar advocates are now worried that the CPUC’s report on containing rate increases calls for reducing the value of solar power for “legacy” net-metering customers as well.
Under the CPUC’s previous net-metering regimes, customers are paid full retail rates for solar power they send back to the grid for 20 years. In its February report, the CPUC proposes shortening those legacy periods, which could reduce costs for utilities but also undermine the economic calculations that made rooftop solar worthwhile to customers who installed it with the assumption that those rules wouldn’t change.
The CPUC report also proposes adding a “grid-benefits charge” to the bills of existing rooftop solar owners — in essence, charging them extra for having solar panels. Utilities have previously proposed this concept and shortening legacy net-metering periods, but regulators rejected them after significant pushback.
The CPUC’s new report doesn’t advocate for these or any other particular changes to utility regulations or policy. But it does propose that state lawmakers consider finding “non-ratepayer sources” to compensate customers with rooftop solar.
The CPUC didn’t specify which alternative sources could fill that gap. Prior proposals to use state tax revenues or California’s cap-and-trade program could be part of the mix, said Mark Toney, executive director of The Utility Reform Network, a ratepayer-advocacy group.
But even supporters of those concepts like Toney don’t see much hope of lawmakers fielding bills that would ask taxpayers to shoulder costs now borne by utilities. “It is wishful thinking that we could shift rooftop subsidies to taxpayers,” he said. “I’m not holding my breath here.”
Given the unlikely prospects of using taxpayer funds to pay rooftop solar customers, solar advocates fear that the CPUC’s proposal is an opening shot in a battle to weaken rooftop solar even further.
Cook of the Environmental Working Group described the potential ramifications of such a move: “If people come to believe that any agreement they thought was going to be good for, say, 20 years means nothing to the state and to the utility regulators — if it can be wiped away — that’s going to make it even harder to convince people to think that their own investments and rooftop solar are going to pencil out.”
Ascend Elements, a leading contender in advanced battery recycling, canceled a portion of its planned battery-materials plant last week. The company still aspires to expand a fully domestic battery supply chain but has had to adapt to tumultuous policy and market conditions.
China controls most of the world’s processing capacity for key battery inputs. Under the Biden administration, the U.S. began a concerted effort to build up those resources — like lithium mines, lithium-processing plants, and advanced facilities that make cathode active materials (CAM) that go into batteries.
A cohort of battery-recycling startups joined the cause, pledging to safely and economically disassemble old batteries and funnel their pieces back into the supply chain. Ascend is one of them: The Massachusetts-based company opened a plant in Covington, Georgia, in March 2023 that grinds up used batteries into the powder known as black mass. Ascend is currently building a plant in Hopkinsville, Kentucky, where it will refine that black mass into battery materials.
That project, called Apex 1, is still happening, but Ascend has narrowed its scope: The startup announced last week that it is scrapping plans to produce CAM there and agreed to cancel the $164 million grant that the project won from the Department of Energy. Ascend intends to convert the space that would have made CAM into a lithium carbonate production line, using a proprietary technology the company rolled out at its Covington plant early this year.
Apex 1 will still produce the precursors to CAM known as pCAM, an effort aided by a separate $316 million grant from the DOE. These powders include cathode materials like nickel, manganese, and cobalt; manufacturers add lithium to those ingredients and fine-tune the recipe to generate finished CAM.
Between the previously planned pCAM and the newly announced lithium carbonate lines, Ascend still plans to invest about $1 billion in the Kentucky project, spokesperson Thomas Frey told Canary Media on Tuesday.
The companies that buy CAM already have supplies lined up, and demand isn’t growing fast in the near-term, Frey said. But the companies that make that CAM need to obtain the precursor materials from somewhere, and that’s where Ascend still sees an opportunity.
“By getting out of CAM, we’re essentially turning potential competitors into potential customers,” he said.
Ascend can sell its pCAM to specialized CAM manufacturers or to electric-vehicle and battery manufacturers who want their suppliers to use that particular material, Frey noted.
“We’re still really highly committed to creating a domestic, closed-loop battery ecosystem in the U.S.,” Frey said. “We will be the only large-scale manufacturer of pCAM in America. With tariffs at play and things like that, that makes us pretty appealing.”
Another benefit to focusing on pCAM is that it’s a more generalizable product than CAM, which has to be tailored intricately to each battery manufacturer’s proprietary designs. Since batteries are such a precisely calibrated technology, prospective buyers scrutinize CAM samples for a year or more before clearing producers for a large commercial order. The sales cycle for pCAM is quicker and easier, Frey said.
Ascend’s timeline has also been influenced by a broader slowdown in the U.S. electric-vehicle manufacturing buildout. Detroit automakers have pulled back on their earlier enthusiasm for EV production, which has pushed back timelines for the battery supply chain, including CAM and pCAM.
Some companies have canceled battery factories in just the last few weeks, like Freyr Battery (now T1 Energy), which had aspired to build one in Georgia, and U.S. startup Kore Power, which ditched plans for a facility near Phoenix.
Ascend has extended its timeline for Apex 1 from the end of 2025 to the third quarter of 2026, which Frey said allows for a more cost-effective construction process. Commissioning is underway for the new lithium carbonate line at Ascend’s Covington factory, which should begin commercial production in the next few months, he added.
The Covington plant has also struggled with a more fundamental problem: The old batteries the facility grinds up keep catching fire.
Firefighters responded to a Feb. 20 conflagration in a tractor trailer delivering used batteries to the site. The fire consumed the trailer but did not jump to the adjacent building, per local news reports from the scene.
Jarringly, that was the 14th time Ascend’s Covington plant called in emergency teams. Not all those calls included outright fires, and nobody was injured in any of them, plant manager Andrew Gardner told WSB-TV. But the track record has the city’s mayor worried about the safety of hosting such a facility in the community.
Some of those calls involved workplace injuries and concerns unrelated to lithium-ion batteries, Frey noted to Canary Media. Nonetheless, the latest incident was the biggest thermal event so far; it destroyed the trailer and left some burn marks on the exterior of the nearby building but did not enter the structure. The cause seems to have been batteries that were not properly packed or discharged prior to shipping.
“Since then we have gone on a blitz with all of our customers to redo training on how to pack end-of-life batteries and scrap,” Frey said. “We’ve stopped operations for 10 days to work really closely with the Fire Department and the mayor to show them we’re doing everything we can to ensure safety.”
This story originally appeared in New York Focus, a nonprofit news publication investigating power in New York. Sign up for their newsletter here.
New York state is one step closer to banning fossil fuels in new buildings.
On Friday, the State Fire Prevention and Building Code Council voted to recommend major updates to the state’s building code, which is updated every five years and sets minimum standards for construction statewide. The draft updates include rules requiring most new buildings to be all-electric starting in 2026, as mandated by a law passed two years ago.
The vote came after the code council went missing in action for more than two months, leaving some advocates nervous that the state might be wavering on the gas ban. With the rules now entering the final stage of the approval process, New York remains on track to be the first state to enact such a ban.
The new draft code also tightens a slew of other standards in a bid to make buildings more energy efficient and save residents money over the long term. But it leaves out several key provisions recommended in the state’s climate plan — possibly running afoul of a 2022 law.
Specifically, the draft energy code leaves out requirements that new homes include on-site energy storage and be wired such that owners can easily add electric vehicle chargers (when the property includes parking space) and solar panels. The state’s 2022 climate plan listed these three provisions as “key strategies” to achieve New York’s legally binding emissions targets. On-site energy storage also makes homes more resilient when disasters strike, the plan noted, providing backup power in the event of a blackout.
A separate 2022 law required the state to take those recommendations into account when updating its building code.
“Updating the infrastructure for those things is a key part of what this transition is,” said Michael Hernandez, New York policy director at the pro-electrification group Rewiring America.
The Department of State, which oversees New York’s code development process, did not respond to a request for comment.
Buildings are New York’s largest source of emissions, according to the state’s accounting, amounting to nearly one-third of all climate pollution. New York’s buildings burn more fossil fuels for heat and hot water than any other state’s, according to the clean-energy group RMI. That contributes not only to global warming but also to local air pollution, with deadly consequences: A 2021 study by Harvard researchers found that pollution from New York’s buildings causes nearly 2,000 premature deaths a year.
Cutting that pollution will require major upgrades to the state’s aging housing stock — an enormous challenge. But climate hawks stress that the first and easiest step is to stop digging the hole deeper, by making new buildings as climate-friendly as possible. Making them all-electric is a key part of that. But other, subtler changes can also play an important role.
The fossil-fuel industry, for its part, is taking those changes seriously. Gas trade groups led a major fight to keep provisions such as the EV-ready requirement out of the national building code that provides a model for states including New York. After nearly five years of wrangling, the International Code Council — actually a national nonprofit — that oversees the process voted not to include the provisions as requirements, siding with the gas groups over the advice of its own experts.
Among the parties who stood up for the stricter energy code: a New York state code official, who joined advocates like Hernandez one year ago in urging the International Code Council to keep the requirements in. Yet the state is now following the national group’s lead and relegating the solar, electric vehicle, and battery standards to the appendices of its draft code. That means they can still serve as templates for localities that want to adopt the tougher standards, but they’re not required.
Fossil-fuel interests and some Republican lawmakers have argued that including such mandates would only drive up the cost of new homes at a time when housing is already deeply unaffordable. But climate advocates point out that it’s far cheaper to install electrical infrastructure up front than add it in later on — as much as six times cheaper in the case of an EV charger, for example.
That’s in keeping with many of the green rules that New York did include in its new draft code. Chris Corcoran, a code expert at the state energy authority NYSERDA, told the code council on Friday that adopting the full suite of proposed energy rules will add about $2 per square foot to the up-front cost of new homes but save residents more than three times that over 30 years.
It’s not entirely clear who in New York has pushed to leave the storage, solar, and EV provisions out. Only eight groups disclosed that they lobbied on the building and energy codes last year, and it’s not obvious that any of them had a specific interest in opposing those rules.
Officials speaking at Friday’s meeting did not explain why they left out the requirements. One lawyer who helped draft the updated energy rules, Ben Kosinski, left the Department of State just this month to work as chief counsel for the Senate Republicans, for whom he also worked before joining the code office, according to his LinkedIn profile. The GOP caucus has voted almost unanimously against the laws driving the pro-electrification updates to the code. (Kosinski did not immediately reply to a request for comment.)
Although the council voted unanimously on Friday to advance the all-electric rules, not all members supported the move. William Tuyn, a builders’ representative from the Buffalo area, noted that the state adds roughly 40,000 homes a year — a tiny fraction of the roughly 7 million that already exist.
“We don’t even make a dent in the issue of climate change by focusing there,” he said in the final minutes of the meeting. “The Legislature did what they did. That ship has sailed … [but] we really need to concentrate on renewables or improving the grid if we’re really going to be able to do something and we’re not just going to simply crash the economy of the state of New York.”
Several lawmakers urged the council on Friday to include the full suite of climate provisions in the final rules.
“These provisions are not trivial add-ons. They are the backbone of a truly effective energy code,” said Neil Jimenez, legislative director for Assemblymember Yudelka Tapia. “Their exclusion weakens the very foundation upon the policies we’ve fought so hard to put into place here in Albany.”
Since its founding back in 2010, Shine Technologies has raised nearly $800 million to deliver on the potential of generating cheap, abundant energy from fusion.
Like the dozens of other startups at work in this field, Shine Technologies has yet to crack the code on fusion, an energy source that has been 40 years away from commercialization for 50 years. But unlike those competitors, Shine is already generating real revenue — not by producing electricity but by essentially selling neutrons from the fusion reaction to industrial imaging and materials testing companies.
Governments, venture capitalists, tech billionaires, and other private investors around the world have pumped more than $7.1 billion into fusion companies, according to a July 2024 report by the Fusion Industry Association.
But despite almost a century of research since fusion’s discovery, engineers have been unable to achieve its holy grail: continuously generating more power than was used to create a fusion reaction in the first place. The fusion world uses a metric called the fusion energy gain factor, also known simply as Q, to measure that ratio. If a project was to achieve a Q greater than 1, it would achieve the much-sought-after energy-breakeven point.
But Shine has a different benchmark — at least for right now.
“If you talk to almost every fusion company on Earth, they’ll say, ‘We’re shooting for Q greater than 1.’ But we have a different Q — our Q is economic. It’s generating more dollars out than dollars in. That’s how you scale a company,” Greg Piefer, Shine’s CEO, said.
The fusion reaction is the primordial alchemical trick that powers our sun, propels spacecraft in science-fiction novels and, if the visionaries and true believers are correct, could meet humanity’s voracious energy needs in the centuries to come.
The reaction occurs in plasma, the fourth state of matter. The sun creates plasma by compressing and heating hydrogen to tens of millions of degrees, and it performs the miracle of fusion by confining that hydrogen, along with its variants, with its mammoth gravity.
Humans hoping to recreate the conditions of the sun on Earth have to rely on exotic magnets, Brobdingnagian laser-beam arrays, or other maximalist techniques.
These complex and expensive fusion machines compress and confine plasma in an attempt to bring two nuclei close enough to overcome their repellant electrostatic forces and fuse together. A successful, sustained fusion reaction would heat up a material surrounding the reactor, allowing it to boil water and drive the same sort of conventional steam turbine you’d find in a coal, gas, or traditional nuclear (fission) power plant.
Most of the fusion startups Canary Media has covered — such as Commonwealth Fusion Systems, TAE Technologies, Avalanche Energy, and Zap Energy — plan to take this steam-turbine approach to producing fusion power. Each company has its own (unproven) method for controlling the plasma and wringing out the heat. Some firms use a tokamak design, a very big, hollow donut-shaped hall in which the plasma circulates, or a twisted variant called a stellarator. Some aspirants confine the plasma with magnetic forces while others use high electrical currents or lasers to tame the atomic-particle soup.
So, which technology and approach is Shine using to solve the fusion riddle?
“I’m going to say something really trippy. As a fusion company, when it comes to energy production — I don’t know yet. … We have our own internal technological approach. I don’t think it’s any more likely than any other technological approach to prevail,” Piefer admitted. “You won’t hear that from any other fusion CEO in the whole world. But the truth is, it’s early innings, and we don’t know which fusion approach is going to be the most cost-effective.”
And while today’s cadre of fusion startups aims to provide power to the electrical grid in the 2030s or 2040s, Shine is following a different path to market.
“Fusion-energy people are trying to go from fusion not really having ever been used commercially for anything to it being the most reliable, cheapest form of generating energy,” said Piefer. “Everyone’s chasing the energy.”
Instead, Shine’s CEO wants his firm to scale the way historic deep-tech companies like semiconductor makers have done: “You start small with a market where you can make money right away, and then you iterate over time — and through that virtuous cycle of providing value and reinvesting a portion of it to make the technology better, you continue to access bigger and bigger markets.”
The market where Shine is making money now is the sale of neutrons for use in industrial imaging and materials testing. Piefer estimates that this will generate “on the order of $50 million of revenue in 2025.”
Shine will next move into medical-isotope production, then recycling spent nuclear fuel, and, ultimately, Piefer said, electrical power generation.
Producing medical isotopes requires fewer sustained reactions than producing power, and while net power is a ways away, the technology for isotope production is already available.
Medical isotopes are currently produced via nuclear fission, but if they can be produced via fusion, that would eliminate the need to use highly enriched uranium. And it could be a lucrative line of business: The global market for medical isotopes is about $6 billion a year.
“If you make a kilowatt-hour of fusion energy, you can sell that kilowatt-hour for maybe 5 cents,” he said. “But you can sell the other product of [deuterium-tritium] fusion reactions, neutrons, for as much as $100,000 per kilowatt-hour in certain markets.”
The prospect of getting a foot in that market drove Shine to break ground on a new facility in Wisconsin, which has already been licensed by the Nuclear Regulatory Commission. It will be the largest isotope-production factory in the world when it comes online in a few years, according to Piefer. He claims that his firm is the only one that has successfully shepherded a new nuclear technology through the NRC process since the agency’s inception in 1974. The firm has also received tens of millions of dollars from the Department of Energy’s National Nuclear Security Administration to support its isotope-production plans, including $32 million last summer.
Unlike the rest of the fusion-startup cohort, “we’re actually selling fusion,” the CEO said. “That’s an important differentiation because it means we get to practice fusion, which is ultimately what’s going to drive it to be cheaper” — and potentially pave the way for it to become a power source in the decades to come.
Correction: This article has been updated to correct the total amount of money Shine Technologies has raised to date.
Maine’s solar incentive program has become a political scapegoat for rising electricity prices in the state, but clean-energy advocates say the numbers don’t add up.
Maine utility customers pay some of the country’s highest electricity prices, but the portion of their monthly bills that goes toward buying surplus power from neighbors’ solar panels has actually decreased in recent months, according to one analysis.
Meanwhile, the amount of money utilities are paying for power from fossil fuel–fired plants and transmission represents a far bigger share of the electricity-bill bottom line.
“It’s an easy narrative to say ‘Solar panels are being built in this field, and electricity prices are going up,’” said Lindsay Bourgoine, director of policy and government affairs at solar company ReVision Energy. “But that’s not actually what’s happening when you look at the data.”
Maine Republican lawmakers this session have introduced four different bills calling for the repeal of net energy billing, the system that compensates utility customers for unused electricity they generate and share on the grid. Supporters of the bills have called the program a “job-stealing solar energy tax,” though it’s not a tax: Utilities compensate the owners of solar panels for excess energy sent to the grid, then spread the cost out among ratepayers.
“What’s really troubling in Maine is that there is this growing narrative that the rise in utility bills is directly attributable to solar,” said Eliza Donoghue, executive director of the Maine Renewable Energy Association. “It’s not true.”
The hostility toward Maine’s net energy billing rules is part of a wave of efforts to blame rising power prices on clean-energy and energy-efficiency programs, particularly in New England. In Rhode Island and Maryland, legislators have called for cuts to fees supporting energy-efficiency and clean-energy programs. And Massachusetts regulators last week ordered $500 million to be cut from the state’s energy-efficiency plan, following utilities’ claims that these money-saving programs have been a major driver of rising energy bills.
At a legislative committee hearing last week, Maine legislators testified that small-business owners will be forced to close their doors and low-income households put in dire financial straits by wealthy solar-panel owners imposing the cost of their renewable-energy choices onto everyone else. It is “a nefarious scheme,” said Sen. Trey Stewart, a Republican and the sponsor of one of the bills. “We risk collapsing our entire economy,” said Republican Sen. Stacey Guerin, the sponsor of another.
The numbers tell a very different story, beginning with the actual dollars-and-cents impact of net energy billing on the average consumer.
Maine’s net energy billing program was expanded in 2019, increasing its cost but also spurring new solar development. By the end of 2024, the state had more than 1,500 MW of solar capacity, up from less than 100 MW in 2019.
Statewide, costs attributed to net energy billing now make up a slightly smaller percentage of the average bill than they did in the latter half of 2024, according to calculations ReVision made using information from utility filings. For Versant Power residential customers using 500 kilowatt-hours per month, net energy billing adds between $6.40 and $7.62 to the monthly bill depending on their exact location, according to a spokesperson for the utility. Central Maine Power residential customers pay on average $7.06 per month for costs related to net energy billing, a spokesperson for the company said.
So if it’s not the solar program, then what is causing utility bills to rise? One of the main forces driving electricity prices is the cost of energy supply in New England, more than half of which comes from natural gas–fired power plants. Volatility in the natural gas market, therefore, translates directly into higher electricity rates for consumers. Prices spiked in 2022 and 2023, for example, as the war in Ukraine pushed the cost of natural gas up worldwide. This year, energy supply accounts for 39% of a typical Maine household’s monthly bill — roughly nine times the cost of net energy billing — according to ReVision’s numbers.
“Solar isn’t the problem. Fossil-fuel volatility really is,” Bourgoine said.
The other major contributor is rising transmission costs, which on average make up 51% of electricity bills, up from 37% in the second half of 2023.
There are some commercial cases in which the cost for net energy billing does have an outsized impact on energy bills, supporters of the incentive agree. Commercial power customers are charged a fixed rate based on the specific rate classification their business falls under. This system means some businesses end up with a much larger percentage of their bill paying for net energy billing.
At last week’s hearing, Sen. Stewart testified that potato processor Penobscot McCrum will pay close to $700,000 in public-policy charges this year. Roughly 55% of this charge reflects the costs of net energy billing, according to utility Versant.
Supporters of net energy billing agree that situations such as these are unfair and unsustainable, and a docket is already underway with the state Public Utilities Commission to address that specific issue without repealing the entire net energy billing program, Donoghue said.
“There is a certain amount of customers that, we agree, should be complaining,” she said.
Net energy billing also provides benefits that are hard to see but which offset the costs, supporters said. In 2023, the program cost ratepayers $130 million but delivered $160 million in benefits to the state, according to an independent analysis prepared for the Public Utilities Commission. By adding solar power to the grid, the program helps suppress wholesale electricity prices, for example, and it improves reliability because there cannot be a shortage of “fuel” for solar generation.
More solar generation in the state means more Maine households are getting power produced in or near their communities, lowering the strain on the transmission and distribution systems — and the associated costs. Solar developers also pay for any infrastructure upgrades needed to accommodate their projects.
“Those are investments that utilities don’t have to put on ratepayers,” said Jack Shapiro, climate and clean energy director for the Natural Resources Council of Maine.
Furthermore, eliminating net energy billing would have its own financial consequences for the roughly 110,000 customers enrolled in the program. The abrupt end of all net energy billing would leave these participants — including residents, businesses, and schools – without promised and planned-for savings, Shapiro said.
Opponents in the legislature have passed three rounds of rollbacks to the program. Now they want to go even further.
“If [these bills] were passed, they would actually have some truly disastrous consequences for a lot of people and schools and municipalities,” Shapiro said.
U.S. manufacturers rely on more than 30,000 small industrial boilers to make a large number of things: foods, drinks, paper, chemicals, clothes, electronics, furniture, transportation equipment, and more.
The vast majority of these smaller boilers burn fossil fuels — mostly gas, but sometimes coal or oil. Their emissions contribute not only to climate change but to smoggy skies and elevated asthma rates, too.
Swapping out such boilers for electric industrial heat pumps would be a quick win for communities and regulators looking to improve air quality, said Hellen Chen, industry research analyst at the nonprofit American Council for an Energy-Efficient Economy, or ACEEE.
Only about 5% of process heat in industry currently comes from electricity, but industrial heat pumps are gaining some momentum. They’ve already been installed in at least 13 American factories, helping reduce pollution from brewing beer, pasteurizing milk, and drying lumber. Kraft Heinz, the famed ketchup and mac-and-cheese maker, plans to install heat pumps at 10 factories by 2030. Oat-milk producer Oatly is considering one at a New Jersey plant. And policymakers in Southern California passed a rule last summer to phase out industrial boilers, a move that will likely boost heat-pump replacements.
Industrial boilers spew a panoply of air pollutants as byproducts of combustion, including nitrogen oxides, or NOx. NOx is harmful in itself but also contributes to the formation of ozone, a key ingredient of smog that can inflame airways and cause a range of respiratory problems, especially in children whose lungs are still developing.
To identify opportunities to clean up air quality, Chen and ACEEE colleagues recently mapped areas where ozone levels exceed the U.S. Environmental Protection Agency standard, the number of small industrial boilers in each area, and the fuel they use. In total, they found that more than 5,400 boilers currently burn in 174 counties. The team focused on smaller industrial boilers, defined as having capacities up to 50 million British thermal units per hour, because their emissions are often overlooked, yet the equipment is the easiest to switch out for heat pumps, Chen said.
“In areas where the baseline community pollution burden is already high, there is a really important opportunity,” Chen said. Heat pumps are “a cleaner and more efficient technology that is ready for adoption today.”
Depending on the boiler size, fuel type, and other aspects, the reduction in onsite NOx emissions from swapping just one industrial boiler for a heat pump is equivalent to taking 400 to 10,000 cars off the road, by Chen’s calculation.
The industrial emissions reductions would add up. Some counties host large stocks of these smaller boilers: Cook County, Illinois, has 297; Philadelphia County, 127; Harris County, Texas, 123; and Los Angeles County, 111, per the ACEEE map.
Heat pumps are available now for low-temperature industrial processes, making them well-suited to industries like food and beverage manufacturing, which relies almost exclusively on heat below 266 degrees Fahrenheit (130 degrees Celsius). Low-temperature heat also plays a significant role in areas like chemicals and paper production.
Industrial heat pumps, which were first developed in the 1980s, are wildly energy efficient and can use just one-third to a quarter as much energy as boilers. Depending on the relative prices of gas and electricity, that superior efficiency can deliver lower operating costs.
Heat pumps can also improve product quality by providing more precise temperature control. Back in 2003, the Department of Energy found that heat pumps produce higher-quality dried lumber.
Plus, heat pumps can have a smaller physical footprint than boilers with similar capacities since they don’t store fuel, making them advantageous for facilities with limited floor space. Since they’re modular, they can be installed in parallel to meet heat demands as needed, Chen said.
Added up, these and other co-benefits can save facilities another 20% to 30% on top of reduced energy costs.
The major impediment to switching out combustion boilers, which can last 20 to 40 years or more, is the upfront cost. The payback period for an industrial heat pump retrofit is typically on the high side — between five and seven years, Chen said.
“Unfortunately, many companies are looking for very short ROIs [returns on investment] of under three years,” Chen said, making the business case difficult even if the lifetime savings are great. In new facilities, heat pumps can cost the same as gas boilers to install, she noted.
Policy support can make it more logical for a business to take on these upfront costs.
At least one air quality regulator is beginning to push industries to decarbonize. Last year, California’s South Coast Air Quality Management District passed a first-in-the-nation measure that aims to gradually phase out NOx emissions from 2026 to 2033 from more than 1 million large water heaters, boilers with capacities of up to 2 million British thermal units per hour, and process heaters in the area, which will necessitate the switch to electric tech.
Chen hopes to see more regulators follow the district’s lead as well as tackle what is to her the biggest hurdle to electrification in the U.S.: the relatively high cost of electricity compared with gas, known as the “spark gap.”
The spark gap, the ratio of average electricity price to fossil-gas price (each in dollars per kilowatt-hour), varies from state to state. A ratio of less than about three to four typically makes switching to a heat pump more economically feasible without additional policy support because industrial heat pumps are about three to four times as efficient as gas boilers and thus can lower operating costs, Chen noted.
Electric utilities and regulators could redesign rates to make the electric equipment more attractive. The idea has precedent for home heat pumps, though hasn’t been realized for industrial ones yet, as far as Chen’s aware.
State and federal programs are also helping to defray the capital costs of electrifying.
California provides $100 million for electric upgrades at factories through the Industrial Decarbonization and Improvement of Grid Operations program. Colorado offers competitive tax credits — up to $168 million in total — for industrial facilities to install improvements that reduce greenhouse gases. Under the Biden administration, about $500 million was granted to Kraft Heinz and others for projects cleaning up emissions from process heat, part of a $6 billion windfall for industrial-decarbonization demonstration projects. But the fate of the awards is unclear as the sweeping federal funding freeze ordered by President Donald Trump in January has, so far, failed to fully thaw.
With momentum growing for zero-emissions equipment like heat pumps, “we’re hoping that … more facilities will see them as a viable technology that’s ready to go,” Chen said, and that companies “will be more confident about applying this technology within their own facilities.”
Sunnova, one of the country’s largest residential-solar companies, has warned investors that it may run out of money within the next 12 months. It’s a snapshot of a company struggling to maintain financial viability amid a punishing economic climate for rooftop solar installers and financiers.
The “going concern” warning came during Sunnova’s fourth-quarter and fiscal-year earnings statement on Monday. The news sank the Houston-based company’s stock price from about $1.60 per share on Friday evening to a low of 56 cents per share on Monday morning. (Sunnova shares were trading at about 60 cents as of market close on Monday.)
Sunnova’s revenue grew to about $840 million in 2024, up from nearly $721 million in the prior year. But the company’s net losses before income taxes of almost $448 million last year were little improved from just over $502 million in 2023. The losses stemmed from declining sales of solar energy systems and products alongside rising operating expenses.
Over the course of the year, Sunnova was unable to increase the amount of unrestricted cash and commitments under existing financing arrangements to fund its business. The company, which finances rooftop-solar and battery installations conducted by independent installers, laid off about 300 employees, or about 15% of its workforce, in February.
As of Friday, these unrestricted funds were “not sufficient to meet obligations and fund operations for a period of at least one year from the date we issue our consolidated financial statements without implementing additional measures,” the company stated.
A Sunnova spokesperson told Canary Media on Monday that the company is “confident in our ability to manage our obligations and position Sunnova for long-term success.”
The bad news from Sunnova comes amidst a tough economic picture for U.S. rooftop solar overall. The nation’s residential-solar installations were forecast to decline by roughly 26% in 2024 compared to 2023 in a December report from analytics firm Wood Mackenzie and the Solar Energy Industries Association trade group — the market’s first annual drop in at least four years.
“When interest rates began to really escalate, more than two years ago, it put a damper on demand for residential solar across the United States,” said Pavel Molchanov, investment strategy analyst at financial services firm Raymond James. “The cost of capital for residential solar correlates with what’s happening with the broader interest-rate environment.”
The Federal Reserve started cutting rates last fall. But the economic and trade policies instituted by President Donald Trump have raised fears of a potential economic downturn and increasing inflation, tamping down expectations of near-term interest rate cuts.
Among different types of solar power, “residential solar is near the high end of the spectrum” in terms of its sensitivity to interest rates, Molchanov added.
That’s in part because residential rates tend to be higher from the start. Unlike utility-scale solar projects, which are backed by power purchase agreements from utilities or large corporate customers, residential projects are “ultimately tied to individual homeowners,” Molchanov explained, increasing the perceived risk of default — and raising the interest rates they are offered as a result.
Sunnova CEO John Berger said in a Monday statement that the company has “acted on several initiatives” to improve its financial picture, including “raising price, simplifying our business to reduce costs, and changing dealer payment terms,” which are intended to “support positive cash in 2025 and beyond.”
But Sunnova’s financial position may make it difficult for the company to raise the capital it needs, at least at reasonable terms. The company stated on Friday that it had secured a $185 million loan at a 15% interest rate, which is well above typical corporate borrowing rates, to use for “general working capital purposes.”
The interest-rate environment has helped drive a number of residential-solar companies into bankruptcy in the past two years, including SunPower, one of the country’s oldest solar companies. Some of SunPower’s assets have been bought by residential installer Complete Solaria.
Sunrun, the country’s largest residential solar and battery installer, also reported declining revenue and increasing losses in 2024 compared to the previous year in an earnings statement last week.
Beyond interest rates, Sunnova and other residential-solar installers have had to contend with a dramatic shift in California’s residential-solar policy, Molchanov said. The state is by far the largest rooftop-solar market in the country.
In April 2023, California regulators sharply reduced the net-metering rates that owners of rooftop solar systems can earn for the electricity they feed back to the power grids operated by the state’s three large investor-owned utilities. Residential solar installations have dropped sharply since that change, and many solar companies in the state have laid off workers or closed their doors.
California’s cutback on net metering “put a damper on demand, compounding the effect of high interest rates,” Molchanov said. Residential-solar sales in the state have grown slightly in recent quarters but remain far from their pre-2023 highs, according to the California Solar and Storage Association trade group.
Residential solar could be hampered further by the Trump administration and Republican-controlled Congress.
After Trump’s election, publicly traded clean-energy companies including Sunrun and Sunnova took hits in the market due to fears that the president’s antipathy to climate and clean-energy policy could drive Congress to undo or weaken federal tax credits that play a central role in boosting the economics of solar power. Trump’s decisions on tariffs could also raise the cost of solar systems.
Sunnova has itself previously been targeted by Republicans in Congress. In 2023, the company won a $3 billion loan guarantee from the U.S. Department of Energy to support its effort to lower consumer costs for financing “virtual power plants” — solar systems bolstered by batteries that can help reduce peak energy.
Rising electricity costs are one of the few tailwinds for residential solar, Molchanov said. Utility rates have been climbing in many parts of the country, which can make generating one’s own electricity more attractive by comparison. More households are also looking to residential systems for reliability purposes, choosing to pair batteries with solar to provide power during grid outages.
“But the No. 1 variable we need to watch is interest rates,” Molchanov said. “The higher they go, the more difficult it will be for residential solar in the aggregate in this country.”
Since 2017, sweeping legislation in Illinois has sparked a solar-power boom and launched ambitious energy-equity and green-jobs programs.
Now, for the third time in under a decade, state lawmakers, advocates, and industry groups have their sights set on ensuring that clean energy momentum.
The focus this legislative session is the electric grid. Stakeholders worry the state’s clean energy progress will stagnate if it can’t expand and fortify its infrastructure for moving and storing electricity.
Advocates are backing a wide-ranging bill known as the Clean and Reliable Grid Affordability Act, or CRGA, which they describe as the successor to the 2017 Future Energy Jobs Act and the 2021 Climate and Equitable Jobs Act. Solar and energy-storage industries are backing another bill that includes even more ambitious goals for building out new transmission and energy storage.
There’s widespread agreement that Illinois’ current grid is not ready for the state’s mandated transition to 100% clean energy by 2050, especially as overall electricity demand climbs thanks to the proliferation of data centers in Illinois. As in other states, Illinois’ long interconnection queues and lengthy transmission planning processes through the regional transmission organizations make it hard to connect renewable energy sources.
CRGA, introduced Feb. 7, aims to make more efficient use of existing grid infrastructure through a transparent audit of the current system and the adoption of grid-enhancing technologies. It would facilitate new transmission buildout by making it easier for merchant transmission developers to get state permits and by allowing high-voltage transmission lines to be built in highway rights-of-way. It also calls for 3 gigawatts of new energy storage to be added to the grid.
“Transmission is crucial to a reliable and affordable grid because it allows us to move clean energy from place to place and be more resilient in cases of extreme weather,” said James Gignac, Midwest policy director for the Union of Concerned Scientists’ climate and energy program.
The industry-backed transmission and storage bill (HB 3758), introduced Feb. 7, calls for 15 GW of new energy storage, which the bill’s backers say would save consumers $2.4 billion over 20 years. The bill calls on the Illinois Power Agency, which procures energy for the state’s utilities, to also procure energy storage. Gignac said studies by advocacy groups indicate 3 GW of storage is sufficient for the near-term. Both industry and advocacy groups backed a “skinny bill” that passed in the legislature’s January lame-duck session, launching an analysis of energy storage needs by the Illinois Commerce Commission, due on May 1.
Stakeholders generally agree that new energy legislation is especially crucial given the Trump administration’s rollbacks to clean energy incentives and mandates.
“A lot of federal funding we just don’t know the future of, so the role of states and local governments is more important than ever now,” said Jen Walling, executive director of the Illinois Environmental Council.
Illinois does not do the type of comprehensive planning for energy use and transmission that electric utilities do in states with vertically integrated energy markets. In Illinois, separate companies generate and transmit electricity, with the idea that the open market will match supply with demand. But experts say centralized planning is necessary to ensure that clean energy can meet the state’s needs.
“The market is not necessarily going to get us where we need to go on resource adequacy and reliability,” said John Delurey, Midwest deputy program director of the advocacy group Vote Solar.
CRGA calls on the state to undertake a clean-resource planning process involving the commerce commission, state Environmental Protection Agency, and Illinois Power Agency, similar to what utilities in other states do with integrated resource plans.
The bill also mandates public studies of the grid to determine where it is underutilized and how the latest technology could more efficiently move electrons around — increasing the grid’s capacity without building new wires.
“A lot of incumbent transmission owners have confidence in their traditional approaches and tend to rely on those” instead of adopting new grid-enhancing technology, said Gignac. As an example, he pointed to software that can help grid operators reroute power through less congested pathways, a tool reminiscent of Google Maps for road traffic.
“There’s potentially a financial disincentive for [companies to embrace] some of these technologies,” Gignac added, “because they can often be cheaper solutions” than building new transmission, which earns companies a guaranteed profit from ratepayers. Clean energy advocates say more transmission lines are needed, but they want a comprehensive study to know exactly where and how much.
“We are at a point in transition where we have to get even more precise,” said Delurey. “That precision is crucial for affordability. How do we make sure we build exactly what we need? No more, no less.”
Last year, companies hoping to build new high-voltage transmission in Illinois backed a proposal for creating renewable energy credits to incentivize it, similar to those that helped Illinois grow its solar capacity manyfold to over 3.5 gigawatts in less than a decade since the passage of the Future Energy Jobs Act.
CRGA does not include such incentives, but it would make it easier for companies that have not previously built transmission in Illinois to get authority from state regulators to do so, Gignac explained.
This could help the company Soo Green construct its planned 350-mile underground transmission cable connecting Iowa and Illinois. Such merchant transmission lines don’t have to go through the lengthy bureaucratic process that new projects built through regional grid operators’ planning programs do.
Meanwhile, both CRGA and the industry-backed storage bill would create a virtual-power-plant program, wherein companies would aggregate and market the capacity of individual batteries owned by residents, businesses, industries, and even vehicles plugged into the grid.
CRGA would also create an Illinois Storage for All program, mirroring the existing Illinois Solar for All initiative, which helps income-qualified customers, nonprofits, and government entities get solar for little or no cost. The same pot of state funds could subsidize batteries for residents, schools, churches, and others.
“That person is now a resilience hub for the neighborhood,” said Delurey. “Neighbors can come over and stay cool in summer, keep medicine cold in the fridge. For the nonprofit and public facility program, it’s the same idea on a larger scale.”
The bill also greatly expands energy-efficiency mandates for the state’s electric and gas utilities. It increases the amount of energy savings that electric utilities are required to achieve each year to the equivalent of 2% of their annual sales. The utilities do this through funding programs like home weatherization and subsidized efficient appliances.
Under the legislation, downstate utility Ameren would have to meet the same targets as Chicago-area utility ComEd, closing a gap between the utilities’ requirements. It would also more than double the savings mandates for natural gas utilities, and it would end the current ability of large industrial users to opt out of paying into a fund for energy efficiency.
“These are important ways to be moving the needle and prioritizing affordability across the board and even more so for Illinoisans who are financially challenged, historically disadvantaged,” said Kari Ross, Midwest energy affordability advocate for the Natural Resources Defense Council. “Investment in energy efficiency is critical for affordability and … getting the grid reliable and moving toward a clean energy future.”
CRGA has planning requirements and transparency mandates specifically for rural cooperatives and municipal utilities. This is especially important since residents who are member-owners of those entities may understand little about contracts they get locked into, said Andrew Rehn, climate policy director of the Prairie Rivers Network, an environmental group in downstate Illinois. One example of such an agreement is the highly controversial and financially troubled Prairie State Energy Campus, a massive coal plant.
“It’s good governance, trying to make sure the way cooperatives are operating is transparent and interested members can have clear pathways to engaging, understanding what’s going on, having a voice,” Rehn said.
“We think if they did some of this planning we’d see different outcomes. We would be looking at a more diverse portfolio,” changing the fact that “a lot of these municipal utilities and co-ops are still on coal, [and] they will be the last in the state still on coal.”
Two separate bills have been introduced related to the municipal-utility and rural-cooperative transparency demands and to help muni and co-op customers more easily install solar. A Solar Bill of Rights for such customers was also introduced last year.
Advocates say they expect energy bill negotiations to continue throughout the spring session, as they try to gain industry support for CRGA and add elements — like provisions related to data centers — that were discussed but not included in the current legislation.
“In a Trump world nothing feels certain,” said Rehn. “But this feels real. This is the state being able to set our own direction and offset a lot of the horrible things that are going to happen on the federal level. It’s a way we can fight back and do important climate and community-focused work.”
A 67-person Finnish startup called Hycamite has just completed a facility it hopes will revolutionize production of low-carbon hydrogen.
The plant, in the industrial port city of Kokkola, on Finland’s west coast, will soon receive gas shipments from a nearby liquefied natural gas import terminal and turn the fossil fuel into hydrogen. That in itself is not novel — pretty much all of the world’s commercially produced hydrogen comes from methane, the main ingredient in natural gas. But all those legacy hydrogen producers end up with carbon dioxide as a byproduct, and they vent it into the atmosphere, exacerbating climate change. Hycamite will make hydrogen without releasing CO2, using a little-known process called methane pyrolysis.
“We split the methane with the help of catalysts and heat — there’s no oxygen present in the reactor, so that there’s no CO2 emissions at all,” founder and Chairman Matti Malkamäki told Canary Media in a December interview. “We are now entering industrial-scale production.”
Hycamite’s Customer Sample Facility in Kokkola can produce 5.5 tons of clean hydrogen per day, or 2,000 tons per year, Malkamäki said. Instead of creating carbon dioxide as an inconvenient gaseous byproduct, pyrolysis yields solid carbon. Hycamite uses catalysts developed over 20 years by professor Ulla Lassi at the University of Oulu, which transform the methane into “carbon nanofibers with graphitic areas.” This solid carbon can be processed further to produce graphite that Malkamäki plans to sell to battery manufacturers and other high-tech industries.
Hycamite closed a $45 million Series A investment in January to fund operations at the hydrogen plant. But it’s just one of a growing cluster of climatetech startups betting that the dual revenue stream of hydrogen and useful carbon products gives them an edge in the nascent marketplace for clean hydrogen, a much-hyped, little-produced wonder fuel for solving tricky climate problems.
Low-carbon hydrogen theoretically could clean up emissions-heavy activities like long-distance trucking, shipping, steel making, and refining — if anyone can manage to make it, at volume, at prices that compete with the dirty stuff that’s already available. In the U.S., some hydrogen producers and fossil fuel majors have talked about retrofitting carbon-capture machinery onto existing hydrogen plants, but nobody’s built a full-scale “blue hydrogen” operation so far. Renewables developers have evangelized “green hydrogen,” which is made by running clean electricity through water to isolate hydrogen, but they need electrolyzers and the production of clean electrons to get considerably cheaper. Until then, they’ll depend heavily on government policy support.
Now President Donald Trump is treating Joe Biden’s suite of clean energy policies like a piñata, and it’s hard to tell if incentives for producing green hydrogen will even survive. That’s already scaring off investors from large, capital-intensive green hydrogen projects. But the up-and-coming pyrolysis crew could find a niche: Their projects are smaller and nimbler, and they consume natural gas, one sector that Trump has ordered his government to encourage.
Methane pyrolysis entrepreneurs like Malkamäki are heeding the call of fundamental chemistry.
“Thermodynamically, it’s far more energy-favorable to split methane than to split water,” said Raivat Singhania, a materials scientist who scrutinizes hydrogen startups at Third Derivative, a clean energy deep-tech accelerator. Water’s chemical bonds hold together more fiercely than methane. That means companies trying to make clean hydrogen by splitting water need huge amounts of electricity to overcome the strength of its bonds; sourcing that electricity creates a daunting cost and a logistical hurdle.
Not only does methane-splitting require less energy, it can be done with a simpler plant design than water electrolysis, using fewer moving parts or fragile pieces of equipment, Singhania noted. This analysis informed Third Derivative’s investment in Aurora Hydrogen, which breaks methane using microwaves.
Those thermodynamic advantages come with tradeoffs. Namely, would-be methane pyrolyzers need a ready source of methane, which in practical terms means a pipe delivering fossil gas. That inevitably entails some level of upstream emissions.
Methane pyrolyzers also need to be located where gas is abundant. It’d be hard to scale up in places like Europe, post Russia’s invasion of Ukraine, or Massachusetts when winter rolls around. But supply is ample across much of the U.S., which is producing more fossil gas than any country ever. Hycamite is building its commercial test facility in its home base of Finland, but the company is looking to the U.S. to deploy its technology, Malkamäki said.
Right after taking office in January, Trump responded to world records in U.S. fossil fuel production by declaring an “energy emergency” and ordering his administration to clear the way for even more fossil fuel extraction.
It’s not clear whether the fossil fuel industry can or wishes to increase production dramatically; in market-based systems, excess supply tends to deflate prices. Whether production stays at current record highs or pushes further skyward, the U.S. will have plenty of gas to go around, and methane pyrolysis companies could generate the kind of new demand that the industry desperately needs. Moreover, they would be using American fossil fuel abundance to create materials useful for the transition to clean energy.
For that to happen, though, pyrolysis startups need to break through early technical demonstrations and start producing at scale.
Hycamite is not the only company chasing the pyrolysis dream.
The American startup Monolith is arguably furthest along in the quest to turn laboratory science into industrial-scale production. It uses high-heat pyrolysis to produce hydrogen and a dark powdery substance called carbon black, an additive used in tire and rubber manufacturing.
Monolith received a conditional $1 billion loan from the Department of Energy in late 2021 to build out its facility in Nebraska, which would deliver clean hydrogen to decarbonize fertilizer production. Monolith had to run a gauntlet to prove to DOE’s Loan Programs Office that it deserved such a loan. It has the rare distinction among pyrolysis startups of having actually sold its carbon products: Goodyear makes a tire for electric vehicles using Monolith’s carbon black.
However, Monolith did not finalize the loan before the Trump administration came to office and froze new disbursements for clean energy. The company was running short on cash while struggling to get its high-heat process to work reliably around the clock, per a Wall Street Journal article published in September. Monolith secured additional financing from its investors just before that story published.
Several other startups want to boost their revenues by turning methane into higher-value forms of carbon than carbon black, a relatively inexpensive commodity — if they can achieve the quality and consistency necessary to sell into those specialized and demanding markets.
A group of Cambridge University scientists founded Levidian in 2012 to create reliable, large-scale production of graphene, a carbon-based supermaterial discovered in Manchester, England, in 2004. After another eight years of research and development under the moniker Cambridge Nanosystems, the company was acquired and brought to market by a British entrepreneur.
Levidian eschews the catalysts, heat, and pressure that other startups use to split methane. Instead, the team ended up building a nozzle that sucks in methane gas, then uses electricity to generate microwave energy, which in turn creates a cold plasma torch that shaves carbon atoms from hydrogen atoms.
This yields hydrogen and graphene, which can be used in semiconductors, electronics, and batteries. Levidian can sell graphene for hundreds of dollars per kilogram, far more than carbon black, CEO John Hartley told Canary Media in January. Indeed, the company will host its first graphene auction on March 24. To install its technology, though, Levidian has focused on customers who want to clean up their fossil gas emissions.
“It’s really an onsite carbon-capture unit at its core: It catches carbon, makes hydrogen, and decarbonizes methane gas,” Hartley said. The first customers include Worthy Farm, which hosts the Glastonbury music festival; a wastewater treatment plant in Manchester; and the Habshan gas processing facility in Abu Dhabi.
U.S.-based Etch builds on research by founder Jonah Erlebacher, a materials science professor at Johns Hopkins University. The startup splits methane with what it describes as a recyclable catalyst that contains no rare minerals; it produces graphite and other forms of carbon.
The Etch team is wrapping up commissioning for its first “commercial-scale pilot” in Baltimore, a spokesperson told Canary Media. Last fall, the startup brought in a new CEO with commercial chops: Katie Ellet previously served as president of hydrogen energy and mobility for North America at Air Liquide, one of the few companies actually producing low-carbon hydrogen at scale, and a key player in six of the seven hydrogen hubs funded by the Department of Energy.
All these companies need to hit their stride just as the clean hydrogen market has entered a period of tumult.
The Biden administration hoped to jump-start a clean hydrogen economy with two major policies: A suite of billion-dollar grants to seven “hydrogen hubs” strategically chosen around the country, which are intended to link up production with entities that could use the fuel to clean up transportation and heavy industry, and a production tax credit to effectively lower the market price of hydrogen produced using low-carbon methods.
Now, the Trump administration has frozen payments on clean energy grants and loans. Prospective hydrogen producers had been waiting breathlessly for the final IRS guidance on the 45V tax credit; now that the lawyers have finally produced that guidance, the nascent hydrogen industry has to plead with the new administration to preserve those credits as it overhauls federal spending this year.
Given this swirling uncertainty, pyrolysis startups can take some solace in the fact that their business is not entirely dependent on the vagaries of hydrogen policy. At least they can sell carbon materials, which have clear value and established buyers who use the stuff in a non-theoretical way.
I asked Malkamäki if Hycamite identifies as a carbon company that also makes hydrogen or a hydrogen company that also makes carbon. He pointed out that the company name itself is a mashup of “Hy-” for hydrogen and “ca-” for carbon (and the -mite is a reference to a fanciful super-fuel that Donald Duck invented in a vintage comic strip). The revenues from the carbon products are “elementary for us to be profitable,” he said. “A couple of investors have said to us that hydrogen makes you sexy, carbon makes you money.”
That’s not to suggest breaking into the battery supply chain will be easy. It requires passing rigorous, multi-year testing by the battery makers that might buy Hycamite’s carbon products. But this kind of revenue can bolster a young business as it rides out the storm in Washington.
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