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California’s Democratic candidate for governor, Xavier Becerra, is borrowing a page from Australia with a new plan to give state residents free electricity during certain parts of the day.
Last week, Becerra unveiled a proposal to offer up to two free hours of electricity per day, starting with low-income families. He estimates it could save households about $1,000 per year.
The idea could find traction with restive voters in the Golden State. Power prices in California have risen by 46% in the last decade, the largest increase in the nation. And energy affordability has become a top issue at the ballot box nationwide.
The program, which he calls “Power Hour,” aims to help Californians soak up more of the state’s copious solar energy.
“We produce so much solar energy … that oftentimes in the afternoon we can’t make use of all of it, and so it essentially goes to waste,” Becerra said at a Politico event last week. Solar power can become so abundant that wholesale electricity prices dip into the negative, meaning that producers will pay others to take the excess off their hands. The state throws away what it can’t consume or store for later with batteries.
Becerra’s plan could send a strong market signal to consumers to take full advantage of the state’s solar riches, he explained to his California audience. “The best way to get you to readapt, to recalibrate, is to tell you the best time for you to use electricity today,” he said, giving as an example a free-power period between 1 p.m. and 3 p.m.
Some energy retailers in Australia started offering free-power plans years ago to take advantage of the solar power flooding the grid.
Thanks to a push from the Aussie federal government, now millions more can access the scheme, known as Solar Sharer. As of last month, households with smart meters in three of the country’s six states can sign up for rate plans that offer free power in the middle of the day. For example, in New South Wales and Queensland, the energy bonanza is from 11 a.m. to 2 p.m.
The no-cost energy is capped at 24 kilowatt-hours per day — enough to cover the energy needs of a household of five, according to the Australian government. Anything beyond that the utility charges for.
While free power sounds like a great deal, it’s important to note that these plans don’t automatically guarantee lower electricity bills. Outside the free-power period, utilities can set higher-than-average rates to recoup costs — sometimes, much higher.
One of the largest retail providers in Australia, AGL, which serves more than 4 million customers, has a free-power plan with a peak rate that’s almost twice what it charges under its standard plan. The federal government provides an online tool to help consumers figure out whether switching to a plan with free power will actually save them money.
People who can shift a lot of their energy demand to the free period or cache the zero-cost power for later will benefit most. The Australian government is making that easier to do by providing a 30% discount on home batteries. (The U.S. had a similar incentive, a federal tax credit, until the Republican-held Congress and President Donald Trump axed it last year.)
More than half a million home batteries have been installed under the Aussie program. And thanks to cheap, high-tech electric vehicles out of China, households increasingly have battery behemoths in their driveways. EVs now make up a quarter of new car sales on the continent.
Existing California programs could give Becerra’s plan a big boost. Qualified households could get a generous home-battery incentive of up to $1,100 per kilowatt-hour. And the state is rolling out a $3,500 EV rebate for first-time buyers.
Some experts doubt a free-power program can be as effective in California as it is shaping up to be in Australia.
“I applaud the intent here to change human behavior,” said Saul Griffith, CEO of Otherlab and founder of electrification advocacy nonprofits Rewiring America, Rewiring Australia, and Rewiring New Zealand. “But unless this [plan] really goes along with more comprehensive electricity market and pricing reform, it may not mean that much.”
Electricity could be far more affordable if Americans unleashed clean, cheap, distributed power, Griffith contends. But to do that, “you have to break the single-utility monopoly model,” he said.
Severin Borenstein, faculty director of the Energy Institute at the University of California, Berkeley’s Haas School of Business, also had a mixed reaction to Becerra’s plan.
“I do think this would be a step in the right direction, making electricity prices more accurately convey the cost of supplying the electricity in a given hour,” Borenstein said in an email. “But it would require making up the revenue shortfall somehow, which I fear would be done by raising prices in other hours.”
The vast majority of what utilities charge customers for is not the electricity itself but fixed system costs, according to Borenstein. “Those costs would still need to be covered,” he noted.
If elected, Becerra can’t implement his plan by fiat. He said he would work with the public utility commission, utilities, and other stakeholders to realize his plan within his first year in office.
Despite the uncertainties, Michael Rochmes, policy and advocacy manager at the nonprofit U.S. Green Building Council California, is excited to see Becerra’s Power Hour take shape.
The prevailing narrative has been that electricity is expensive, and costs are ballooning faster than inflation, he said. But that story leaves out how renewables and battery storage can deliver “long-term energy abundance,” Rochmes noted. “If this idea can break through and get people who aren’t in the energy space to start to understand the benefits of electrification, load shifting, battery storage, and renewable energy, I think this is a huge win.”
Next-generation geothermal projects are underway in the U.S. West, but states will need more targeted policies for the industry to scale, a new report argues.
Next-generation geothermal energy has massive potential in the western United States, but it won’t be realized unless developers can overcome the big economic barriers these novel systems face.
Unlike traditional geothermal plants, next-gen projects use innovative underground techniques to produce power wherever rocks are sufficiently hot, making it possible to harness heat in more locations. The energy source could provide hundreds of gigawatts of clean electricity around the clock, up from just 4 GW nationwide today.
Amid ballooning energy demand from data centers and electrification, western states are increasing their support for the industry, using tools like direct investment and permitting reform. These state-level efforts are supporting a wave of pilot projects and first-of-a-kind systems across the region, where heat is accessible at relatively shallow depths.
Still, states will need to adopt more sweeping and coordinated policies to help companies secure the kind of large-scale financing necessary to scale up next-gen geothermal, said Ann Garth, policy manager for superhot rock geothermal at the nonprofit Clean Air Task Force.
Garth is the lead author of a new report, shared first with Canary Media, that describes how states can “de-risk” geothermal for infrastructure investors, who typically pick up where venture-capital funds and federal research programs leave off.
Geothermal’s high upfront drilling costs, the slow trickle of investment returns, and the uncertainty around project development — like how long permitting will take or how profitable the resource will be — are major stumbling blocks for project financiers. Whereas some investors can stomach any two of the factors, “the three in combination will make financing very difficult,” Garth said.
Many western states have made some policy changes to address these challenges, though none have put all the pieces together yet. In its new report, Clean Air Task Force outlines what the states should focus on and highlights which steps they’re already taking.
Perhaps the most meaningful move that states can make is to create demand for utility-scale geothermal.
Take California, as an example. In 2021, the California Public Utilities Commission adopted a procurement order calling on utilities to add at least 1 GW of “clean firm resources,” such as geothermal, to meet the state’s long-term climate goals and grid reliability requirements. The mandate is largely responsible for the rise in power purchase agreements for next-generation projects — including Fervo Energy’s Cape Station in Utah. Southern California Edison has agreed to buy 320 megawatts of power from the 500-MW project, which is set to come partially online this fall.
“That has been an incredibly important driver of the growth in the geothermal industry,” Garth said. “Seeing those PPAs come in has given a lot of confidence [to investors].”
California itself has installed almost 2.9 gigawatts of conventional geothermal capacity, making it the nation’s leader. Colorado, by contrast, is working to land its first geothermal power plants of any kind.
In June, Colorado’s legislature passed a bipartisan bill that requires investor-owned utilities to solicit proposals for the development of large geothermal projects greater than 25 MW, as well as smaller systems. The state also awarded $494,000 to Fervo to evaluate the potential for developing geothermal power projects in two regions of the state.
New Mexico, meanwhile, is backing the commercial deployment of a novel geothermal system through its $75 billion sovereign wealth fund that draws on oil and gas royalties. Through the fund’s venture-capital investments, the state is supporting the startup XGS Energy as it develops a 150-MW closed-loop system in New Mexico along with Meta.
However, before developers get to the point of proposing projects, they need to scour geologic data to understand what rock formations are like, and how hot they are at certain depths. Many states already have this information from earlier oil and gas development, but the files aren’t easy to access.
Some states are working to make geological records more readily available. North Dakota has scanned and digitized the bulk of its historic data, which it provides to academics for free and to companies for a fee. Earlier this year, Arizona invested $1 million in the state’s geological survey to integrate historic subsurface data with new information, gathered using airborne and laser-based imaging, to bring geothermal development to Arizona.
Washington state, which also doesn’t produce geothermal power, passed a bipartisan law in 2024 that directs the state’s geological survey to compile a public database of subsurface information. It also creates grant programs for companies to do deep exploratory drilling in areas with high geothermal potential.
State permitting agencies, meanwhile, are still wrapping their heads around next-gen geothermal.
As a result, permitting can be a slow and unpredictable process — and a source of anxiety for investors. “The longer you have to wait before you can actually start generating revenue, the more expensive it gets,” Garth said.
Nevada devised a solution to this problem in 2008 to support its conventional geothermal sector. The state’s environmental protection and minerals divisions entered a cooperative agreement to clarify which agency has jurisdiction over certain aspects of drilling and operating geothermal wells, avoiding confusion and delays. Nevada has installed 892 MW of conventional geothermal capacity, making it second to California, and Fervo is developing a 115-MW “enhanced geothermal system” with Google in the state.
Texas, which is home to several test projects but no commercial geothermal, resolved a bureaucratic conundrum that had slowed next-gen development. In 2023, lawmakers passed a law to clarify who owned the geothermal resources on a given property: the surface landowner, not the owner of subsurface oil, gas, and minerals.
Another major barrier to scaling next-generation geothermal is access to transmission lines. This plagues every energy source in the U.S., and it can’t necessarily be tackled by individual states.
Connecting rural geothermal plants over long distances to pockets of demand requires coordinated, long-term efforts within regions, and that work has hardly begun in the West, according to Clean Air Task Force.
The group also recommends creating innovation test beds as a way for states to reduce project risks in specific areas. For example, the federally funded Utah Forge is an underground field laboratory in Beaver County, Utah, that has developed and refined enhanced geothermal using oil and gas techniques. Fervo said it built Cape Station next door so the company could collaborate with researchers who have extensively explored the area’s geology.
So far, states have adopted “an interesting hodgepodge of efforts” to attract geothermal investment, Dan West, senior Western regional policy manager at Clean Air Task Force, said by phone.
But “no state has checked all the boxes and pulled all the policy levers yet,” he said.
As the legislative session nears an end, lawmakers push ahead bills that aim to stop AI centers from raising utility costs and spur builders to opt for clean energy.
California, with its sky-high electricity prices, isn’t facing the same influx of data centers that many other states are. But the massive facilities are still being built and proposed in California — and legislators are racing to stop them from pushing up utility rates and pollution.
Two major data center bills passed a key committee last week as California’s legislative session nears its close at the end of this month. Senate Bill 886 aims to prevent data centers from raising utility costs for other consumers, while SB 887 would incentivize developers to invest in clean energy and nearby communities.
Data centers have lawmakers nationwide walking a fine line. Voters are increasingly worried about the facilities’ impacts on energy affordability and the environment, but the industry also promises jobs and economic benefits. State Sen. Steve Padilla, the Democrat who penned both California bills, says his proposals would rein in the sector without stifling it completely.
“People are asserting that it’s a binary choice” on data centers — “you can either ban them all, which is some communities’ reaction, or you can have zero regulation,” said Padilla, whose bills were inspired by a high-profile conflict between a data center developer and residents in a county he represents.
“I think we can walk and chew gum at the same time,” he said. “We can protect consumers and communities, and support infrastructure that supports tech companies and jobs.”
SB 886 takes on the first part of that equation. It would require the California Public Utilities Commission to set rules for data centers of at least 25 megawatts to fully cover the costs they impose on customers of the state’s three major utilities. Data centers would pay for the new power generation and grid upgrades they need, along with a “reasonable share” of the fees utilities collect for wildfire mitigation, environmental programs, and other social initiatives.
This is not a new approach, with many states already enacting similar “large load tariffs.” Along with these requirements, SB 886 would create a mandatory demand-response program that forces data centers to stop pulling power from the grid during supply-demand emergencies. Similar mandates are under consideration in places like Texas and the 13-state region served by grid operator PJM Interconnection.
SB 887, meanwhile, would offer expedited state environmental review for data centers “if they commit to high standards and serving communities,” Padilla said. Data centers seeking this special treatment must get 100% of their hourly electricity consumption from carbon-free resources within five years, 75% of it newly built. And they’ll need to draw from zero-carbon backup power — most likely batteries — when the grid is under stress, rather than using diesel generators, which are installed by almost all data centers. Developers would also have to pay for grid interconnection costs in advance and commit to a community benefits plan.
Although California has yet to see the massive, gigawatt-scale data centers being built in some states, several larger-scale projects are in the works near Silicon Valley. Those include Microsoft’s 48-megawatt data center in San Jose, developer Stack Infrastructure’s 77-megawatt data center in Hayward, and, most recently, Google’s 250-megawatt research and development center in San Jose.
More data centers are coming. Northern California utility Pacific Gas & Electric has 10 gigawatts of demand from data centers in its pipeline over the next 10 years, equivalent to what’s needed to power roughly 7.5 million homes. PG&E says that load growth will create billions of dollars in tax revenue and — more important to its customers — lower electric bills by 10% or more “by spreading fixed costs across more energy usage.”
Environmental and consumer groups are skeptical. The Union of Concerned Scientists warned in a May report that the state “currently has too few protections to ensure data center costs are not passed along to ratepayers.”
“The data center developers don’t really care about costs,” said Matthew Freedman, senior staff attorney with The Utility Reform Network, a consumer advocacy group that supports SB 886 and SB 887. “They’re focused entirely on speed of development, and on proximity to Silicon Valley.” Meanwhile, PG&E and the state’s other investor-owned utilities earn guaranteed profits based on how much money they invest in capital infrastructure, giving them little incentive to control those costs, he said.
Although SB 886 has won the support of utility worker unions, PG&E opposes it. In an email to Canary Media, company spokesperson Paul Moreno said the bill would “introduce rigid, duplicative requirements that conflict with existing regulatory processes, risk higher costs for customers, and delay critical infrastructure needed to serve the state’s growing energy demand. We continue to work with lawmakers to improve the bill, so it better supports affordability, reliability and equitable cost allocation for all customers.” PG&E has taken no position on SB 887.
Both bills face pushback from the Data Center Coalition, a trade group representing major data center developers, natural gas generator company ERock, and business organizations. The groups wrote in a March letter that data centers shouldn’t be “singled out” for different treatment from other big power-using customers. They also fear that SB 886’s demand-response mandate could force them to curtail computing operations relied on for critical health care and government services.
Meanwhile, the coalition argues that SB 887’s clean power requirements are virtually impossible for data centers to meet. “We don’t see it as a streamlining mechanism, because those standards are not attainable,” said Khara Boender, Western government affairs director for the group.
It’s unclear how Gov. Gavin Newsom (D) will respond to bills opposed by politically powerful utilities and tech companies. Last year, Newsom vetoed a bill that would have required data centers to report their water usage. And Padilla said his 2025 proposal to create a new rate class for data centers was watered down to a “study” bill requiring the utility commission to examine and report on their energy cost impacts.
But the politics are shifting. A recent poll commissioned by Net-Zero California, a Sacramento-based environmental policy group that supports SB 886 and SB 887, found that 70% of voters in the state oppose data centers in their communities, and that 74% want to see requirements for data centers to cover their costs and use clean energy. Newsom recently told reporters that “it’s absolutely essential and appropriate that these hyperscalers pay their fair share,” citing Google and Microsoft specifically.
Padilla said he expects SB 886 and SB 887 will pass in the state Senate and Assembly before the end of the legislative session this month. Newsom has until the end of September to sign bills into law.
While solar and EV sales cratered after the Republican Congress eliminated federal tax credits, batteries bucked the trend. Here’s why.
Last fall, as generous federal incentives for consumer cleantech were set to expire, people raced to lock in good deals on EVs and rooftop solar. Then, this year, sales cratered.
But home batteries bucked the trend. Federal tax credits for residential storage expired at the end of last year, prompting record sales in Q4 of 2025 — and then sales climbed even higher in the first quarter of 2026, per a BloombergNEF analysis of U.S. Energy Information Administration data. Homeowners installed a total of 673 megawatts of battery storage in Q1 of this year.
A few factors explain the market’s resilience. There’s the zeitgeisty reason: Across the nation, utility bills are high and rising, and batteries, typically paired with rooftop solar, offer people the ability to radically reduce their reliance on the centralized grid. There’s also the wonky explanation: State policies meant to spur home battery adoption are now doing just that.
Adoption is highest in the states where these factors — high electricity costs and supportive policy — coincide. California has since 2023 incentivized households to pair storage with solar, and in both 2024 and 2025 the state accounted for around three-quarters of home battery installations nationwide. Meanwhile, Hawaii, which has the highest electric bills in the country, created a new storage incentive program last year that resulted in a surge of installations in Q1 of this year, per BNEF.
The rising adoption comes even as the rooftop solar market struggles. Last year’s Republican tax and spending bill, the One Big Beautiful Bill Act, eliminated long-standing tax credits that knocked 30% off the price of both rooftop solar and storage systems. As a result, BNEF expects that this year residential solar installations will fall to their lowest level since 2020.
The stubborn growth of residential energy storage is another reminder that batteries are fast becoming a critical part of the U.S. electricity story. Large-scale batteries, for which Republicans actually preserved tax credits in last year’s law, are being built at a blistering pace. Expect home battery adoption to keep climbing, too.
Swapping your gas car for an electric vehicle is a climate win in almost all cases, says a new study, which even “tipped the scales” against EVs.
A few years ago, environmental scientist Elliot Campbell went around asking people why they would, or would not, switch to an electric vehicle. A surprising number of them asked him a question in return: Because building an EV generates emissions, isn’t it better for the planet just to keep my gas car running for as long as possible?
Campbell, a professor at the University of California, Santa Cruz, didn’t know the answer, so he set out to find it. Turns out the old adage that the greenest car is the one in your driveway is a myth. In fact, his study, published today in the journal Science, finds that swapping even a two-year-old gas car for an EV leads to a lifetime emissions savings of roughly 50 percent.
Not everyone can afford to ditch a nearly new car, of course. It’s simply the most extreme example of the broader point his study revealed: The emissions saved by driving an EV very quickly compensate for the planet-warming gases generated by building it. Campbell said that finding consistently surprises his students, and goes against his own instincts.
“I like to repair things and keep them going,” he said. But, “we found there is a big advantage to retiring the gas vehicles early.”
Campbell designed the study to give internal combustion vehicles every possible advantage. “We really tipped the scales in favor of the gas vehicle,” he said. Most notably, it ignored the emissions that went into making the gas car, treating them instead as a sunk cost. The EV still came out ahead, which suggests that climate-conscious drivers should make the switch as soon as it’s feasible.
“You’re just delaying the benefits longer and longer,” he said, noting that sidelining gas guzzlers off the road can improve air quality as well. This is especially true for cars that were built to less stringent standards, added David Reichmuth, a transportation sustainability expert at the Union of Concerned Scientists. “The magnitude of the benefits for getting an older gasoline vehicle,” he said, “can be much higher in terms of the air pollution.”
Reichmuth was not involved with Campbell’s study, but said it aligns with his own work on the issue. His analysis found that EVs reach an emissions break-even point at around 18,000 miles, which the average driver travels in about 18 months. That, however, depends on where a person lives and the source of their electricity.
The benefit is greatest where the grid is greenest. In upstate New York, which generates a lot of hydroelectric power, getting around in an EV is like driving a gas car that gets 219 mpg. But even in the Rockies, where coal and natural gas are the norm, an EV is better than anything getting less than 68 mpg.
Campbell’s study identified few exceptions to the conclusion that replacing a gas car with an electric one significantly reduces greenhouse gas emissions. Even moving away from high-efficiency vehicles and hybrids, like the Toyota Prius, is a climate win in the long-run. One case where it wouldn’t make sense, Campbell and his co-author found, is with plug-in hybrid electric vehicles, which have larger batteries and travel farther on electric power before switching to an internal combustion engine. Another is low-mileage situations, such as with a second car that doesn’t get used that often.
“To me, this is the biggest factor,” said Moaz Uddin, senior electric vehicle policy specialist at the think tank Great Plains Institute, about mileage. He gave the example of a retiree who only drives their Prius a few thousand miles a year. “It’s good that the study considers that.”
The new research finds that in order to repay the carbon debt of making a new EV, it must be driven 4,400 miles if it’s a car and 6,700 miles each year if it’s a truck. That’s already well below the 12,500 miles the average driver travels in a year, and the benefits to making the switch are likely to grow.
As the United States increasingly relies on renewables, for example, charging an EV becomes even more environmentally appealing. Campbell and his co-author also point to improvements in battery recycling as a way of reducing the emissions involved with making an electric car.
One hole in this latest study is that it doesn’t consider the cost of going electric. While previous research has shown that EVs come with higher upfront costs but lower operating expenses, it’s a thread that Campbell hopes economists pull on. He would also like to see someone better account for the emissions generated while extracting oil and getting gasoline to the pump, rather than simply the burning. But, for now, he believes the study sends a clear message.
“We’re trying to show that there’s not an environmental motivation for extending the lifetime of a gas vehicle,” he said. “Electric vehicles are a very clear winner.”
The most direct policy interpretation of the study would be to give people money to scrap gas cars. There have been some efforts to do this, such as the 2009 federal Car Allowance Rebate System, also known as “cash for clunkers.” That gave people $3,500 to $4,500 if they upgraded to more efficient vehicles, and blew through its $3 billion budget in only a month. Reichmuth, though, says that the issue could be tackled earlier in the process.
“The obvious policy implication is don’t sell the gasoline car to begin with,” he said, with the corollary being that EVs need to be as attractive an alternative as possible. “Make sure there are more options, more support, for people to make that initial choice.”
Firms that enlist homes to reduce energy demand — and costs — have long complained that utility data rules prevent them from helping in PJM. FERC agrees.
A recent ruling from federal regulators will let virtual power plants help meet surging energy demand in the county’s biggest energy market.
Late last month, the Federal Energy Regulatory Commission ordered PJM Interconnection to accept statistical sampling as a valid method for measuring the reliability of programs tapping into demand-response and virtual-power-plant programs, which pay customers to turn down energy use as needed. The decision requires the grid operator to reconsider strict data rules that had prevented providers of this carbon-free resource from participating in PJM’s constrained energy-capacity market.
In its decision, FERC ruled in favor of Voltus, which runs demand-response and virtual-power-plant programs, and the Mission:data Coalition, a nonprofit advocacy group, and against PJM’s desire to preserve its status quo.
FERC agreed with Voltus and Mission:data that, under its current rules, PJM is losing out on at least 4.9 gigawatts of capacity — the equivalent of several large power plants — “at a time when PJM is experiencing unprecedented load growth driven in part by hyperscale data center development, threatening reliability.”
Booming power demand from data centers and bottlenecks in power plant construction are not just threatening reliability in PJM but also driving up energy costs for the 67 million people it serves across 13 states. FERC found it would be “unjust and unreasonable” to allow the current rules to stand.
Last month’s ruling caps a yearslong fight from providers of demand-response and virtual-power-plant services.
“This is a huge win, and we’re really optimistic that it will unlock hundreds of megawatts of residential load over the next several years,” said Marissa Galizia, Voltus’ senior director of partnerships. FERC’s order makes clear that “PJM has the power to change the rules even while utilities aren’t providing the data,” she said.
At issue was PJM’s concern about relying on third-party demand-response aggregators to reduce household electricity demand when needed. PJM insisted that Voltus and other demand-response firms must furnish detailed evidence that participating households actually cut power when prompted to do so. Specifically, PJM required smart-meter data, which is collected in the service territories of most utilities PJM covers.
If firms could not produce that data, PJM would not count on — or pay for — that demand-response capacity to show up during times of peak demand.
But for the most part, demand-response firms could not get their hands on that data. That’s because, as Voltus and Mission:data argued to FERC, most of the major utilities in PJM territory have failed to make that data from their digital smart meters readily available.
It’s a catch-22. And as a result, PJM has missed out on gigawatts of demand-response capacity that could have helped alleviate the reliability and cost crunch it faces — and aggregator firms have been essentially locked out of the lucrative capacity market.
Utilities blame states’ data privacy regulations for their conservative management of smart-meter data. FERC doesn’t get to tell states how to manage those data privacy and data access rules, but it can compel PJM, which it has jurisdiction over, to accept alternative forms of data.
That’s what FERC did in the July decision.
Given the “significant barriers to obtaining interval meter data,” FERC told PJM to allow aggregators to use a statistical sampling method that the grid operator had relied on before smart meters existed. PJM also still allows this method for customers that don’t have smart meters. In light of those facts, FERC found that “statistical sampling is a valid method to approximate load reductions when interval meter data is not reasonably available.”
Both PJM staff and Monitoring Analytics, its independent market monitor, protested that letting demand-response companies use statistical methods could undermine reliability.
Monitoring Analytics argued that allowing statistical sampling would “degrade PJM’s ability to maintain resource adequacy and to correctly determine efficient capacity market prices through supply and demand.”
FERC disagreed, citing evidence presented by Mission:data and Voltus showing that statistical sampling can be as or more accurate than methods that use metered data when applied to large numbers of homes, as opposed to single large customers like factories.
The order won’t take effect immediately. FERC directed PJM to launch a proceeding to work with stakeholders to find a method that parties could agree on, with initial plans due within 45 days of FERC’s order.
“We’re going to be working with our partners to submit answers to the questions and propose what we’d like to see,” Voltus’ Galizia said. “Generally, we’d like to make it as easy as we can while guaranteeing that that process is as accurate as possible.”
FERC’s ruling comes at a tense time for PJM. Over the past year, the Trump administration and state governors have attacked the grid operator for failing to mitigate the huge increase in capacity market prices that are driving up utility rates and driving public anger against utilities and data center developers.
“I hope the decision sends a message to PJM and its stakeholders,” said Ken Schisler, chief legal and regulatory officer at CPower, a demand-response company that brought a similar complaint that FERC rejected in 2024 for lack of evidence. “The message is to stop the nonsense and to remove barriers that are keeping demand response from growing in the market.”
Michael Murray, president of Mission:data, hopes the ruling will also add fuel to his decade-long effort to make utilities and state regulators unblock smart-meter data that technically belongs to customers.
FERC’s order doesn’t address the underlying state-by-state data-access barriers that Mission:data is working on — the agency doesn’t have the jurisdiction to do so even if it wanted to.
Still, Murray hopes it will push state regulators to revisit their data-access policies, since “states may not like the remedies that FERC comes up with in this case or in other cases.”
And more broadly, he said, it’s the first time the agency has acknowledged just how critical this issue is.
“FERC has finally recognized that what I’ll call data blocking is not just an artifact of state privacy laws, and it’s not something to just ignore and say, ‘Oh this is just a state matter,’” he said. “They definitely said that it rises to a Federal Power Act matter.”
Tariffs and rising grid demand are spurring a revival, but high electricity costs and community concerns threaten to stall key new smelter projects.
America’s aluminum sector is growing again after years of decline, spurred by tariffs and a push to revive domestic manufacturing. But the voracious power needs of aluminum smelters and communities’ concerns about pollution still pose major hurdles to scaling up production.
Globally, a deficit in aluminum supply is expected to worsen this year following damage to major Middle Eastern smelters and disruptions in the Strait of Hormuz amid the ongoing U.S.-Iran conflict. At the same time, soaring U.S. power consumption is boosting demand for the versatile metal, as the makers of transformers, cables, and other electrical equipment race to build out the grid.
“There is very little cushion left anywhere in the system,” Jesse Gary, president and CEO of Century Aluminum, said on an earnings call last week. “In a market with no slack, the value of secure domestic units goes up.”
Chicago-based Century recently marked the return to full operations at its Mount Holly aluminum plant in South Carolina — one of only four remaining U.S. smelters. The facility has begun churning out another 50,000 metric tons of virgin, or primary, aluminum, raising total U.S. production by nearly 10%.
Mount Holly is, at the ripe age of 46, the country’s youngest smelter. In 2015, Century partially idled the plant because of high electricity costs — a persistent problem faced by virtually all smelters, which require hundreds of megawatts of continuous power to convert raw materials into metal. Last fall, Century reached a new long-term power agreement for its Mount Holly plant with the utility Santee Cooper. (Over half the utility’s power supply comes from coal-fired power plants, and about a quarter comes from natural gas and oil.)
Other smelter projects advancing in Oklahoma and Missouri are expected to further increase domestic supply, but their success largely hinges on their developers’ ability to access cheap, reliable electricity for the power-hungry operations.
In Oklahoma, Century and its joint-venture partner Emirates Global Aluminium are working to build a giant new smelter that would more than double the nation’s capacity for making primary aluminum. If all goes as planned, Oklahoma Primary Aluminum could break ground by the end of this year and start producing its “first hot metal by the end of 2029,” Gary said on the earnings call.
The proposed smelter is set to receive a $500 million grant from the Department of Energy, which Century landed in 2024 from of a Biden-era program to decarbonize U.S. industries. The project was sited in Inola, Oklahoma, partly because of the state’s abundant natural gas and wind energy resources and solar energy potential. Utility-scale wind and solar represent the fastest and most cost-effective resources for expanding grid capacity — and running a smelter on renewables would sharply reduce the planet-warming gases and toxic pollution associated with aluminum production.
Oklahoma Primary Aluminum has been pushing for more than a year to strike a competitive deal with the local utility, the Public Service Company of Oklahoma. Gary said the developers have “advanced negotiations toward a final energy contract,” which they’ll need to obtain before construction can begin. “Just know that we’re working hard and continue to make progress,” he said.
However, the proposed 750,000-metric-ton smelter is facing growing pushback from state political leaders and Oklahoma residents, who worry that the hulking facility will pollute the air and water and harm cattle and crops in northeastern Oklahoma, including on tribal lands.
In recent weeks, members of the Muscogee (Creek) Nation and Cherokee Nation have raised concerns about the project’s environmental impacts, with Muscogee leaders adopting a bill that opposes building and operating smelters on the reservation. Gentner Drummond, Oklahoma’s attorney general and a Republican gubernatorial candidate, has also opposed the smelter’s foreign ownership and pollution risks. On Aug. 11, he filed a motion to block construction of the smelter while his lawsuit against the project is pending.
Century and Emirates Global Aluminium claim the Inola facility will be significantly cleaner than existing U.S. smelters and will use the latest version of EGA’s smelter technology. “We’re working very closely with the community in Inola and elsewhere in Oklahoma to better understand what their concerns are and to make sure that they have all the facts about our technology and process,” Gary said.
Meanwhile, some 420 miles east of Inola, the company Magnitude 7 Metals is planning to partially reopen its idled aluminum smelter in New Madrid, Missouri, before the end of this year.
The manufacturer shut down operations in 2024 and laid off over 500 workers, after struggling with low aluminum prices and high power costs, Bloomberg reported. The 263,000-metric-ton facility represented about 30% of the nation’s aluminum production capacity at that time — and was Missouri’s single largest consumer of energy.
On July 1, Magnitude 7 Metals said it will restart about 75,000 metric tons of annual production at the facility. The company attributed the comeback to the Trump administration’s Section 232 aluminum tariffs, which raise the costs of importing aluminum for cars, cans, and construction. Last month, the White House also created a related tariff program that’s designed to further incentivize investment in new U.S. primary aluminum capacity.
Whether the tariffs can offset the inescapable challenge of electricity costs remains to be seen.
Annie Sartor, senior campaigns director at Industrious Labs, noted one potential roadblock for the Magnitude 7 Metals restart: Missouri’s “large load” electricity tariffs. The state adopted the policy in 2025 to ensure that major power users help cover the costs of improving grid infrastructure to support their increased demand. But while wealthy tech companies can afford those added expenses, they’ll only add insult to injury for aluminum producers.
“The smelter would face the same electricity cost structure as a data center — even though that same smelter has already curtailed operations twice [in 2016 and 2024] because of skyrocketing power costs,” Sartor said on LinkedIn. “The policy challenge is clear: a framework created to manage data center growth could unintentionally make it harder for manufacturers to operate, create jobs and support local economies.”
It’s also unclear how Magnitude 7 Metals plans to power its partially reopened smelter. The company did not immediately reply to Canary Media’s questions.
The facility was historically powered by the especially dirty New Madrid coal-fired power plant, which emitted the most nitrogen oxides from a power plant in the region and the country in 2020. Residents in southeastern Missouri who support restarting the smelter said they’re nevertheless concerned that it will drive up pollution, unless the smelter moves away from coal and toward clean energy, according to a March survey by Industrious Labs.
“Long-term economic investment will be more likely if this operation is powered by clean energy, especially solar and storage,” Jenn DeRose, Sierra Club’s Beyond Coal campaign strategist in Missouri, said in a July 1 statement. “Powering the smelter with clean energy will help ensure the smelter’s long-term viability by leveraging affordable, fixed-cost energy, and cleaner air for everyone who lives in New Madrid County and beyond.”
ScottishPower’s Whitelee onshore wind farm could double its capacity with far fewer turbines. It’s an example of how much wind technology has improved.
It’s almost an ironclad law: Over time, wind turbines get taller, better, and more cost-effective.
A new proposed project in the U.K. demonstrates that. ScottishPower recently announced its intention to repower the U.K.’s largest onshore wind farm, a process that will involve replacing old turbines with state-of-the-art new ones. Once that is done, the wind farm will produce twice as much power with almost half the number of turbines.
The Whitelee wind facility, near Glasgow, was completed in 2008. The developers installed 140 turbines that stood 360 feet tall at the highest blade tip and could generate 2.3 megawatts each. By 2013, the site had been expanded with 3-MW turbines that stood 459 feet. Since then, Whitelee has produced up to 539 MW from its 215 turbines, storing some of that in a 50-MW battery on-site.
If the forthcoming upgrade gets regulatory signoff, the old turbines will be taken down and in their place will rise 124 new ones, measuring 787 feet tall and producing around 7 MW apiece. Collectively, they will be able to generate more than 1 gigawatt of carbon-free power when the wind blows fiercely.
“Repowering allows SPR [ScottishPower Renewables] to reuse existing site infrastructure and take advantage of new technologies resulting in increased electricity generation and ultimately, increased security of supply,” the company noted in a scoping document.
It’s a striking example of how far this clean energy technology has advanced in recent decades. Modern turbines have pushed to incrementally higher heights and broader wingspans, allowing them to generate far more electricity than their predecessors — and to do so at a cheaper unit price. This evolution supports onshore wind’s position as the cheapest of all the electricity sources on an unsubsidized basis, per the latest analysis by the financial advisory firm Lazard.
Repowerings like Whitelee’s could help the U.K. and the European Union shore up their energy security as the natural gas supply chain remains in war-torn upheaval. And while the U.S. government currently seeks to thwart this affordable energy source, there are signs that repowerings could add significant capacity in the coming years.
The main appeal of repowering is to access the much greater clean power generation — but there are other benefits, too.
“It doesn’t take twice as long to service a turbine that’s twice as big, and you don’t have to do two foundations — you only need to do one,” said Kaj Skov Nielsen, a longtime wind power specialist who helped set up the control system at Whitelee.
Installing a new turbine also gives project owners an easy opportunity to add state-of-the-art sensors, Nielsen said. New sensors can detect birds and bats and slow the blades’ rotation to protect them. Others can spot potential mechanical issues, like debris that could cause problems in the gearbox, before they become catastrophic.
Older turbines have control systems that can stop the blades if they detect a fault. Newer systems can slow the rotation to a safe level based on the specific fault that is happening, Nielsen said, eking out more generation without endangering the equipment — “it’s a totally different game.”
That’s not to say repowering is easy. Larger equipment may exceed the weight limits on the roads and bridges to the project site, or height limits on underpasses along the route, Nielsen noted. Developers need to weigh the cost of upgrading that transportation infrastructure against the alternative of shipping in pieces and assembling them on-site, which adds more work on the back end. A developer also needs to strengthen foundations to support the weight of much larger turbines.
ScottishPower still needs consent from the Scottish ministers for the repowering, so it will go through a detailed assessment for impacts on the community and the environment. The repowering project has two big advantages in that process, compared with a brand-new project: It already secured permission to build many more turbines on the same land, and it would upgrade capacity without expanding into undeveloped countryside.
ScottishPower, for its part, has tried to make Whitelee welcoming to the broader community. The energy company acquired the site after it had been used for commercial logging and has invested in wide-scale restoration of the underlying peatland ecosystem. People can bike or hike around the premises, take guided bus tours, and enjoy the views from a visitor center that touts its “delicious cakes” from local vendors. The power company markets it with the hashtag #MoreThanAWindfarm.
Turbines of the size proposed for Whitelee have just started getting installed around the world, said BloombergNEF wind analyst Harrison Sholler. Chinese manufacturers have been pushing the boundaries of onshore turbine size, but those units are typically shut out of Europe and the U.S. because of geopolitical concerns. Instead, developers in those regions turn to manufacturers including Siemens Gamesa, Vestas, and Nordex, all of which now sell 7-MW onshore wind turbines; or GE, which has onshore models up to 6 MW.
A project in Brazil’s Bahia state installed a new 7-MW turbine last fall, touting it as the largest onshore turbine in the Americas.
“It’s established technology in the sense that they’re not that different from a 6-MW turbine, for example,” Sholler said. “They’re considered by the industry to be proven at scale.”
The U.S. might not have any turbines that big yet, but it does have plenty of installed turbines of the smaller vintage that ScottishPower seeks to replace. The U.S. average onshore wind turbine capacity has steadily ticked up from 0.8 MW in 2000 to 1.8 MW in 2010 to 3.5 MW in 2024, per the most recent accounting by Lawrence Berkeley National Laboratory. The country’s first 6-MW-turbine project came online that year in Oklahoma.
Of the 86 GW of new wind capacity BNEF expects the U.S. to build over the next decade, 10 GW will come from repowering, said Sholler. “Towards the early to mid-2030s, we expect repowering activity to ramp up as some of the larger wind farms are reaching the end of their operational life,” he noted.
BNEF expects the Northwest and Midwest will build the most repowered wind capacity in the next 10 years, with significant capacity popping up in Texas, California, and the mid-Atlantic. In California, repowerings will provide pretty much all new onshore wind capacity in that period, Sholler said, because all the good sites for onshore wind farms got developed decades ago, starting when the state initiated a subsidy in the 1980s.
That said, the largest U.S. repowering on BNEF’s radar for the next decade clocks in at just over 200 MW, a far cry from the projected 1 GW at the refurbished Whitelee.
“I don’t think we’re at the stage of market maturity where we’re starting to see those larger-scale projects start to repower in the U.S.” Sholler said. “But we will get there eventually.”
Illinois community solar incentives spurred plans to put 60 arrays on top of Public Storage facilities in the state. So far, 10 are online.
Krzysztof Wasowicz, mayor of Justice, Illinois, has some concerns about solar: that it takes up farmland and enriches China. But he’s all-in on the community solar array that was recently deployed at a Public Storage facility in his village, a suburb of Chicago.
The panels are located on otherwise unused roof space and could provide significant savings for Illinoisans who subscribe to the project, while also helping the state meet its goal of 100% clean power by 2050.
“This creates more opportunities for people, job creation, and revenue that can be taxed by our state,” said Wasowicz, who has been mayor of Justice, home to about 12,000 people, since 2007. “This is going to be an excellent addition to this village.”
The 763-kilowatt array, which went online in March, is one of 60 planned projects for the rooftops of Public Storage facilities in Illinois. Ten such projects are now online, and once completed, the portfolio will cover 5 million square feet of roof space, provide 44 megawatts of solar capacity, deliver $36 million total savings, and create 300 construction jobs, according to Solar Landscape, a leading developer of rooftop community solar sites nationwide.
Only a fraction of industrial and commercial roof space is currently used for solar, because those projects are generally more expensive to build and interconnect than ground-mounted arrays in rural areas. But thanks to new incentives, developers, utilities, and building owners nationwide are increasingly considering the possibilities.
Federal data analyzed by the solar company Lumen Energy found that commercial, industrial, and school rooftops could host enough panels to provide 581 gigawatts of power, nearly enough to meet the entire country’s energy demand. Cook County, Illinois, which includes Justice, is among the metropolitan areas with the greatest potential, that analysis found.
Mark Schottinger, president and chief legal officer of Solar Landscape, said that working with large companies like Public Storage allows his company to deploy rooftop projects quickly at multiple sites.
“The beauty of commercial-industrial real estate is the speed and scalability,” he said, noting that major logistics, storage, and big-box companies “have millions of square feet around the country.”
Community solar allows households, businesses, and organizations to reap savings and support clean energy even if they can’t have their own solar panels. By subscribing to a community solar array, customers get credit on their energy bill for a portion of the solar power generated.
Illinois is among the nation’s leaders in community solar capacity, according to the Solar Energy Industries Association, with more installed than even California. It is among the two dozen states that have laws enabling community solar, which typically leads to more arrays than in states without specific policies.
Illinois’ 2016 clean energy law created generous incentives for community solar, leading to a boom in projects of up to 2 MW each. An energy law passed last fall made the incentives available for projects of up to 10 MW.
Most of the state’s community solar has been built on rural land or industrial brownfields. About a fifth of the arrays are on rooftops, with the rest being ground-mounted. The rooftop arrays are concentrated in the Chicago area, and rooftops are an increasing priority for community solar, according to Paul Kovacs, project execution manager for distributed energy resources for utility ComEd, which serves northern Illinois.
At a July 30 event promoting the Justice project, Melissa Washington, ComEd’s senior vice president for government relations and external affairs, called rooftop community solar “an elegant solution” for deploying clean energy to meet rising demand.
She listed three mandates for the utility: supplying power to businesses and residents, keeping electricity affordable, and addressing climate change — a necessity underscored by violent storms three days earlier that had left many ComEd customers without power.
Rooftop community solar, she said, “checks the box for every single one of those three critical priorities.” The utility plans to have over 400 community solar arrays in service by the end of this year, she added. Kovacs said about 100 of those will be on rooftops.
In a typical setup, a company like Solar Landscape develops and owns the array and collects revenue from incentives and subscribers. Those subscribers get savings on their energy bills, the property owner hosting the panels gets lease payments, and the utility gets credit toward renewable energy mandates. The utility works with the developer to make any upgrades needed to connect the array to the grid, which the developer pays for so that costs are not passed on to ratepayers.
The Public Storage projects are part of Illinois’ Community-Driven Community Solar program, meant to incentivize solar arrays whose subscribers are predominantly local households and small businesses or nonprofits, as opposed to a few large subscribers hogging the savings.
Under state law, owners of community solar can sell renewable energy credits to utilities for revenue that makes the financing equation more favorable for all the partners involved. The incentives are awarded through a highly competitive process, and proposals gain points for being in designated low-income or environmental justice census tracts, having a large proportion of local subscribers, involving the community in design and planning, and hiring through the state’s workforce training programs, among other factors. The community solar credits are also worth $5 more per megawatt-hour for rooftop installations.
The Justice project earned points for making charitable contributions and for hosting a workforce training program in conjunction with the New Jersey–based training and education nonprofit STEP-UP Solar, according to Solar Landscape marketing director Samantha Kanipe.
State incentive programs are critical to facilitating community solar development since the expiration of federal tax credits under the Trump administration’s 2025 spending bill, advocates note. Meanwhile, arrays on industrial and commercial sites, like the Public Storage ones, can still qualify for federal tax credits if they are operational by the end of 2027, or if they started construction by July 4 of this year.
“We began construction on a ton of projects before July 4,” including all the Public Storage ones, said Schottinger of Solar Landscape, noting that his company can build an array like the one in Justice in about six months.
He said his company and other solar developers are still in the “early innings” of using rooftops for community solar. But, “it’s growing exponentially,” he added. “There’s a lot of blank space out there.”
SB 905 would curb returns on wildfire costs, seek new financing, and explore performance metrics to curb sky-high electric rates. Can it overcome utility opposition?
California lawmakers are once again contending with how to curb the state’s high energy costs as they hurtle toward the end of this year’s legislative session on Aug. 31. So what’s on the table for utility rate reform in the final stretch?
Enter Senate Bill 905, a complicated package of proposals that are likely to face intense opposition from utilities, which tend to reflexively resist rules that could crimp their profits. But California voters are demanding reform, according to state Senator Josh Becker, the Democrat who wrote the bill.
Californians rank cost of living as a top concern, and most blame the state’s three big utilities for rising electricity rates that are now roughly twice the U.S. average. And when it comes to California’s climate strategy, “it’s going to be really hard to convince people to install heat pumps and switch to EVs, or get a factory to switch to electricity rather than natural gas, if the price of electricity is too high,” he said.
Becker was speaking at a July 14 webinar hosted by the University of California at Berkeley’s Center for Law, Energy, and Environment (CLEE) to promote its latest research on the causes of the state’s electricity cost crisis. As that report highlights, there are no easy fixes.
Climate change and wildfire risks are forcing Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric to invest more in their aging and strained power grids. The California Public Utilities Commission, which regulates those utilities, is loath to rein in spending that expands the grid, brings more clean energy online, and reduces the risk of wildfires.
But the sheer amount of spending planned by utilities threatens to overwhelm the ability of their customers to pay for it. PG&E is seeking state regulator permission to spend $73 billion through 2030, and Southern California Edison has told investors it plans to spend from $38 billion to $41 billion through 2030.
SB 905 seeks to tackle utility spending in three key ways:
“Lowering electricity rates is a hard problem with no silver bullet,” Becker said. “But if we get this right, we can start a virtuous cycle.”
California lawmakers have been trying for years to pass utility reforms. In 2024, most of their efforts failed. But last year, Senate Bill 254, also sponsored by Becker, managed to make it through the legislative gauntlet.
SB 905 represents an important, if somewhat incremental, next step on those efforts, said Matthew Freedman, senior staff attorney at The Utility Reform Network (TURN), one of the state’s most vocal utility ratepayer advocacy groups and a sponsor of the bill. Among the bill’s provisions, a “lower return on equity is a pretty big one,” he said.
Utilities earn guaranteed rates of profit on capital investments, which puts upward pressure on customer rates. Anything that can reduce that rate of “return on equity,” or ROE, could help limit those increases, he said. A number of states are targeting utilities’ ROE to combat rising rates — and utilities are, not surprisingly, fighting back against the idea.
In a nod to the challenging politics, SB 905 proposes assigning a lower ROE only to key categories of utility spending, Freedman said. The biggest category is the tens of billions of dollars utilities are investing in burying and hardening power lines to eliminate the risk of sparking wildfires. SB 905 would also limit ROE for utility capital costs in “balancing” and “memorandum” accounts over which regulators have waived their typical authority for a “reasonableness review” to examine and claw back spending, usually for costs that can’t be predicted in advance of ratemaking proceedings.
Both these types of spending help reduce risk for utilities, which can lower the cost of financing as they go out to Wall Street to raise investment and procure debt, Becker said during the July webinar. That means utilities get “other benefits besides the pure financial return” from those investments, he said — and that justifies reducing how much they get to charge customers to recover those costs.
SB 905 also seeks to curb costs by forcing utilities to borrow money themselves, or rely on state-issued loans, to pay for some of their costs, Freedman said.
The math is fairly simple, he said. Borrowing money to pay for costs via a process known as securitization allows utilities to reduce the amount of money going into the “rate base” of capital investments on which they earn a guaranteed return. Utilities must collect money from customers over time to pay back those loans, but up-front impacts on customer rates are lower.
Tapping into state-backed bonds for utility projects that benefit the state at large — say, building transmission lines to allow more clean energy to be constructed and connected to the grid — could reduce costs even further, since governments can borrow more cheaply than utilities.
Last year’s SB 254 required the state’s big three utilities to securitize the first $6 billion in their ongoing grid wildfire-safety investments and created a state “transmission accelerator” to provide public funding for new transmission projects.
SB 905 would “require the PUC and the utilities to continue evaluating ways like that to lower financing costs,” Becker said, with an end-of-2028 deadline to report to the legislature on findings and recommendations.
It will take time for savings from this shift to borrowing to show up, said Sam Uden, co-founder and managing director of Net-Zero California, a Sacramento-based environmental policy group. He cited the example of the transmission accelerator, whose initial funding awaits final state budget negotiations.
“Then the goal would be for the accelerator to fire up next year, and launch public financing,” he said. “This is a multiyear transition.”
Curbing the return on investment and requiring utilities to borrow more both target the “capex bias” of regulatory structures that reward utilities with guaranteed profits on the capital expenditures. But what if utilities could be financially rewarded more directly for doing a better job on the things their customers and regulators really care about?
For decades, utility regulators and lawmakers have attempted to structure performance-based regulations to accomplish this. Some noteworthy examples include a long-running implementation at Hawaiian Electric and an abortive effort from Connecticut’s former head utility regulator that led to a bitter fight with utilities and her eventual departure from the agency.
SB 905 would set a Jan. 1, 2028, deadline for the California Public Utilities Commission to launch an effort to establish clear performance metrics for tasks such as making the grid more reliable, reducing greenhouse gas emissions, and speeding up the process of connecting new customers and renewable sources. “This will make clear what our expectations are for good performance, and hold utilities accountable for delivering safe, reliable, clean, and affordable power,” Becker said.
To be clear, SB 905 doesn’t authorize the commission to offer any financial incentives for meeting or exceeding whatever metrics it comes up with, Freedman said — at least, not yet. “We’re worried about a performance-based regulatory approach that the utilities can game and earn excessive profits from,” he said, as happened with Illinois utility ComEd over the 2010s.
“Let’s see how it goes for a few years. If we like it, the legislature can change the law and attach some incentives around that,” he added.
One big performance metric that SB 905 would establish, and which Virginia and other states have already implemented, is “grid utilization,” or squeezing more of the power grids that utilities already have. That’s a good way to drive down utility costs, which are based on “dividing the total costs of running the grid by the total amount of energy delivered to customers,” Becker said.
“We need to control the numerator of that equation — the costs. But if we can increase the denominator of the energy sold, then rates will go down,” he said.
California has plenty of load growth coming, whether from data centers, EV charging, or heat pumps and air conditioners for homes and buildings, Becker noted. The right combination of cost controls along with that can “make EVs look cheaper to drive, and make heat pumps look more cost-effective versus gas furnaces,” he said.
Right now, SB 905 is in the state Assembly appropriations committee, where it could undergo a number of amendments that won’t become known to its author until it is released for further consideration via a process known as “suspense.” Similar last-minute amendments gutted key provisions from another of Becker’s bills last year — before it was vetoed by Gov. Gavin Newsom.
Meanwhile, a late-breaking push by Newsom to reform California’s wildfire liability system — one of the state’s key drivers of utility costs — is likely to add more pressure on lawmakers trying to negotiate on a plethora of energy and climate issues, ranging from what to do about data centers to how to manage budget pressures tied to the state’s carbon cap-and-invest program.
Will SB 905 make it into law? “You know, utilities are fighting it fiercely,” Becker said. “But as we learned from last year, big things come down to the final wire, and I hope we’re going to get it through.”
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