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Everyone agrees that California’s major utilities are charging too much for electricity. But as in previous years, state lawmakers, regulators, and consumer advocates are at odds over what to do about it.
With the state’s three biggest utilities reporting record profits even as customers’ rates have skyrocketed, critics say the time is right to pass laws that will force regulators to more tightly control key utility costs — or even outright curb utility spending and profits.
Customers of Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric now pay roughly twice the national average for their power, with average residential rates rising 47% from 2019 to 2023, according to a January report from the state Legislative Analyst’s Office.
Rates are set to climb even further in the coming years as utilities look to expand their power grids to meet growing demand from data centers, electric vehicle charging depots, and millions of households buying EVs and heat pumps. Utilities also need to build high-voltage transmission lines to connect far-off clean energy resources to population centers. And they need to harden and protect thousands of miles of low-voltage power lines to prevent deadly wildfires in a landscape that’s growing more susceptible to conflagration because of climate change.
Utilities are allowed to earn a profit on these infrastructure investments and to pass the costs onto customers — but only within reason. It’s the job of regulators to ensure that profits aren’t disproportionate to what utilities charge ratepayers.
Consumer advocates are now demanding that the California Public Utilities Commission be more aggressive in challenging PG&E, SCE, and SDG&E’s spending plans, which have allowed them to earn more profits than ever over the past year. In October, Gov. Gavin Newsom (D) ordered the CPUC to issue a report on how to curb rate increases.
“There’s agreement that record-breaking shareholder earnings make no sense along with skyrocketing costs,” said Mark Toney, executive director of The Utility Reform Network (TURN), a ratepayer advocacy group, and that “utilities need to be held more accountable for their spending.”
TURN is supporting a list of bills being introduced in this year’s legislative session that take aim at utility costs. Some would increase state regulator oversight on utility grid spending. Others seek to forbid utilities from spending ratepayer funds on lobbying and advertising and strengthen CPUC oversight of potential “double recovery,” or utilities collecting funds for projects already financed via other means.
Beyond TURN’s list of favored bills, there are more aggressive legislative proposals that would limit utility rate increases to no higher than the general rate of inflation and force utility shareholders to pay more into a state fund created to shelter utilities from bankruptcy as a result of having to pay for catastrophic wildfires caused by their equipment. PG&E was forced into bankruptcy in 2019 under these conditions after a failure of one of its power lines sparked the state’s deadliest-ever wildfire in 2018.
Legislation that would order the CPUC to increase oversight of utility spending or limit the costs utilities can pass on to customers faces an uphill battle. Last year, a number of reform proposals faltered in the face of heavy lobbying from utility workers unions and pushback from utilities, which spend generously on state political campaigns.
But with customers of California’s three big utilities now paying the highest rates in the nation outside Hawaii and one in five California households struggling to pay their monthly bills, the public pressure to do something may outweigh utility lobbying muscle, advocates say.
Last month, the California state Senate Energy, Utilities and Communications Committee held a legislative hearing where the CPUC briefed lawmakers on its new report on how to contain rate increases.
That report shied away from suggesting major clawbacks in utility spending or limiting profits. Instead, it focused on shifting some costs now passed through to ratepayers — including payments to customers who have rooftop solar, wildfire mitigation and recovery investments, and programs that boost energy efficiency and help low-income customers pay their bills — to “other sources of funding.” That could include state taxpayers, California’s cap-and-trade program, or customers of publicly owned utilities.
All of these proposals would require legislative action, and some lawmakers pushed back on the idea that utilities should be able to shift costs that are their responsibility under law. But CPUC President Alice Reynolds said the alternative — forcing utility shareholders rather than ratepayers to bear more costs — could violate legal precedents that allow utilities a “reasonable rate of return to attract investment in the system,” as she put it.
State Sen. Josh Becker (D), chair of the committee, said during the hearing that legislative leaders and Gov. Newsom’s office plan to put together a bill focused on energy affordability in the coming months.
Toney said he’s hopeful this affordability package “has some of the proposals that went down at the last minute last year, and that there’s going to be a lot more support for them” this year. But he was also critical of the CPUC’s report. “I’ll tell you what was missing” from it, he said — “any conversations about utility profits.”
PG&E, the state’s biggest utility, has reported record-breaking profits over the past two years. The average customer bill increased more than 35% between 2021 and 2023, and CPUC approved six PG&E rate hikes in 2024. The utility’s rates will increase again this year to cover the cost of keeping the Diablo Canyon nuclear power plant open.
SCE, the state’s largest electric-only utility, reported record-setting profits in 2024, after winning CPUC approval for rate hikes last year. Another rate hike was approved in January.
SDG&E reported profits near its all-time high last year after record-high profits in 2023 and 2022. The utility’s rates have increased to become among the highest in the nation, as shown in this chart from the state Legislative Analyst’s Office.
The CPUC’s report stated that “the biggest drivers of rate increases” are “the growth in spending to address wildfire mitigation” as well as “the cost shift that results from legacy Net Energy Metering programs,” which compensate customers with rooftop solar systems for electricity they send back to the grid. The CPUC delegated to secondary status the costs of “energy transition related investments in transmission and distribution infrastructure.”
But rooftop solar incentives don’t deserve most of the blame for rising rates, said Loretta Lynch, an attorney and energy policy expert who served as CPUC president from 2000 to 2002. She is also a longtime critic of the current CPUC commissioners appointed by Gov. Newsom.
Instead, she said during a February webinar presenting new data on the connection between utility spending and rising rates, “the primary drivers of a vast majority of the costs over the last five to 10 years have been extraordinary procurement” of clean energy at the early stages of the state’s energy transition, when solar power was far more expensive than today, and, more notably, “the tripling of the costs of transmission and distribution” grid investments over the past decade.
Other energy analysts, including some who strongly disagree with Lynch’s views on rooftop solar, share this perspective on the grid’s role in driving up utility costs.
Severin Borenstein, head of the Energy Institute at the University of California, Berkeley’s Haas School of Business, is a major backer of the proposition that rooftop solar is causing bills to rise for other customers. He reiterated that position in a February presentation to the Little Hoover Commission, an independent state oversight agency, noting the significant costs of “public purpose programs,” such as the billions of dollars that utility customers at large pay to support rooftop solar incentives and low-income ratepayer assistance.
But Borenstein also said a majority of the rising utility costs over the past decade are tied to investments in low-voltage distribution grids and wildfire hardening and prevention.
“Those last two sort of meld together because we’re spending a whole lot of money on upgrading our distribution network, reinforcing our distribution network, in some cases, under-grounding it, in order to reduce wildfires,” he said.
The below chart from the CPUC’s February report highlights the majority of costs that come from paying for electricity generation and maintaining the utilities’ sprawling low-voltage distribution grids.
Borenstein agrees with the CPUC that rooftop solar incentives make up a significant portion of rising utility rates — a view that’s disputed by solar and environmental advocates. But even when the costs of net metering are calculated in the way that the CPUC proposes, they still make up a relatively small portion of typical residential utility customer bills compared to the “other” category that includes generation and grid costs, as the below chart from the Legislative Analyst’s Office report shows.
The Natural Resources Defense Council, one of the few environmental organizations that strongly favors reducing rooftop solar compensation, issued a report this week proposing a host of ways to reduce PG&E’s rates, including shifting those costs away from ratepayers. But NRDC also found that the “largest contributor to PG&E’s skyrocketing rates is the cost of vegetation management and hardening the grid to prevent wildfires,” making up more than half of the utility’s rate increases above the rate of inflation since 2018.
Going after those costs is tricky, however. When it comes to generation, utilities can’t back out of contracts for expensive power, even if they were signed more than a decade ago. Nor can they avoid buying power on the state’s energy markets during times when those prices spike.
Tackling grid costs puts regulators and lawmakers in a bind as well. Nobody wants utilities to skimp on critical investments like replacing aging equipment or protecting power lines from being knocked down by trees or high winds. Efforts to police utility grid investments risk forcing regulators and utilities to spend lots of time and effort delving into the minutiae of those plans without any clear promise of savings to show at the end of it.
Even so, Toney highlighted several bills being proposed this year, and others he hopes will be revived from last year’s session, that could drive down some of these costs.
On wildfire-related expenditures, he’d like to see a new bill that revives the policies proposed by SB 1003, a bill that failed to pass last year. The bill would have instructed the CPUC to limit utility wildfire spending outside of closely examined plans and put utility wildfire planning more squarely under the commission’s control.
Another option to address utility spending is AB 745, a bill that would increase state oversight of utility transmission grid upgrades. Energy analysts argue that a regulatory gap between federal and state authority over certain types of smaller grid projects has led to utility overspending on those projects. AB 745 cites a CPUC report that found $4.4 billion in transmission investments by California’s big utilities between 2020 and 2022, or nearly two-thirds of total grid spending, fell into this category.
California could also find other ways to pay for grid investments, Toney said. Those options can include securitization — having a utility issue bonds backed by the steady stream of payments its customers make on their bills — or the state issuing bonds to pay for certain utility costs. Both replace a portion of costs that are passed on to ratepayers, which “saves money because there’s no shareholder profit to be made,” he said.
SB 330, a bill proposed by state Sen. Steve Padilla (D), would authorize the state to “pilot projects to develop, finance, and operate electrical transmission infrastructure” via “low-cost public debt and alternative institutional models.” California will need to spend an estimated $45.8 billion to $63.2 billion on transmission by 2045, and an October report from the nonprofit Clean Air Task Force found that such public financing options could annually shave billions of dollars from rate increases in future years.
Some consumer advocates say lawmakers and regulators need to go after rising rates directly by limiting the return on investment that utilities are permitted to pass on to customers. Utility critics say that’s the most direct way to halt rate increases.
It’s also the most likely to trigger major pushback from utilities.
“We need to reduce the utilities’ profits to the national average or perhaps tie those profits to increases in safety,” Lynch proposed during February’s webinar. “As long as our policymakers focus on the wrong problem, we won’t find the right solution to reducing customers’ punishing and unwarranted bills.”
These efforts are hampered by the complexity and volume of data that goes into calculating such returns on investment as well as the fact that utilities control all the data. Indeed, utility critics have noted that recent rate-increase requests from PG&E have been approved by the CPUC in a perfunctory manner, with little to no attempt to order the utility to prove its cost increases were warranted.
Lynch blamed CPUC commissioners. ”It’s a fundamental failure of regulation, but it’s also a fundamental failure of political will to require the regulators to do their job as written in the law,” she said.
Utility finance expert Mark Ellis agreed that the CPUC needs to cut utilities’ profits. As an independent consultant and senior fellow at the American Economic Liberties Project, Ellis published a January paper accusing utilities of using financial legerdemain to justify excessive returns on their investments — and regulators of violating their duty to hold utilities to account.
The regulatory compact between states and investor-owned utilities boils down to this, he told Canary Media: “We’re going to give you a monopoly, but we won’t let you charge monopoly rents. Anything above your cost of capital is a monopoly rent.”
In an opinion piece in the San Francisco Chronicle, Ellis argued that California’s investor-owned utilities have been earning far above the cost of capital for decades — an assertion he backs up from experience working as former chief of corporate strategy and chief economist at Sempra, the holding company of Southern California Gas Co. and SDG&E.
The Energy Institute’s Borenstein agreed during his February presentation that utilities have “some important perverse incentives for capital investment” and that “cost of equity is the big point of contention because it’s hard to know what you need to pay stock shareholders to get them to invest.”
At the same time, “I don’t blame the CPUC for this,” he said. “I think the CPUC is massively understaffed and undercompensated, and they are just overwhelmed with the many things that they are required to do with limited staff. And when they get into these rate-of-return hearings, the utilities are able to bring world experts in finance.”
Ultimately, he said, “the CPUC is really outgunned and outmanned.”
Some lawmakers are going after utility profits more directly. SB 332, a bill sponsored by state Sen. Aisha Wahab (D), would cap investor-owned utility rate increases for residential customers to no more than the Consumer Price Index, a federal measure of cost-of-living inflation. It would also make shareholders rather than ratepayers provide more of the funding for the state’s utility wildfire fund — a sensitive issue amid rising investor uncertainty regarding SCE’s potential liability for January’s devastating Eaton Fire. SB 332 would also tie utility executive compensation to safety metrics.
“This bill flips the script and puts utility profits on the table,” said Roger Lin, a senior attorney at the nonprofit Center for Biological Diversity, which supports the legislation. While he conceded the proposal will face serious pushback from utilities, “we have to start looking at the systemic causes of the affordability crisis we have today in California.”
Last May, Florida enacted a law deleting any reference to climate change from most of its state policies, a move Republican Gov. Ron DeSantis described as “restoring sanity in our approach to energy and rejecting the agenda of the radical green zealots.”
That hasn’t stopped the Sunshine State from becoming a national leader in solar power.
In a first, Florida vaulted past California last year in terms of new utility-scale solar capacity plugged into its grid. It built 3 gigawatts of large-scale solar in 2024, making it second only to Texas. And in the residential solar sector, Florida continued its longtime leadership streak. The state has ranked No. 2 behind California for the most rooftop panels installed each year from 2019 through 2024, according to data the energy consultancy Wood Mackenzie shared with Canary Media.
“We do expect Florida to continue as No. 2 in 2025,” said Zoë Gaston, Wood Mackenzie’s principal U.S. distributed solar analyst.
Florida is expected to again be neck and neck with California for this year’s second-place spot in utility-scale solar installations, said Sylvia Leyva Martinez, Wood Mackenzie’s principal utility-scale solar analyst for North America.
Overall, the state receives about 8% of its electricity from solar, according to Solar Energy Industries Association data. The vast majority of its power comes from fossil gas.
The state’s solar surge is the result of weather — both good and bad — and policies at the state and federal level that have made panels cheaper and easier to build, advocates say.
“Obviously in Florida, sunshine is extremely abundant,” said Zachary Colletti, the executive director of the Florida chapter of Conservatives for Clean Energy. “We’ve got plenty of it.”
The state is also facing a growing number of extreme storms. Of the 94 billion-dollar weather disasters that federal data show unfolded in Florida since 1980, 34 occurred in the last five years.
“Floridians have long understood that not only is solar good for your pocket, it’s also good for your home resilience,” said Yoca Arditi-Rocha, the executive director of The CLEO Institute, a Miami-based nonprofit that advocates for climate action. “In the face of increasing extreme weather events, having access to reliable energy is a big motivator.”
The tax credits available under former President Joe Biden’s Inflation Reduction Act have also made buying panels cheaper than ever before, she said.
“A lot of people took advantage of that. I’m one of them,” Arditi-Rocha said. “As soon as I saw that the federal government was going to give me 30% back on my taxes, I decided to make the investment and got myself a solar system that I could pay back in seven years. It was a win-win proposition.”
But solar started growing in Florida long before Democrats passed the IRA in 2022, and that’s thanks to favorable state policies.
Municipalities and counties have little say over power plants, giving the Florida Public Service Commission ultimate control over siting and permitting. Plus, solar plants with a capacity under 75 megawatts are exempt from review and permitting altogether under the Florida Power Plant Siting Act.
The latter policy in particular has made building solar farms easy and inexpensive for the state’s major utilities, said Leyva Martinez. Companies such as NextEra Energy–owned Florida Power & Light, the state’s largest electrical utility, have for years patched together gigawatts of solar with small farms.
“We’re seeing this wave of project installations at gigawatt scales, but if you look at what’s actually being built, it’s a small 74-megawatt [project] here or 74.9-megawatt project there,” she said. “It’s just easier to permit in the state, and developers have realized that they can keep installations at this range and they don’t need to go through the longer process.”
The solar buildout has prompted some backlash in rural parts of the state. A bill Republican state Sen. Keith Truenow filed last month proposes granting some additional local control over siting and permitting solar farms on agricultural land.
“You’re starting to see a lot more complaining about the abundance of solar installations in more rural areas,” Colletti said. The legislation, he said, “would add some hurdles and ultimately add costs” but “wouldn’t necessarily reverse the state’s preemption” of local permitting authorities.
NextEra and Florida Power & Light did not respond to an email requesting comment. Nor did Truenow return a call.
While the bill is currently making its way through the Legislature, DeSantis previously vetoed legislation that threatened Florida’s solar buildout.
In 2022, the governor blocked a utility-backed bill to end the state’s net metering program, which pays homeowners with rooftop solar for sending extra electricity back to the grid during the day.
“The governor did the right thing by vetoing that bill that would have strangled net metering and a lot of the rooftop solar industry in Florida,” Colletti said. “I know Floridians are much better off for it because we are able to offset our costs very well and take more control and ownership over our households.”
A telephone survey conducted by the pollster Mason-Dixon in February 2022 found that among 625 registered Florida voters, 84% supported net metering, including 76% of self-identified Republicans.
“It’s not about left or right,” Arditi-Rocha said. “It’s about making sure we live up to our state’s name. In the Sunshine State, the future can be really sunny and bright if we continue to harness the power of the sun.”
As winter turns to spring, Texas is setting new records with its nation-leading clean energy fleet.
In just the first week of March, the ERCOT power grid that supplies nearly all of Texas set records for most wind production (28,470 megawatts), most solar production (24,818 megawatts), and greatest battery discharge (4,833 megawatts). Only two years ago, the most that batteries had ever injected into the ERCOT grid at once was 766 megawatts. Now the battery fleet is providing nearly as much instantaneous power as Texas nuclear power plants, which contribute around 5,000 megawatts.
“These records, along with the generator interconnection queue, point towards a cleaner and more dynamic future for ERCOT,” said Joshua Rhodes, a research scientist studying the energy system at The University of Texas at Austin.
The famously developer-friendly Lone Star State has struggled to add new gas power plants lately, even after offering up billions of taxpayer dollars for a dedicated loan program to private gas developers. Solar and battery additions since last March average about 1 gigawatt per month, based on ERCOT’s figures, Texas energy analyst Doug Lewin said. In 2024, Texas produced almost twice as much wind and solar electricity as California.
When weather conditions align, the state’s abundant clean-energy resources come alive — and those conditions aligned last week amid sunny, windy, warm weather. On March 2 at 2:40 p.m. CST, renewables collectively met a record 76% of ERCOT demand.
Then, on Wednesday evening, solar production started to dip with the setting sun. More than 23,000 megawatts of thermal power plants were missing in action. Most of those were offline for scheduled repairs, but ERCOT data show that nearly half of all recent outages have been “forced,” meaning unscheduled.
At 6:15 p.m. CST, batteries jumped in and delivered more than 10% of ERCOT’s electricity demand — the first time they’ve ever crossed that threshold in the state.
“Batteries just don’t need the kind of maintenance windows that thermal plants do,” said Lewin, who authors the Texas Energy and Power newsletter. “The fleet of thermal plants is pretty rickety and old at this point, so having the batteries on there, it’s not just a summertime thing or winter morning peak, they can bail us out in the spring, too.”
At some level, the March records show clean energy excelling in the conditions that are most favorable to it. Bright sun and strong winds boosted renewable generation, while temperate weather kept demand lower than it would be on a hot summer or a cold winter day. But those seemingly balmy circumstances could belie a deeper threat to the Texas energy system.
“One thing that I don’t think is talked about nearly enough is the potential for problems in shoulder season,” said Lewin.
If unusually hot weather struck during a spring day with lots of gas and coal power plants offline, ERCOT could struggle to meet demand, even if it was much lower than the blistering summer peaks. In fact, this happened in April 2006, when a surprise heat wave forced rolling outages, Lewin noted. Texas officials don’t talk much about climate change, but that kind of hot weather in the springtime is becoming more common.
Last summer produced ample data on how the surge in solar and battery capacity reduced the threat to the grid from heat waves and lowered energy prices for customers. This spring, batteries and renewables are showing they can also fill in the gaps when traditional plants step back.
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.”
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.
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.”
A number of Connecticut cities and towns want to secure more clean electricity for residents using a program that has already saved millions of dollars for consumers in other states.
Community choice aggregation allows cities and towns — or, in some cases, multiple municipalities working together — to negotiate with electricity suppliers on behalf of their residents. The goal is to achieve lower rates than those offered by utilities, often with a higher percentage of renewable energy in the mix.
“Municipalities can play a bigger role in using less electricity, using it more efficiently, and reducing the cost,” said Peter Millman, vice president of People’s Action for Clean Energy, a Connecticut nonprofit that supports community choice aggregation. “I hate to see an opportunity wasted.”
Nationally, community choice aggregation, also known as municipal aggregation, is authorized by ten states, including Northeast neighbors Massachusetts, New Hampshire, New Jersey, New York, and Rhode Island. Connecticut could become the eleventh: The state legislature is now considering a bill, HB 6928, that would allow municipalities to create these programs. The measure has wide support from environmental groups and municipal leaders.
Data suggest there are opportunities for meaningful savings. In Massachusetts, 225 of the state’s 351 cities and towns had approved municipal aggregation programs as of July 2024, and many include a higher percentage of renewable energy than required by law. In one group of communities, households realized an average of $200 to $237 in annual savings while receiving electricity with 5% to 11% more renewable power content than state requirements, according to an analysis from the Green Energy Consumers Alliance, a nonprofit that helps municipalities create aggregation programs.
“History shows that when a community aggregates consumers for the supplier side, good things happen,” said Larry Chretien, executive director of the organization. “It’s a fallacy that you can’t have greener power without paying more.”
Connecticut’s version of aggregation could be particularly ambitious, following a model used in California and New Hampshire. This approach allows cities and towns to choose between a basic aggregation program, in which a hired energy broker negotiates for electricity on behalf of residents, and a system in which multiple municipalities band together to form a larger aggregator that could handle the process of procuring power itself.
The multi-community approach allows these aggregation groups to retain the revenues that would have gone to an outside broker and use these reserve funds to develop and manage their own programs aimed at producing renewable energy, supporting energy efficiency, or reducing demand. In its first year, New Hampshire’s aggregation program saved ratepayers in participating communities about $14 million and created revenue of $10 million for reinvestment.
In California, this strategy has helped fund dozens of programs including battery rebates, electric vehicle charging infrastructure, and discounts on solar power for low-income households.
Some skeptics of community choice aggregation have raised concerns about Connecticut’s proposed model, which would make a city or town’s negotiated rate the default for residents but allow them to opt out if they’d rather stick with utility service or an alternate supplier. Consumers, they say, should not be placed in a new program without choosing to make the move.
Supporters, however, argue that the successes in states where municipal aggregation has already been deployed demonstrate the model works with little risk to consumers.
“The opt-in model simply doesn’t work,” Millman said at a legislative committee hearing last week. “If these aggregations were not meeting or beating utility rates most of the time, there would be lots and lots of defections — and there are not.”
The numbers are in, and clean energy is set to sweep U.S. power plant construction yet again this year.
The U.S. is expected to build 63 gigawatts of power plant capacity this year, more than it has in decades, as new AI computing and domestic manufacturing projects cause a surge in energy demand. At this crucial juncture, plants that don’t burn fossil fuels are set to deliver 93% of all the new capacity joining the U.S. grid in 2025, per new estimates from the federal Energy Information Administration.
The new prediction is no fluke — carbon-free sources delivered nearly all the new capacity last year, too. And the trend was building for years before that.
This year, utility-scale solar is expected to continue its winning streak as the largest source of new electricity generation. More than half of new power plant capacity built this year will be solar, followed by batteries, with 29% of total capacity. That’s a step up for batteries from last year. Meanwhile, solar’s share is forecast to fall, but EIA expects more construction in absolute terms — 32.5 gigawatts compared to 30 last year.
Wind will add 12% of the new capacity, burnished by two major offshore wind projects the EIA still expects to come online despite political headwinds: Massachusetts’ 800-megawatt Vineyard Wind 1 and Rhode Island’s 715-megawatt Revolution Wind. The Trump administration unilaterally halted federal permitting for new offshore wind projects, but these are among the five that were already under construction, with necessary permits in hand.
This dominant showing from clean energy developers leaves natural gas with just 7% of new power capacity. That fossil fuel still leads in total U.S. electricity generation with about 42% of the mix but has entered a multi-year slump in terms of new construction.
The EIA predicts total gas-fired generation — the actual electricity produced — will fall 3% this year while solar generation rises by more than one-third.
This dataset offers a snapshot of where the U.S. power industry is heading — and the direction is toward cleaner, cheaper energy that mainly comes from solar and batteries.
But beyond the climate metrics, these clean power plants are proving vital in meeting the needs of an increasingly power-hungry economy. Data centers, AI hubs, and the domestic manufacturing that grew during the Biden administration all need more electricity. Renewables and batteries are the source of energy that can meet this demand most quickly and cost-effectively, though they still need to work alongside other resources to ensure 24/7 service.
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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