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CEOs of artificial-intelligence companies want to spend hundreds of billions of dollars building their energy-gobbling data centers, but that can’t happen without the necessary electricity supply. And they want to move way faster than electric utilities are used to.
One idea gaining traction is to allow data centers to come online more quickly if they agree to occasionally pull less power from the grid when demand is high, a concept endorsed by none other than Energy Secretary Chris Wright in a rulemaking proposal filed Thursday. The massive computing facilities could accomplish such flexibility with the help of on-site renewables and batteries, but precious few projects using this model have materialized. That’s about to change.
On Wednesday, Aligned Data Centers announced it would pay for a new 31-megawatt/62-megawatt-hour battery alongside a forthcoming data center in the Pacific Northwest. The battery, developed by energy-storage specialist Calibrant Energy in partnership with the local utility, is now entering the construction phase and should be operating sometime next year. The kicker is, this deal will let Aligned get up and running “years earlier than would be possible with traditional utility upgrades,” per the companies.
If the plan works, would-be AI leaders will be jumping all over this battery-first strategy. In fact, many already are, they just haven’t publicly acknowledged it yet.
“There’s so much chatter right now about the potential to use energy storage in this manner to facilitate the connection that large power users want from the grid. But there hadn’t really been evidence of that theory being reality,” said Phil Martin, CEO at Calibrant, which is owned by Macquarie Asset Management. “It is possible, and it is being done — not as a proof of concept in a lab somewhere, but really a commercial project.”
Batteries aren’t, at first glance, a tool well matched to the needs of AI computing.
Lithium-ion chemistries have become quite competitive for short-form activities: First, it was managing second-by-second frequency fluctuations on the grid; now, in places like Australia, California, and Texas, batteries are shifting solar generation to compete with gas plants in the evening when demand rises.
Data centers, though, use energy around the clock — not literally at full blast 24/7, but a lot closer to it than current batteries can keep up with. Data-center developers have chased new gas, hydropower, and an exotic array of nuclear power plants in hopes of feeding the beast. But those options will take several years to come online, if they ever get built. The headlong rush into AI demands nearer-term solutions.
As a lot of exceedingly well-funded firms contemplated this conundrum, some thinkers started focusing on grid flexibility as a way to accelerate the computing-infrastructure buildout. Earlier this year, Duke University researcher Tyler Norris made waves in the AI-energy world with research that found today’s grid could handle quite a lot more data centers if the facilities could simply dial back their consumption for a couple hours at a time during moments of maximum demand.
The Aligned battery offers a concrete example of that kind of research. The utility studied just how big the battery would need to be to compensate for challenges imposed on the local grid by the data center. Aligned and Calibrant had their own calculations, Martin said, “but the validation of that, and the actual specification of that, came out of the interconnection study done on the utility side.”
Due to the local nature of the power constraint, the battery had to be built close to Aligned’s facility; the company ultimately provided the land to host the grid storage installation. In other cases, where a proposed data center runs up against a system-wide capacity constraint, a battery solution could be further away.
Another glimpse of the battery-enabled future came this summer when Redwood Materials, a richly funded battery-recycling startup, unveiled a new business line that repackages old EV batteries to serve data-center demand. The first installation, at Redwood’s campus near Reno, Nevada, fully powered a very small, modular data center using a solar array and a field of former EV battery packs laid out on the desert floor.
Redwood just got its own vote of confidence in that concept: On Thursday, it raised another $350 million from investors including AI-chip leader Nvidia.
Aligned’s commitment to paying for the battery itself could serve as a model of socially responsible AI-infrastructure development.
Some utilities around the country are jumping to build new power plants to support the projected data-center buildout, and charging their regular customers for the investment, hoping the AI titans eventually become paying customers. But this approach risks saddling consumers with unnecessary costs if the AI hubs don’t materialize.
Because Aligned is footing the bill, the utility’s other customers won’t be forced to pay for the data-center firm’s growth ambitions. But, though this one large customer will provide the land and funding, the battery will sit on the utility side of the meter. That means the utility can leverage the tech for other grid uses, like frequency management and capacity, when it’s not maintaining the flow of power to the data center during otherwise scarce hours.
In this case, Martin said, the permitting and buildout could move faster with the battery connecting to the utility grid instead of directly to the data center. In other situations, bigger batteries on the customer side of the meter might make more sense. Calibrant is already working on more and even larger batteries for the AI sector, he added.
“Whereas right now, we think this is unique, I think over a relatively short time horizon it’s going to be much more common,” Martin said. “It’ll start to look surprising if we don’t see projects like this at the largest loads as they connect [to the grid].”
A clarification was made on Oct. 25, 2025: This story originally stated that the local utility studied how many times per year the local grid could run out of electricity if the data center got built. The piece has been updated to clarify that the utility studied how big the battery would need to be to compensate for challenges imposed on the local grid by the data center.
Energy affordability has become a flash point over the past few months. It’s a key issue in this year’s gubernatorial races. It’s something President Donald Trump has promised to fix by boosting fossil-fuel production. And of course, it’s showing up in the bills that arrive in mailboxes every month.
Three-quarters of Americans count electricity costs as a source of stress in their lives, according to a new Associated Press-NORC survey. But a recent study from the Lawrence Berkeley National Laboratory provides more nuance to the conversation. When adjusted for inflation, 31 continental states actually saw their power prices decline from 2019 to 2024, while the other 17 states experienced increases.
One reason why some states saw prices jump? Utility spending on disaster recovery and preparedness. Take California, where utilities have added billions of dollars in wildfire-recovery costs and mitigation programs to retail electricity prices in recent years, the national lab found. It’s a bracing fact as the planet warms and disasters become more frequent and destructive.
But the report also tempered fears that the growth of data centers and other power-hungry industries will jack up electricity prices. Grid maintenance has been a top driver of increased electricity costs over the last few years, but spreading these expenses among more customers — like data centers and manufacturers — has helped lower retail electricity prices, researchers found. One caveat: That dynamic tends to benefit large, commercial consumers more than residential ones.
The Trump administration has elevated fossil fuels as a solution to rising electricity bills, positing that more coal and gas power can cut prices. But building a new gas-fired plant is increasingly expensive and takes years, and the U.S. is preparing to ship more liquefied natural gas out of the country anyway.
If you look at two rare examples of power utilities reducing their rates, it’s clear that falling back on coal isn’t the answer either. In Oregon, Idaho Power Co. has asked regulators to lower electricity prices by nearly 1%, saying the closure of a coal-fired power unit and demolition of another coal plant have brought down costs. And in Virginia, where a state law is pushing the electricity sector to lower emissions, Appalachian Power cited the addition of renewable power in its request to lower rates. West Virginia is meanwhile pushing to keep its coal plants running — a move that Appalachian Power said would raise prices for its electricity customers in that state.
But putting the national lab’s inflation-adjusted numbers aside, it’s clear that rising utility bills are reaching a fever pitch across the country — and it’s going to take both more clean energy and smarter utility regulation to rein them in.
Trump sinks a global shipping-decarbonization plan
Until a few weeks ago, the International Maritime Organization was on track to approve a global shipping-decarbonization strategy. That is, until the Trump administration launched a last-minute offensive and got the United Nations body to delay adoption of the plan, Maria Gallucci and Dan McCarthy reported late last week.
The tens of thousands of shipping vessels that travel the oceans are responsible for about 3% of the world’s annual greenhouse gas emissions. But as Maria points out in her follow-up dive into shipping decarbonization, the industry doesn’t currently have much incentive to replace dirty diesel-powered vessels with lower-carbon alternatives.
Some good news, some bad news for U.S. battery startups
The U.S. Department of Energy slashed another wave of federal funding this week, targeting $700 million in grants for battery and other clean manufacturing projects. Nearly half of that funding had been awarded to Ascend Elements, which had already canceled a portion of its planned battery-recycling facility in Kentucky earlier this year. A smaller portion was going to American Battery Technology Co., which said it will carry on with its lithium mine and refinery project in Nevada.
But it wasn’t a bad week for every battery company. Redwood Materials raised $350 million, which it’ll use to expand its unique energy-storage business that packages together used EV batteries into grid-scale resources that can power data centers and other industrial users. And Pila Energy raised $4 million to keep building batteries that provide backup power to large appliances, but are more affordable and portable than whole-home systems like the Tesla Powerwall.
Losing the reactor race: China has a clear head start on the U.S. when it comes to nuclear power, as China has figured out how to produce reactors cheaply and quickly, while the U.S.’s last project went billions of dollars over budget. (New York Times)
What whales? The Trump administration has repeatedly blamed offshore wind farms for whale deaths but just canceled funding for research meant to protect the marine mammals in an increasingly busy ocean. (Canary Media)
Drill here, drill there, drill everywhere: The Trump administration opens 1.56 million acres of the Arctic National Wildlife Refuge’s coastal plain to new oil and gas leasing, and reportedly plans to open significant swaths of the East and West coasts to offshore drilling as well. (New York Times, Politico)
Testing the grid: Xcel Energy is taking different approaches to building out distributed energy resources depending on the state, installing batteries at local businesses in Minnesota while pursuing a more complicated, legislatively mandated model in Colorado. (Latitude Media)
Battling battery blazes: California passes a new law to strengthen fire-safety standards for grid battery systems after a devastating blaze in Moss Landing earlier this year, though new storage-facility designs have already made similar fires unlikely. (Canary Media)
Flagged and forgotten: The United Nations says governments and oil and gas companies are ignoring nearly 90% of leaks that methane-tracking satellites have detected for them. (Reuters)
A winding road to decarbonization: Rondo Energy’s “heat batteries” could be key to decarbonizing heavy industry, but the company’s first industrial-scale test is at a controversial site: a California oil field. (Canary Media)
From AI to Facebook to Google Maps, the nation’s demand for computing power is growing, with households in the U.S. now averaging a whopping 21 devices — think smartphones, TVs, and thermostats — all connected to the internet.
That was one of many statistics lobbed at North Carolina utility regulators last week as they gathered to grapple with the coming onslaught of data centers, the immense buildings filled with hardware that make our around-the-clock connectivity possible but could strain the state’s electric grid, raise utility bills, and increase pollution.
Over the course of a two-day discussion on how to avoid these downsides, one simple solution came up again and again: Data centers could commit to limiting their electricity consumption slightly for a handful of periods during the year, formalizing the practice of modulating energy use that’s already standard across the industry.
“One of the issues that the commission is particularly interested in is load flexibility,” Karen Kemerait, the commissioner presiding over the technical conference, said to more than one presenter last week, before pressing them on the concept.
In response to Kemerait, experts from Google and other tech giants, along with North Carolina’s predominant utility, Duke Energy, all voiced degrees of support for the notion.
Yet how and whether regulators move to actualize load flexibility remains unclear. The Utilities Commission isn’t required to take action following its Oct. 14 and 15 meeting. And unlike other reforms repeatedly mentioned, such as a special tariff for data centers, the policy doesn’t easily translate to a rate case or other dockets before the panel.
That’s part of why Tyler Norris, a former solar developer and a thought leader on load flexibility who presented last week, hopes it will become a choice for data centers if nothing else.
“At minimum, why not have a voluntary service option that enables a large load to connect faster in exchange for bounded flexibility?” Norris told Canary Media. “In every conversation I’ve been in, I’ve heard no objection to the idea. Obviously, it’s at the discretion of the commission — whether they want to encourage it.”
Data centers aren’t the only new large customers driving ever-growing electricity demand forecasts in North Carolina, which Duke used to justify a massive new fleet of gas plants in its most recent proposed long-term plan. But the centers are the most voracious consumers by far, accounting for over 85% of the energy demand in the economic development pipeline, the utility said last week.
Not all of these facilities in the pipeline will come to fruition: It’s not uncommon for tech companies to request grid connections in multiple locations before deciding where they’ll actually build. But many will materialize, posing thorny issues for the utility and its regulators.
What if Duke can’t build generation quickly enough to serve the energy-hungry centers? Can the company do so while still zeroing out its carbon pollution, as required by state law? How can regulators assure that tech giants, not residential customers, pay for new power plants and associated upgrades to the grid?
Load flexibility could provide an elegant answer to these vexing questions.
The idea is rooted in a counterintuitive reality: Data centers don’t run at maximum tilt 100% of the time — they routinely adjust processing power even as we can post videos to Instagram or EMS responders can transmit lifesaving patient data in the middle of the night.
That’s true for a number of reasons, Norris wrote on his Power and Policy site, including the fact that computer chips could overheat if stretched to their maximum theoretical processing speeds 24/7 and also that data centers plan for redundancy.
“Many facilities are overbuilt to ensure uptime, with servers periodically taken offline for routine maintenance, software upgrades, or hardware replacements,” Norris explained in the August post.
Information on data centers’ exact electricity use is scant, and it appears to vary based on type, but research suggests the facilities’ peak consumption is about 80% of what they could pull from the grid.
Yet utility planners typically assume otherwise, categorizing data centers as “firm loads” that need “firm capacity,” such as an on-demand power plant with an ample supply of fuel, plus an extra reserve margin — in Duke’s case, 22% — in the event of emergency.
In the simplest terms, while Duke might build 122 megawatts of generation to serve a data center that can draw a maximum of 100 megawatts of electricity, the center may never use more than 80 megawatts.
But if prospective data centers were transparent about their electricity-utilization plans and committed to them on paper, utilities could adjust how they anticipate new power capacity — averting the construction of massive amounts of fossil-fuel infrastructure as well as expensive grid improvements.
In September, analytics groups GridLab and Telos Energy published a report finding that Nevada’s biggest utility could delay the need for hundreds of megawatts of new power plants if data centers committed to modest flexibility terms that allow “uptimes” of 99.5%.
Similarly, Norris, a Ph.D. student at Duke University — which has no connection to the utility — is the lead author of a February paper showing that if data centers shaved just 0.5% off their use over the course of the year, 4.1 gigawatts of power capacity in Duke’s territory in the Carolinas could be avoided.
The figure “isn’t everything in terms of their load forecast,” Norris told regulators last week, “but it is arguably a meaningful share.”
While enlisting data centers to curtail their own energy use is still more theory than practice, that’s slowly starting to change. Pacific Gas and Electric in California, for instance, has piloted flexible service agreements that could get data centers online more quickly.
In August, Google announced voluntary flexibility agreements with Indiana Michigan Power and the Tennessee Valley Authority. The following month, the tech giant revealed a similar arrangement with Entergy in Arkansas.
The company vaunted those agreements, along with its plans to self-generate carbon-free electricity, at last week’s meeting. “Google is leaning in,” Rachel Wilson, a representative for the company, told commissioners.
The Data Center Coalition is an alliance of Google, Microsoft, Meta, Amazon, and dozens of other companies that own, operate, or lease data-center capacity. The coalition listed “voluntary demand response and load flexibility” as a recommendation to regulators last week, so long as data centers could get something in return — such as a quicker connection to the grid.
“There has to be some reciprocal value for data centers,” said Lucas Fykes, director of energy policy for the coalition.
Still, the AI race, a lack of transparency about data-center electricity use, and a genuine inability of anyone in this space to predict the future could complicate efforts around load flexibility.
“Not even the most sophisticated data center owner-operators” know what their load will look like in “a rapidly shifting competitive landscape,” Norris wrote in August. “Amid such uncertainty, their preference is generally to maintain maximal optionality.”
Indeed, though Duke expressed openness to load flexibility last week, the company advised caution for the long term.
“Looking at these [load-flexibility agreements] as temporary is important,” said Mike Quinto, the company’s director of planning analytics. “A well-designed voluntary program, that’s great. It’s not something we think should be mandated on a long-term basis.”
And while utilities are well-practiced in demand response for large industrial customers, Public Staff, the state-sanctioned customer advocate, voiced worry last week about scaling the same concept to data centers.
“We haven’t seen these magnitudes trying to interconnect and … potentially drop off the system,” said Dustin Metz, director of the agency’s energy division. “From an academic standpoint, if we can shave off some of those peaks, then that could potentially reduce some of the generation assets that we need to build out,” he said. But enforcement would be essential, and North Carolina is still new to data-center growth. “We’re a little bit of a living lab,” he said.
Home batteries tend to come in two flavors. There are the no-frills, portable systems meant for emergencies, not for full-on integration with solar panels or the power grid. And then there are the Tesla Powerwalls of the world: smart, large devices that can power an entire home but which require a lot of time and money to install.
Cole Ashman, CEO of Pila Energy, wanted to build a battery that combines the best of both of those options — something that is affordable and useful in an emergency but also able to help customers on a daily basis. His years of work at smart-electrical-panel startup Span and as a Powerwall engineer at Tesla gave him the technical chops. His experience growing up in New Orleans and witnessing the aftermath of post-Hurricane Katrina power outages gave him the motivation.
“There’s this need for energy resilience — and hurdles for adoption that exist today,” he said. “We want to bring forward this notion that you don’t have to compromise on the not-so-smart battery or overspend on the primo solution. This is a middle ground.”
The result, the Pila Mesh Home Battery, debuted at the South by Southwest 2025 conference in Texas this spring. On Tuesday, Pila announced it has raised $4 million to scale up manufacturing, via a seed funding round led by R7 Partners and joined by Toyota Ventures, Refactor Capital, GS Futures, and others. The startup aims to deliver its first batteries to customers in early 2026.
Pila’s 1.6-kilowatt-hour batteries retail for $1,299, which is more than what you’d spend for another portable battery with roughly equivalent storage capacity. But unlike the typical portable backup battery, Pila’s sleek, briefcase-sized units are designed to be a constant companion for key home appliances. Set-up is simple: Just plug the battery into a standard wall outlet and connect the equipment you want backed up.
Take a refrigerator — one of the most important things to keep powered when the electricity goes out. Ashman recalled seeing thousands of them on New Orleans street curbs following Hurricane Katrina, abandoned after multiday power outages left them filled with spoiled food.
One Pila battery can power a typical refrigerator for 32 hours, or double that for customers that tack on an “expansion pack.” It also comes with wireless sensors that can be placed inside a fridge to monitor internal temperatures and with on-board sensors that can detect signs of incipient failure of refrigerator compressors from fluctuations in electricity use.
Pila’s batteries don’t just provide value to their owners during blackouts; the devices are also functional when the grid is up and running. They can be programmed to store energy when it’s cheap — say, during midday hours when grid prices are low or rooftop solar is abundant — and deploy that power during afternoon or evening hours, when households often pay higher rates for electricity from utilities.
These are the kinds of features that come standard with large, high-end home batteries like the Tesla Powerwall, sonnenCore+, Enphase IQ, and FranklinWH. But a typical Powerwall costs between $12,000 and $16,000 to buy and install — and the vast majority of them are in owner-occupied single-family homes that went through fairly extensive permitting and utility interconnection processes.
Pila batteries, by contrast, are what Ashman describes as “permissionless” energy infrastructure.
“You don’t ask for permission to put in a new refrigerator,” he said. “Why does this have to be any different?”
That puts Pila in a category of “do-it-yourself” energy systems that are gaining traction around the world.
Take balcony solar systems, which now power more than a million households in Germany and are starting to take off in other European countries. These portable panels generate only a fraction of what rooftop solar systems can provide, but they cost a lot less and can simply plug into an outlet — a much simpler process than getting a professionally installed rooftop array.
Yet balcony solar hasn’t caught on in the U.S., where electrical codes put strict limits on devices that send power back into household circuits. For now, Pila’s software is configured to only allow power to flow from wall sockets into its batteries, not vice versa, Ashman emphasized.
However, as more states pass laws promoting DIY solar and as electrical codes evolve to allow intelligently controlled devices to safely deliver power through wall sockets into household circuits, Pila Mesh batteries can flip to serve that task, Ashman said.
The do-it-yourself design also makes Pila batteries suitable for renters and people living in multifamily housing, who are largely locked out of the solar and battery market today, he said — a frustration Ashman himself has experienced as a renter in New York City.
Consumers want to be able to adopt batteries, solar panels, EV chargers, and the latest all-electric appliances as they see fit, said Andrew Krause, CEO of Northern Pacific Power Systems, a California-based contractor that specializes in solar and battery installations. He’s involved in the Agile Electrification coalition, a group of companies and researchers working to overcome barriers to people electrifying their homes.
“It’s important not to view these things as standalone assets, because as standalone assets they’re marginal. A Pila battery on the grid looks like a vacuum cleaner,” Krause said. “But I’m buying a Pila battery because I have solar on my roof, and I’m trying to handle certain end-use loads that will benefit from a battery and solar, and for which I don’t want to overcommit for a whole-home battery system.”
“It’s just a fractional Powerwall,” he said.
That ethos is appealing to Mackey Saturday, an investor at R7 Partners, which led this week’s investment in Pila. He splits his time between a New York City apartment and a home in Nosara, Costa Rica — and he’d like to have more flexible options for backup power in both places.
“In Costa Rica, while power is readily available, it’s consistently on and off,” he said. “If you want to keep your critical appliances available — not resetting clocks, not having food waste, not having your internet die — that’s hugely valuable.”
Meanwhile, “in New York we have pretty reliable energy,” he said. “But we also have some pretty challenging weather as of late,” like the June heat wave that forced utilities and government officials to issue emergency alerts asking people to conserve energy.
Someday, when Pila’s batteries get the OK to send electricity back to the grid, they could help relieve pressure on the power system, Ashman said.
Ashman highlighted numerous features that could allow Pila batteries to work together as virtual power plants, starting with the wireless mesh network built into each system. The network runs on a 900-megahertz band and allows the batteries to communicate through the walls of a home or even “a 200-unit New York City skyscraper,” he said.
Each battery also contains a cellular modem along with WiFi connections to ensure that individual and meshed batteries have multiple ways to stay in contact with their owners, building managers, or utility control centers, Ashman said. That kind of redundancy is a must-have for eventual use as a grid asset, he added.
Pila is in preliminary discussions with utilities on this front, although it isn’t naming any names. But Ashman noted that the startup presented alongside other providers of plug-and-play home-energy tech, like CraftStrom Solar, at a September pitchfest hosted by the California utility Pacific Gas and Electric.
U.S. utilities have a decidedly mixed track record in terms of how they treat customers installing rooftop solar and backup batteries. Across the country, utilities have campaigned to claw back net-metering incentives for consumers who send solar energy back to the grid, seeing that framework as a threat to electricity sales and a risk to the power system’s stability.
But utility regulators and policymakers are increasingly eager to use these distributed technologies to avoid expensive upgrades to the grid. As electricity demand grows and these cost pressures become more acute, the appeal of systems like Pila’s could grow even larger.
“We’re firm believers that batteries will be inside everything,” Ashman said, echoing a conviction shared by an increasing number of startups, especially in the induction-stove sector. “But we need those batteries to be smart. Having an unintelligent battery in everything might be good for backup, but it doesn’t help solve broader problems in the home or for energy.”
In January, the coastal California town of Moss Landing witnessed the most destructive battery fire in U.S. history. Now, Gov. Gavin Newsom (D) has signed SB 283, a law designed to prevent a repeat of the disaster by strengthening statewide fire safety standards for grid battery installations.
Batteries have become an integral part of California’s push to clean up its electricity system. But the Moss Landing conflagration jolted the state as it burned for several days, provoked evacuations of surrounding communities, and destroyed an old power-plant hall that electricity company Vistra had packed full of lithium-ion batteries in 2020. That disaster has since become a symbol of the apparent risks of adopting large-scale batteries, popping up in conversations about proposed battery projects around the country.
In the years since Moss Landing came online, though, the grid battery industry has moved on from that type of design. These days, most every project places batteries in individual containers spaced out across an open field, which minimizes the chances of a fire spreading between them.
Even with those advances in grid battery designs, state Sen. John Laird saw an opportunity to tighten state requirements in light of what happened in January, and he authored SB 283 to do just that.
“Moss Landing was approved through local planning processes — the state was not involved,” said Laird, a Democrat who represents Moss Landing and much of California’s central coast. “What this bill was designed to do was provide guidance from the state.”
Instead of leaving everything up to local jurisdictions — which may be reviewing a large battery project for the first time — the law requires developers to collaborate with first responders on emergency-response plans. Battery developers must now meet with fire authorities during the design phase, and then bring them in to inspect fire-suppression systems prior to launching commercial operations.
That requirement “codifies an industry best practice to ensure early outreach to the fire department” or other relevant authorities, noted Nick Petrakis, director of engineering at Energy Safety Response Group, a firm that works with battery owners on crafting their emergency-response plans.
An earlier draft of the law would have required California to adopt the National Fire Protection Association’s standards for battery safety. As it happened, the Office of the State Fire Marshal did so back in March, so SB 283 didn’t need to force the issue.
The final text does call for the fire marshal, in the next building code update, to “review and consider proposing provisions that restrict the location of energy storage systems to dedicated-use noncombustible buildings or outdoor installations.” That could lead to an effective ban on projects like Moss Landing that insert batteries into existing structures.
This law isn’t the only state action afoot on this topic. The California Public Utilities Commission updated its own battery standards in March and will monitor compliance. That regulatory body is leading an investigation into the cause of the Moss Landing fire. No official determination has been released yet, but the public can expect the PUC to share its findings when they are complete, Laird said.
California leaders see a safe, sustainable grid storage industry as crucial to reaching the state’s long-term climate goals, because the battery plants facilitate the ongoing buildout of clean energy generation.
In 2020, the year Moss Landing came online, the state had mere hundreds of megawatts of batteries hooked up to help the grid. This year, the state surpassed 15,000 megawatts of installed batteries, and it’s aiming for 52,000 megawatts by 2045. The battery fleet is already helping prevent shortages during summer heat waves and cutting into fossil-gas consumption during evening hours, pushing down the cost of energy at those times.
Energy storage trade groups, eager to maintain the pace of the battery buildout, welcomed the new guidance from SB 283 rather than resisting the imposition of new regulations.
The national group American Clean Power, which advocates for the battery industry among others, spoke favorably of the bill’s potential impact. “SB 283 strengthens safety protocols with support from firefighters, electricians, industry, and utilities — ensuring California can continue leading this growing clean energy sector,” the group wrote in a June fact sheet.
“The latest standards for this technology have proven extremely effective,” said Alex Jackson, executive director of American Clean Power’s California branch, in an emailed statement. “Every state should give local officials the tools and the authority to ensure those standards are in place.”
The California Energy Storage Alliance similarly said it was “proud to support this bill” and praised Newsom for signing it.
Responsible developers already work closely with local emergency-response teams, so the new requirements won’t increase their workload appreciably. Many battery firms worry about how the few battery fires that do happen reflect poorly on the industry as a whole; communities debating whether to allow a battery in their proximity might not appreciate the differences in safety between a Moss Landing–era plant and the state of the art today. In that sense, the fact that California has enhanced its battery safety laws could serve the industry better than an absence of new regulations.
“Everybody’s realistic about how serious the Moss Landing fire was,” Laird said. “The whole industry rests on public confidence that they’re not at risk next to a huge battery storage facility, and the industry wants to help in that assurance.”
Data centers are creating problems for the congested, overburdened U.S. power grid. One company thinks it can crowdsource the solution.
California-based Voltus operates “virtual power plants” across North America, controlling the amount of electricity that participating homes and businesses consume or send to the grid via resources like rooftop solar and batteries.
Last month, the firm unveiled its “bring your own capacity” plan. Put simply, the idea is for data center operators to pay other utility customers to reduce their power use when electricity demand peaks, a move that would diminish strain on the system without disrupting computing processes at data centers.
The proposal comes as the nationwide boom in data center construction pushes electricity demand — and prices — to new heights. These conditions are putting pressure on data center developers, utilities, regulators, and regional grid operators to find ways to enable rapid construction that don’t break the grid, or customers’ wallets.
That’s where the bring-your-own-capacity concept could fill the gaps, said Dana Guernsey, Voltus’ CEO and cofounder.
The approach benefits utilities and their customers because it’s a lot cheaper to reduce energy use than it is to build new power plants and infrastructure. And it benefits data centers by offering a much faster route to getting a grid interconnection, as developers wouldn’t have to wait years for utilities to bring new power generation online.
“The hyperscalers and data center developers are eager to fund this,” Guernsey told Canary Media. “It’s more affordable, it’s faster, and it’s an investment back into the communities.”
Voltus is in a good position to spearhead this work, she said. As a virtual power plant operator, it already aggregates backup batteries, electric vehicles, smart appliances, and other fast-responding technologies to provide on-demand relief to the grid. Voltus was recently dubbed the top company in this sector by analytics firm Wood Mackenzie, and after several years of rapid growth, it now has more than 7.5 gigawatts of scattered “demand response” capacity under management.
In general, virtual power plants, or VPPs, could meet 10% to 20% of U.S. peak grid needs in the coming years and save utility customers roughly $10 billion in annual costs, according to a U.S. Department of Energy analysis released in January. Voltus’ new plan is to harness the power of VPPs to help specifically with the data-center-driven electricity crunch — a creative idea with big potential, if the company can convince utilities to play ball.
Voltus already has one developer on board to participate in its bring-your-own-capacity plan: Cloverleaf Infrastructure, which builds gigawatt-scale data centers.
“The right way to serve data center load quickly, at scale, and less expensively and more sustainably, is to leverage the existing resources on the grid as efficiently as possible,” said Brian Janous, Cloverleaf’s chief commercial officer.
Data centers, which are facing yearslong wait times to connect to the grid, are considering every available option. In Wisconsin, Cloverleaf is planning a flagship data center project that could draw up to 3.5 gigawatts of power from the grid when it’s fully built at the end of 2030. Cloverleaf has worked with utility We Energies and its parent company, WEC Energy Group, to develop a tariff that will put the onus on Cloverleaf to pay for the new resources the utility is building to meet its facility’s energy needs.
While specifics on that deal remain confidential, Janous noted that it could include demand response and VPP resources.
“The conversation we’ve been having with utilities is, we want to connect fast. If you tell us, ‘You have to come back in seven years, after the completion of my latest gas-fired power plant,’ I’ll go somewhere else,” he said. But if Cloverleaf can work with a company like Voltus to supply the necessary energy capacity within months, a utility may be able to connect a data center faster.
Guernsey highlighted other examples of data centers bringing their own capacity to utilities. In August, Google announced agreements with Indiana Michigan Power and the Tennessee Valley Authority to reduce the peak loads of data centers in their territories.
Most of the attention on those deals focused on Google’s commitment to shift its computing workloads to reduce peak grid demand — a novel approach to data center power flexibility that tackles the electricity consumption of the massive racks of servers within the facilities’ walls.
But part of Google’s deal with Indiana Michigan Power includes transferring credits for a portion of carbon-free energy Google has contracted to serve its data centers in the region to help the utility meet its capacity requirements. In this case, the tech giant offered up its renewable-energy resources to cover its data centers’ power use, but Google could have leveraged VPPs for that purpose just as easily, Guernsey said.
Ben Hertz-Shargel, global head of grid-edge research for Wood Mackenzie, agreed that VPPs are theoretically a faster and cheaper means of achieving data center flexibility compared to the alternatives.
Most tech companies haven’t done the hard work that Google has done over the past decade or so to enable flexible computing, he said. Data center developers will face cost and air-quality challenges in using their ubiquitous diesel-fueled backup generators for on-site power. And they may be loath to invest in more expensive options like on-site solar, batteries, and gas-fired generators and microturbines — the “build-your-own-power plants” model some developers are pursuing.
“We don’t think that’s going to be faster or cheaper or more sustainable,” Janous said of the latter model. “We think the better approach is to work with companies like Voltus on how to bring more available resources into the mix.”
Demand-response programs and VPPs can also counteract utility customers’ rising power bills, since these initiatives financially compensate the individuals who allow their energy use to be managed.
“You’re paying homeowners and business owners to be part of the solution to accommodate data centers,” Hertz-Shargel said. “They’re already facing large and growing bill increases, not just because of large loads but because of utility investments, costs of climate change. This is a way to offset that.”
It won’t be easy to turn these ideas into reality.
Utilities and regional grid operators consider demand response and VPPs primarily as a tool for managing existing grid stresses, but are far less eager to allow VPPs to substitute for building more traditional power plants and upgrading the grid. It’s always a tall order to get utilities to do something for the first time, but especially so when dealing with data centers, which can require a small city’s worth of electricity for their operations.
Guernsey conceded these challenges to Voltus’ plan. “Most of the deals we’re discussing start in 2027 or 2028 time frame,” she said. “We’re just running as fast as we can to keep up. We’re growing at a clip of about a gigawatt a year across North America. … In particular regions where data centers are getting built, we usually respond with, ‘We can get a couple hundred megawatts in a given territory within that time.’”
One of Voltus’ key early targets is PJM Interconnection, a grid operator responsible for the transmission system and energy markets serving Washington, D.C., and 13 states from Virginia to Illinois. Electricity bills are spiking for the region’s more than 65 million residents — primarily due to data centers. Similar pressures are pushing up costs across the Midwest, and in data center hotspots like Georgia and Texas.
Johannes Pfeifenberger, a grid-planning expert and principal with The Brattle Group, has argued for years that grid operators need to embrace VPPs and other innovations to deal with rising demand. Among those options, “a VPP is very attractive, whether it’s storage, or controlled EV charging, or heating and air conditioning controls,” he said.
But putting this solution into practice will require grid operators to restructure the rules by which VPPs can directly reduce a data center’s impact on the system, he said. PJM and the Southwest Power Pool, which serves 14 Midwest and Great Plains states, are starting to take on these challenges, but their efforts remain a work in progress.
Data centers may also be limited by the capacity of the power lines and substations at the points they’re seeking to connect to the grid, he said. VPPs that consist of customers scattered across a grid operator’s territory can’t relieve those specific stresses, although other options could, such as data centers colocating at spots with ample grid capacity and building their own generation to fill those gaps, he said.
Guernsey agreed that Voltus’ bring-your-own-capacity construct “can only be a solution when capacity is the problem. If the data center is creating an acute distribution level constraint or requires a substation upgrade, that’s a different type of problem.”
Janous thinks data center developers are willing to pay even more than the currently inflated prices for energy if it means they can move faster. Grid operators just have to be willing to allow them to cut deals with companies like Voltus to go do it.
“Our view from our side is that the market is still undervaluing capacity relative to the willingness to pay for a data center to go faster,” he said.
In the face of those pressures, allowing data centers and VPP providers to bring their own capacity is the kind of fast-track effort that could actually succeed at the speed needed, Guernsey said. And it’s a way to make sure that big developers — rather than ordinary consumers — are the ones paying for the energy capacity that data centers require.
An enormous solar project planned for the Nevada desert was canceled last week while awaiting final federal approvals, an ominous sign for renewables development on public lands under the Trump administration.
Esmeralda 7 was unique for its size: It would have installed 6.2 gigawatts of solar generation and 5.2 gigawatts of battery capacity across 62,300 acres of Nevada desert. No other solar project in the U.S. comes close to that scale. It was also a test case for a new, more efficient approach to federal permitting, one that promised to get clean energy infrastructure built more quickly.
The solar colossus incorporated seven distinct solar-and-battery projects from different developers on adjacent parcels of land overseen by the federal Bureau of Land Management. Instead of each going through an exhaustive process to attain federal permits, the projects banded together to undergo a joint analysis by the BLM. The bureau completed a draft environmental review of the megaproject under the Biden administration, but didn’t release a final version. Instead, as first reported by Heatmap, the BLM website switched the project status to “canceled” on Thursday.
It’s not yet clear if the decision to cancel was made by the BLM or Interior Secretary Doug Burgum, or if the Esmeralda 7 developers pulled out, perhaps based on conversations with the government. An automated email reply from Scott Distel, the BLM contact for the project, said he is not authorized to work during the government shutdown and thus was unable to respond.
The BLM circulated a statement to media on Friday saying that “applicants will now have the option to submit individual project proposals to the BLM to more effectively analyze potential impacts.” Such a move would entail repeating the already-conducted environmental analysis for each project individually, after which the administration could simply move to cancel the projects again.
“While we await further clarity from BLM on its apparent decision to abruptly cancel these solar projects in the late stages of the review process, we remain deeply concerned that this administration continues to flout the law to the detriment of consumers, the grid, and America’s economic competitiveness,” Ben Norris, vice president of regulatory affairs at the Solar Energy Industries Association, wrote in a statement Friday.
President Donald Trump swept into office declaring an “energy emergency” and pledging to unleash more American energy and bring down prices. Since then, though, his administration has intervened to obstruct several major power projects that would deliver renewable electricity to the grid at a time of swiftly rising power demand.
The White House attempted to halt two fully permitted offshore wind farms, the 810-megawatt Empire Wind 1 and the 704-megawatt Revolution Wind. Offshore wind requires permissions from the Interior Department’s Bureau of Ocean Energy Management, giving the administration leverage over this type of private enterprise. Those efforts to stop construction did not hold up, but they incurred millions of dollars of unanticipated costs for the developers, and damaged the country’s reputation as a safe place to invest in billion-dollar infrastructure projects.
Currently, only 4% of terrestrial, utility-scale renewable capacity sits on federal land, according to the National Renewable Energy Laboratory. But in the U.S. West, many federal parcels are well-suited for renewable energy; if these sites were successfully developed, they could greatly increase clean energy production.
Esmeralda 7 appears to be the first large renewable development on public lands to be officially canceled during the Trump administration, said Ted Kelly, director and lead counsel for U.S. clean energy at the Environmental Defense Fund.
Previously, he added, some projects that were expected to move forward were “sitting in limbo,” neither canceled nor approved on schedule. Now, Kelly said, there’s “a real concern” that public lands may be effectively off limits for wind or solar development for the duration of the Trump administration.
While it lasted, Esmeralda 7 modeled a new, more streamlined way to analyze a huge amount of renewable capacity.
“It increases efficiency on the government side, not having to recreate the same review of the same type of impact over and over again,” Kelly noted. Combining the permitting also helps in scrutinizing the cumulative effect of multiple projects, something environmental advocates have pushed for.
The BLM released its draft environmental impact statement in late July 2024, kicking off a 90-day comment period, which included an in-person public meeting and an online one.
The project would have impacted the desert landscape. But the draft environmental review identified those impacts and outlined mitigation efforts needed to protect endangered species and minimize disruption to desert plants. Esmeralda 7 also would have had environmental benefits by displacing polluting power production with emissions-free generation.
Projects that undergo thorough vetting and abide by the government’s conditions have a legal right to move forward, Kelly said. Under U.S. law, the government can’t cancel a project without mustering a set of reasons and evidence; the Administrative Procedures Act forbids “arbitrary and capricious” decisions that violate due process.
“It’s inconsistent with the law, but it’s also obviously inconsistent with what our country needs,” Kelly said of the cancellation.
Several prominent voices outside the clean energy industry expressed alarm at the news. Utah’s Republican Gov. Spencer Cox blasted the cancellation on X, writing, “This is how we lose the AI/energy arms race with China. … Solar with batteries can now be close to baseload power and we should keep these projects rolling until we get the gas/nuclear/geothermal plants we need.”
Billionaire John Arnold, who made a name for himself as a gas trader at Enron, also tweeted about the cancellation, saying, “I’m increasingly worried we’re headed for the cliff.” Coal, hydropower, and nuclear are not projected to grow much in this decade, he noted, so “all growth has to come from gas, solar & wind.”
Halting new wind and solar developments thus threatens the country’s ability to grow electricity supply even as AI companies and leaders in other industries are in desperate need of more power.
A new law in Ohio will fast-track energy projects in places that are hard to argue with: former coal mines and brownfields.
But how much the legislation benefits clean energy will depend on the final rules for its implementation, which the state is working out now.
House Bill 15, which took effect Aug. 14, lets the state’s Department of Development designate such properties as “priority investment areas” at the request of a local government.
The law aims to boost energy production to meet growing demand from data centers and increasing electrification, while applying competitive pressure to rein in power prices.
Targeting former coal mines and brownfields as priority investment areas furthers that goal while encouraging the productive use of land after mining, manufacturing, or other industrial activity ends. Buyers are often wary of acquiring these properties due to the risk of lingering pollution.
The new law could also help developers sidestep the bitter land-use battles that have bogged down other clean-energy projects in Ohio, particularly those looking to use farmland.
Priority areas might “otherwise not see these investments, which can breathe new life into communities, improve energy reliability, provide tax revenue, and lower electricity costs,” said Diane Cherry, deputy director of MAREC Action, a clean-energy industry group.
Ohio has more than 567,000 acres of mine lands and about 50,000 acres of brownfields that are potentially suitable for renewable-energy development, according to a 2024 report from The Nature Conservancy. Federal funding to clean up abandoned mine lands has continued so far under the 2021 bipartisan infrastructure law, so yet more sites may become available. Overall, remediating documented hazards at Ohio’s abandoned mine lands is estimated to cost nearly $586 million, said spokesperson Karina Cheung at the state Department of Natural Resources.
But two Ohio agencies still need to finalize rules before companies can start building energy projects in these underutilized spaces and benefiting from the new law.
The Department of Development has not yet proposed standards for approving requests to designate priority investment areas, said spokesperson Mason Waldvogel. However, in late August, the Ohio Power Siting Board proposed rules to implement HB 15, and the public comment period just closed.
Under the law, approved priority investment areas will get a five-year tax exemption for equipment used to transport electricity or natural gas. The sites will also be eligible for grants of up to $10 million for cleanup and construction preparation.
HB 15 also calls for accelerated regulatory permit review of proposed energy projects in priority investment areas. The Power Siting Board will have 45 days to determine if a permit application is complete, plus another 45 days to make a decision on it.
Those timelines are shorter than the approximately five months HB 15 allows for standard projects. And it’s substantially faster than recent projects where it took the board more than a year to grant or deny applications after they were filed.
Advocates and industry groups generally applaud the new law but want tweaks to the Power Siting Board’s proposed rules.
A big concern is making sure the board will allow wind and solar developments on mine lands and brownfields throughout Ohio, regardless of which county they’re in. Roughly one-third of Ohio’s 88 counties ban wind, solar, or both in all or a significant part of their jurisdiction. This authority was granted to them by a 2021 law, Senate Bill 52.
However, the language and legislative history of HB 15 make clear that it “was meant to be technology-neutral,” said Rebecca Mellino, a climate and energy policy associate for The Nature Conservancy.
HB 15 even states that its terms for permitting energy projects in priority investment areas apply “notwithstanding” some other parts of Ohio law.
“That clause is meant to bypass some of the typical Ohio Power Siting Board procedures — including the procedures for siting in restricted areas” under SB 52, wrote Bill Stanley, Ohio director for The Nature Conservancy, in comments filed with the board.
But the exemption provided by the “notwithstanding” clause is narrow, Mellino added, because local government authorities must ask for a priority investment area designation. That means, for example, that in a county with a solar and wind ban in place, officials would need to choose to request that a former coal mine or brownfield become a priority investment area.
The Nature Conservancy has asked the Power Siting Board to add language making it crystal-clear that renewable-energy projects can be built on any land marked a priority investment area — even if a solar and wind ban otherwise exists in a county.
Industry groups are pushing for additional clarifications to make sure the Power Siting Board meets the permitting deadlines set by the new law, both for expedited and standard projects.
For example, Open Road Renewables, which builds large-scale solar and battery storage, said in comments that, in order to align with HB 15, the board’s rules should require energy developers to notify the public of an application when it is filed, rather than after it is deemed complete.
Separate comments from the American Clean Power Association, MAREC Action, and the Utility Scale Solar Energy Coalition of Ohio ask for tweaks to provisions regarding notices on public hearings and for clarifications on application fees. The board should also promptly issue certificates for projects that are automatically approved, say comments by Robert Brundrett, president of the Ohio Oil and Gas Association.
The Department of Development hopes to finish draft standards and invite public comments on them soon, Waldvogel said. Meanwhile, the department has received its first request to designate a priority investment area. The ask comes from Jefferson County’s board of commissioners, which did not specify the type of energy that may be built in the area.
That request deals with land where FirstEnergy’s former Sammis coal plant is undergoing demolition, as well as the Hollow Rock Landfill, which received waste from the site. HB 15 gives the department 90 days to act on designation requests.
The Ohio Power Siting Board, for its part, is expected to finalize its rules within the next couple of months. Ultimately, said Cherry of MAREC Action, the law “clears the path for developers to bring energy projects online quickly and affordably, something Ohio’s consumers and businesses desperately need.”
The Department of Energy has closed a $1.6 billion loan guarantee for transmission upgrades in the middle of the country — a move that comes as the Trump administration slashes funding for other grid improvements, including a separate transmission megaproject in the Midwest.
The financing from the Department of Energy’s Loan Programs Office will go to a subsidiary of utility giant American Electric Power to overhaul around 5,000 miles of power lines across Indiana, Michigan, Ohio, Oklahoma, and West Virginia. The agency called the deal “the first closed loan guarantee” under a new “Energy Dominance Financing Program” established by President Donald Trump’s landmark tax law, the One Big Beautiful Bill Act.
Despite the Energy Dominance branding, the loan guarantee was originally announced in mid-January by the Biden administration as part of a broader $22.4 billion push to strengthen the grid using LPO funding. The Trump administration has now finalized that loan in a rare example of continuity between the administrations on energy policy.
In a statement, the Energy Department said that “all electric utilities receiving an EDF loan must provide assurance to DOE that financial benefits from the financing will be passed on to the customers of that utility.” A spokesperson for the agency did not immediately respond to Canary Media’s email requesting comment on how those assurances will be monitored and enforced.
“The President has been clear: America must reverse course from the energy subtraction agenda of past administrations and strengthen our electrical grid,” Energy Secretary Chris Wright said in a press release. “This loan guarantee will not only help modernize the grid and expand transmission capacity but will help position the United States to win the AI race and grow our manufacturing base.”
The United States needs more transmission lines to upgrade the aging grid, create room for additional power generation, and increase reliability by making it easier to share electrons across regions. Much of the U.S. grid was built in the 1960s and 1970s, and about 70% of existing transmission lines are over 25 years old and approaching the end of their typical life cycle.
Despite this, the Department of Energy’s Loan Programs Office canceled a $4.9 billion loan guarantee in July to finance construction of the Grain Belt Express, a major transmission project more than a decade in the works and designed to channel power from wind and solar farms in the Great Plains to cities in more densely populated eastern states.
The termination came a week after Sen. Josh Hawley, a Missouri Republican, told The New York Times that he had made a personal appeal to Trump to block the project.
“He said, ‘Well, let’s just resolve this now,’” Hawley told the newspaper. “So he got Chris Wright on the line right there.”
Hawley’s hostility to the Grain Belt Express followed a playbook that has long been deployed by actors across the political spectrum to block transmission projects, amplifying not-in-my-backyard opponents’ anger over seizures of land through eminent domain. In this case, Missouri farmers balked at the transmission route running through their land without, in their view, providing enough direct benefits.
A similar dynamic tanked construction of the 700-mile-long transmission project that Clean Line Energy Partners wanted to build to connect wind farms in Oklahoma to energy users in Tennessee nearly a decade ago, as chronicled in journalist Russell Gold’s book, “Superpower: One Man’s Quest to Transform American Energy.” In Maine, meanwhile, environmental groups teamed up with fossil-fuel companies to pass a 2021 referendum banning construction of a power line connecting New England’s electricity-starved grid to Quebec’s almost-entirely carbon-free hydroelectric system.
The Trump administration has slashed far more than just the Grain Belt Express’ funding. Since taking office, Trump has yanked billions in Biden-era loans and grants for clean-energy projects and clawed back incentives for the sector in the One Big Beautiful Bill Act. One of the few projects to receive steady funding under Trump’s Loan Programs Office has been nuclear developer Holtec International’s bid to restart the Palisades plant in Michigan, which aims to come back online before the end of the year.
The administration also in early October announced a list of billions of dollars more in clean-energy funding cuts targeted primarily at blue states — a list that included 26 grants from the DOE’s Grid Deployment Office, most of which are meant to expand the grid and boost its reliability.
Still, the latest transmission loan — along with the federal government’s AI Action Plan released in July — could signal that the administration is starting to acknowledge the importance of reinforcing the grid, said Thomas Hochman, director of the infrastructure and energy policy program at the right-leaning think tank Foundation for American Innovation.
“From the AI Action Plan to this latest loan, it’s great to see signs of this administration recognizing the centrality of the grid to AI and China competition,” he said.
California Governor Gavin Newsom has vetoed three bills that aimed to boost the use of virtual power plants, undermining an opportunity to decrease the state’s fast-rising electricity costs and increase its grid reliability.
On Friday, Newsom vetoed AB 44, AB 740, and SB 541, which were passed by large majorities in the state legislature last month. Each bill proposed a distinct approach to expanding the state’s use of rooftop solar, backup batteries, electric vehicles, smart thermostats, and other customer-owned energy technologies.
In three separate statements, Newsom argued that the bills would complicate state regulators’ existing efforts to use those technologies to meet clean energy and grid reliability goals.
The moves come as utility costs reach crisis levels in California; its residents now pay roughly twice the U.S. average for their power.
In response, Newsom did sign into law a package of bills aimed at combating cost increases at the state’s three major utilities: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric. But some supporters of the virtual power plant (VPP) bills speculated that these same utilities were to blame for Newsom’s vetoing legislation that could have further driven down costs, as the governor has received significant campaign contributions from PG&E and the policies would have eaten into utility profits.
“These vetoes effectively stall progress on key distributed energy and affordability strategies,” said Kurt Johnson, community energy resilience directorat the Climate Center, a nonprofit group. “Policies and programs in California continue to be killed because they threaten the economic interests of California’s powerful investor-owned utilities.”
Izzy Gardon, Newsom’s director of communications, declined to comment on these critiques in an email response to Canary Media, saying, “The Governor’s veto messages speak for themselves.”
But Edson Perez, who leads California legislative and political engagement for clean-energy trade group Advanced Energy United, argued that the justifications cited in the veto statements fail to adequately consider the value the state’s increasingly large numbers of rooftop solar systems, backup batteries, EVs, and smart appliances can deliver to the grid.
An August report from think tank GridLab and grid-data analytics startup Kevala found that California could cut energy costs for consumers by between $3.7 billion and $13.7 billion in 2030 by triggering home batteries, EV chargers, and smart thermostats to reduce summertime grid demand peaks that drive an outsize portion of utility grid costs.
The Brattle Group, a well-regarded energy consultancy, found in a 2024 analysis that VPPs could provide more than 15% of the state’s peak grid demand by 2035, delivering $550 million in annual utility customer savings. Simply put, paying homes and businesses for the grid value of devices they’ve already bought and installed is cheaper than the alternative of utilities building out new poles and wires and substations to serve peak demand.
“These distributed energy resources are already deployed, connected to customers, and connected to the internet,” Perez said. “The longer we wait to tap into this potential, the longer we waste away the savings.”
To date, the VPP programs run by California’s major utilities have failed to capture that savings value. In fact, the programs administered by the California Public Utilities Commission (CPUC) have seen their overall capacity fall over the past five years or so, even as installations of the underlying technologies have risen.
The saving grace for VPPs in California has been the Demand Side Grid Support program, which is administered by the California Energy Commission (CEC) and has expanded rapidly in the past three years. A Brattle Group study released in August found that the roughly 700 megawatts of capacity from solar-charged batteries in homes and businesses enrolled in the DSGS program could save California utility customers from $28 million to $206 million over the next four years.
But last month the DSGS program was stripped of its funding during last-minute negotiations between legislative leaders and Newsom’s staff, leaving its future in doubt.
That’s frustrating to companies like Sunrun, the leading U.S. residential solar and battery installer, which has enlisted customers in California to supply hundreds of megawatts of DSGS capacity from their solar-charged batteries.
“Do we want to leverage existing infrastructure — electrons in batteries that are already there — and non-ratepayer capital to lower rates for everyone in creating a more efficient and smarter grid?” said Walker Wright, Sunrun’s vice president of public policy. “Yes or no?”
Because of changes made during closed-door negotiations in August, the VPP legislation vetoed by Newsom was relatively limited, but it still would have made a positive difference had it passed, said Gabriela Olmedo, regulatory affairs specialist at EnergyHub, a company that manages demand-side resources and virtual power plants in the U.S. and Canada.
“These were unopposed bills that were pretty uncontroversial but would have made impactful steps toward enhancing load flexibility in California,” she said. “We can’t afford to keep leaving these readily available and affordable solutions off the table.”
SB 541, for instance, would have authorized the CEC to create regulations to track the progress toward a state-mandated goal of achieving 7 gigawatts of “load shift” capacity by 2030 across utilities, community energy providers, and other entities supplying power to customers. Newsom’s veto statement said the bill would have been “disruptive of existing and planned efforts” by the CPUC, CEC, and state grid operator CAISO.
“I’m disappointed in this veto,” state Senator Josh Becker, the Democrat who authored SB 541, said in a statement to Canary Media. “This bill was about affordability,” he said. “Next year this area will be a focus of the clean energy community. Clearly we have some educating to do.”
AB 44 would have authorized the CEC to expand a method it has used to help some of California’s community choice aggregators (CCAs) tap VPPs to reduce peak demand.
Newsom’s veto statement declared that the bill “does not align” with the long-running effort by the CPUC to reform the Resource Adequacy program that sets the rules for how these grid needs are met. But critics say the CPUC has consistently failed to allow VPPs and other distributed energy resources to offset the increasingly high prices that utilities and CCAs are bearing to meet those needs.
AB 740 would have instructed the CEC to work with the CPUC, CAISO, and an advisory group representing disadvantaged communities to adopt a VPP deployment plan by November 2026.
Newsom’s veto statement declared that the bill would result in “costs to the CEC’s primary operating fund, which is currently facing an ongoing structural deficit.” But critics have pointed out that the text of the law would have instructed the VPP plan only to move forward “subject to available funding,” which would have forestalled any budget impacts.
“Even if it were signed, it would not have to be implemented unless the state budget proactively funded it,” Perez said. “It is very disappointing that we can’t even have the agencies talk about this in a comprehensive way. It’s kind of shocking that even that’s not allowed.”
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