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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.”
Power demand from data centers threatens to scuttle utility decarbonization goals, push grid infrastructure to the brink, and drive up electricity costs for everyday customers already struggling to pay their bills.
But a new report identifies a strategy that utility planners can take to avoid these problems while still providing data centers with the massive amounts of power they require. They simply need to convince data centers to use less electricity from time to time — and they need to do so early in the utility planning process, when it’s still a win-win for both developers and utilities.
The report, based on research conducted by analysis firms GridLab and Telos Energy, used NV Energy, Nevada’s biggest utility, as a case study. According to its numbers, NV Energy could save hundreds of millions of dollars and defer hundreds of megawatts of “new firm capacity needs” — i.e., fossil-gas-fired power plants — if the proposed new data centers in its territory agree to be flexible.
But all these benefits are predicated on that flexibility being “factored into resource planning early on rather than being an afterthought,” Priya Sreedharan, a senior program director at GridLab, said during a webinar last week. Without that vital early work, utilities will lock in multibillion-dollar investments to manage the grid peaks that they assume inflexible data centers will cause.
And once those plans are in motion, the chief incentive for data-center developers to commit to being flexible with their energy — getting faster grid interconnections — will evaporate.
Grid planners and utilities face an unprecedented wave of power demand as tech giants race to build data centers to support their artificial-intelligence ambitions. In many cases, plans for new data centers — the largest of which can use as much power as a small city — are spurring the construction of new fossil-fueled power plants, putting decarbonization further out of reach and raising costs for consumers.
The GridLab–Telos Energy report adds to a growing body of work identifying flexibility as a way for data centers to connect to the grid quickly without causing utility costs and emissions to skyrocket.
To become flexible, data centers will need to invest in gas-fired generators, batteries, solar panels, or other resources to supply their own power needs during times of peak demand. Or they’ll need to take on the technically complex task of ramping down power-hungry computing processes when the grid is under the greatest stress.
Data centers won’t do that just to save money on their electric bills, said Derek Stenclik, founding partner at Telos Energy. But they might do it to speed up when they get connected to the grid — or, in data-center parlance, “time to power.”
In some parts of the country, data centers are struggling to get the grid connections they need even though they’re willing to pay extremely high power prices to secure them. That’s because building the power plants and grid infrastructure to meet their demands can take years.
“If you go to a prospective data center and say, ‘Hey, with our queue, it’s going to take five years for us to bring on new resources to build the transmission to get to you and you can wait five years, or we can interconnect you in two years if you’re willing to curtail 10 to 12 hours a year,’ the answer there will be much, much different than if you’re asking them after they’ve been designed,” Stenclik said.
GridLab and Telos Energy chose NV Energy as a test case for a few reasons.
First, the utility has a ton of new data centers trying to connect to its grid — enough to add 2 gigawatts of peak load by 2030 — and keeping up with that demand will be expensive. Former NV Energy CEO Doug Cannon told the Nevada Appeal in February that the utility may need “billions of dollars of investment” to “double, triple, even quadruple the size of the total electric grid” in the northern Nevada region where most of the new data centers are being built.
Second, GridLab and Telos were ready to model the impact of flexible data centers in the region because they served as experts for groups intervening in the utility’s 2024 integrated resource plan. Utilities, regulators, and other stakeholders use these plans to figure out what mix of generation resources are required to meet future grid needs.
NV Energy’s latest plan calls for converting a coal-fired power plant in northern Nevada to run on fossil gas, rather than building solar and batteries at the site, as it had previously proposed — a decision opponents are formally challenging because they argue it will increase customer costs. Like many U.S. utilities, NV Energy faces backlash over rising rates, including an overcharging scandal that coincided with Cannon’s resignation in May.
Similar load-growth pressures driven by the AI data-center boom are pushing utilities across the country to plan far more new gas-fired power plants, at great cost not only to the climate but also to customers, who will pay higher bills to cover the cost of building and fueling them. Data centers are already pushing up electricity rates in some parts of the country.
Flexible data centers could make a big dent in these costs by allowing utilities to rely more on solar and batteries, which are less costly and faster to build than gas plants. GridLab and Telos Energy’s fact sheet on their analysis of NV Energy found that “even modest levels of load flexibility can yield large capacity savings.”
Specifically, the report found that 1 GW of data-center flexibility could defer from 665 to 865 megawatts of new firm capacity needs and save $300 million to $400 million through 2050. Those savings would come from alleviating the utility’s need to build more gas-fired power plants and from substituting more “lower cost ‘energy’ focused resources such as solar plus storage.”
Getting data centers to commit to energy-flexible operations could make a huge difference across the country, according to Tyler Norris, a Duke University doctoral fellow who is a former solar developer and special adviser at the Department of Energy. He co-authored an analysis released in February that found nearly 100 gigawatts of existing capacity on U.S. grids for data centers that can commit to a certain level of flexibility.
Getting data centers to ease off during specific hours of the year is eminently feasible, Norris argued in an August presentation to state utility regulators. Data centers’ “capacity utilization” rates — a measure of how much of their total potential power demand they’re using across all hours of the year — are all over the map, with some analyses estimating rates as low as 50%.
But utility planners can’t build a grid around estimates, and data-center developers don’t have good reasons to commit to using less power unless they see a clear reward.
“Not even the most sophisticated data center owner-operators necessarily know what their utilization rates and load shapes will look like,” Norris wrote in an August blog post. “Their preference is generally to maintain maximal optionality” — that is, to demand as much access to as much always-available power as they can get.
Nor do data centers have a clear path to achieve the kind of flexibility that utility planners may demand, said Ben Hertz-Shargel, global head of grid-edge research for analytics firm Wood Mackenzie.
“There are two main ways to make data centers flexible,” Hertz-Shargel said. “You can make the compute flexible. Or you can use backup generation, which is almost always diesel today.”
But data centers can’t run megawatts of noisy, polluting, and expensive diesel generators without running afoul of air-quality regulations and enraging neighbors, he said. True flexibility will require more novel options like gas-fired generators and batteries charged from the grid or on-site solar systems, he added.
Meanwhile, flexible computing is in its early stages. Of the major tech giants, only Google has actively engaged with utilities to shift computing to match grid needs. Experiments from companies such as Emerald AI have shown “some auspicious results,” Hertz-Shargel said. “But for the industry to count on that, it’s too early.”
Utilities and regulators will also need to adapt how they plan for serving flexible data centers, Telos Energy’s Stenclik said. Today, they’re taking on rising data-center costs in a multitude of ways, from crafting special tariffs to govern their impact to allowing tech giants to contract for 24/7 clean energy resources in order to supply their power demands. But he wasn’t aware of any utility that has undertaken a real-world version of the kind of demand-side flexibility analysis that GridLab and Telos did.
Utilities should start working on it, given the alternatives, he said. “We’re leading to higher total capacity needs. We’ve seen huge challenges on the supply chain. We’re out five, six years from new gas turbines now,” he estimated.
“I think there’s a ton of latent flexibility,” he concluded. “We’re just asking for it at the wrong time. If you ask for it when they’re already built and designed and on the system, the answer is going to be no. If we trade speed to interconnect for flexibility, I think the answer will absolutely be yes.”
Investment in cleantech startups is tracking toward the lowest level in years. But Base Power shrugged off the market trends and just raised $1 billion to turbocharge its home battery buildout.
The colossal Series C funding round comes only six months after it raised $200 million in an April Series B. Addition led the latest round, which brought back all previous investors, including Andreessen Horowitz and Valor Equity Partners. The company’s valuation now stands at $4 billion after receiving the new investment, Base Power founder and CEO Zach Dell said.
The pace and scale of those investments put the Austin, Texas–based firm in a league of its own among clean energy startups this year — beating out even the outlandish $863 million that Commonwealth Fusion Systems raised in August. Dell says his company’s traction comes down to a very clear value proposition: It’s potentially the fastest way to expand on-demand grid power at a time when everyone wants more of it.
“Right now, we’re in a capacity crunch — everyone needs capacity,” Dell said. “We install capacity faster and cheaper than really anyone out there.”
The U.S. is going through the fastest electricity demand growth in decades, as AI data centers proliferate, more factories open up, and customers purchase electric vehicles. Utilities have long maintained a skeptical stance toward startups’ plans to turn home energy devices into substantial forces on the grid; now, Dell said, they’re not just willing but “more excited than ever” to have that conversation.
The key to Base Power’s model is finding households in Texas who want cheap electricity with the benefit of backup power. The company becomes their retail power provider and installs one or two unusually large batteries on-site. Base owns the batteries, and the customers pay an installation fee starting at $695 and a small monthly rate instead of purchasing them for many thousands of dollars. Then the startup aggregates this dispersed fleet of batteries to essentially create miniature power plants it can profit from in the state’s competitive energy market.
The batteries earn money through simple arbitrage: They charge up when wind or solar production pushes prices down and then discharge when demand and prices spike. Base Power also earned certification to deliver ancillary services, which are rapid-fire adjustments to maintain grid reliability, for which batteries are uniquely suited. The company has already maxed out the 20 megawatts it can bid through the Aggregate Distributed Energy Resource pilot, a virtual-power-plant program, and is pushing for the cap to be raised, Dell said.
Base Power has begun selling its services to regulated utilities so that they can help their customers with backup power and free up more grid capacity. And Dell is scoping out other geographical markets where the rules could allow the Base Power model to grow. But for now, Texas is the ideal place to start. It not only has the competitive market run by the Electric Reliability Council of Texas, or ERCOT, but it is also awash in more utility-scale solar and wind than any other state, enhancing the value of battery-based arbitrage.
When Dell spoke to Canary Media for the previous fundraise, he employed 100 people, and his in-house teams were installing 20 home battery systems per day, for a total of about 10 megawatt-hours in March. Now Base Power employs 250 people and installs double that rate. A year from now, Dell wants to install 100 megawatt-hours per month.
That’s a brash goal for a 2-year-old company. But Base Power has actually followed through on its goals, a rare distinction among buzzy cleantech startups. In April, Dell had promised 100 megawatt-hours of cumulative installations by midsummer; he hit that target and is now approaching 150 megawatt-hours.
The firm has also been planning to move from contract manufacturing for its bespoke battery enclosures to in-house manufacturing. In April, Dell said he planned to break ground on a factory near Austin by the end of the year. Now the company has leased the old Austin American-Statesman newspaper headquarters in the heart of town and has begun moving in manufacturing equipment.
“It’s a 90,000-square-foot empty warehouse that happens to be right across the street from our HQ. There’s massive amounts of benefits you get from colocating engineering and manufacturing — having the engineers be really close to the factory, being able to walk the line and make iterations in real time.”
This factory will take imported battery cells and build the modules, packs, and power electronics needed to turn them into large home-battery products. The plan is to start manufacturing in the first quarter of 2026 and ramp up to 4 gigawatt-hours per year of production capacity, Dell said. This supply chain strategy also shores up compliance with new federal rules limiting tax credits for batteries that contain too much content from China.
Base Power is already finalizing a location for a “much, much larger” facility outside Austin to continue growing its manufacturing capacity.
Other startups have opted for “capital light” strategies to get solar or batteries into the hands of customers. Base Power, in contrast, went capital-heavy, fronting the money to design, own, and install the batteries with the expectation of making future profits on their capacity. It’s too soon to know how that business bet will play out over years, but Dell indicated the early returns were attractive.
“It’s hard to raise a billion dollars without that,” he noted. “The math is indeed mathing.”
The U.S. is a nation of air-conditioned houses, and this ubiquitous cooling machinery drives an outsize chunk of the country’s electrical demand, especially during heat waves. Now, as utilities scramble to meet even more power demand for AI computing, legacy air-conditioning giant Carrier has launched a new business venture to make regular old HVAC equipment part of the solution.
The concept is simple enough: Put a battery on central ACs that can charge up when energy is plentiful and take over the job of running the appliances when the grid is stressed. But actually doing that requires grappling with the forces that shape America’s energy system — monopoly utilities, regulators, decentralized energy, intermittent renewable power, and the looming colossus of data centers’ energy consumption.
“The homes we have and the fact that they all have air conditioning or a heat pump defines how the grid is sized, built, and operated today,” said Hakan Yilmaz, Carrier’s chief technology and sustainability officer and head of its energy-solutions arm, in an interview at this month’s RE+ conference. “The [U.S.’s] peak load is about 750 gigawatts — that’s what the grid can manage today. Around 300 gigawatts of that is reserved for HVAC.”
Now Carrier has begun installing its HVAC-connected batteries in a pilot test with utilities to prove that the product works in customers’ homes. Some 15 households have the batteries already, and the company plans to install more by the end of the year. The Electric Power Research Institute, a nonprofit that studies emerging grid technologies to inform the power sector, will document the performance.
“We want to measure the reality of what happens — the profile of load shifting across weather conditions,” said Ron Domitrovic, senior program manager for electrification and customer solutions at EPRI.
Carrier hopes to eventually scale up the plan by getting electric utilities to pay for the batteries when households in their territory buy the company’s air conditioners. Then Carrier would operate the batteries based on signals from each utility, charging the devices at times of cheap, clean energy — like during midday in regions with lots of solar generation — and powering the cooling system directly from the battery when electricity demand surges.
“If we replace an HVAC unit today with a battery-integrated HVAC, the load of that HVAC unit never shows up at the peak for the next 15 years,” Yilmaz said. “Use that electricity somewhere else, [like] in the data center.”
Carrier’s market domination — the company has been making air conditioners since its founder, Willis Carrier, invented the thing in 1902 — means that it could scale up and reach far more households far more quickly than residential batteries have thus far.
Carrier, in short, is the rare century-old incumbent trying to shake up its own business to respond to the dynamic shifts in the contemporary energy market.
“Air conditioners really rely on electricity, and in most parts of the world the electricity is still being powered by fossil-based sources,” said Ankit Kalanki, who studies HVAC climate impacts as a principal on the carbon-free buildings team at think tank RMI. “The most demand for air conditioning happens on the hottest days, and at that time the grid is already under strain.”
The power mix gets dirtier in the peak hours — California regularly runs on huge amounts of solar power at noon on sunny days but fires up its gas-burning peaker plants to meet demand in the evenings. So HVAC use at peak times exacerbates carbon emissions and challenges the grid’s ability to deliver enough power.
To mitigate those effects, Yilmaz’s team at Carrier designed a modular battery that sits under or next to its outdoor HVAC units and matches their electricity consumption during peak hours. The batteries range from 5 to 10 kilowatt-hours.
The alternating-current electricity from the home gets converted to direct current for storage in the battery; then the battery supplies DC power right into the HVAC equipment. The duo operate like a nanogrid, connected to the house but separate from all the other appliances. This improves efficiency compared to shipping electricity into and out of a general home battery, losing some energy on each AC-to-DC conversion.
Carrier’s software tracks when the grid supply is “cleaner, greener, cheaper, and more resilient,” Yilmaz said. The goal would be to load up at the cheapest and cleanest times to offset demand in the more expensive and carbon-intensive hours.
Of course, that interaction with the broader energy system goes beyond the usual scope of an HVAC vendor.
“Carrier has a scale that can really make this a much more viable solution for consumers, but it will require the right channels and the right partners to make it happen,” Kalanki said. “It has to be a collaborative effort between utilities and manufacturers and also consumers.”
Carrier has already worked to get utilities on board — hence the testing with EPRI, designed to show the hardware and its controls are up to the industry’s specifications. The company convened an advisory board of utilities covering “the most congested grids” across the country, Yilmaz said. Some of them want to dispatch the batteries based on day-ahead signals, others want to toggle them in real time.
Clearing that hurdle, Carrier wants to help utilities win regulatory approval to pay for these batteries on behalf of all their customers. Regulators have long granted funds for utilities to invest in energy efficiency or demand reduction for individual households as a way to save money for consumers as a whole.
In theory, these HVAC batteries could deliver all the benefits that distributed-energy startups have pitched over the last decade or two: They could defer or eliminate upgrades to the distribution or transmission grid; reduce the need for expensive, fossil-fueled peaker plants; expand utilization of renewable power by shifting it from hours of surplus; and, that new imperative of all grid planners, free up valuable peak capacity for data centers and factories.
That last point also answers the question of why utilities would go for a concept that seemingly threatens their traditional business model. Regulated utilities earn guaranteed profits from building things, like grid expansions or new power plants; Carrier’s plan would diminish the need for those investments. But in the AI era, customer-sited energy devices could look less like a competitive threat and more like a helpful tool as utilities race to catch up with skyrocketing demand.
“We want this technology to work for the utilities so that they can provide more affordable and reliable power to homeowners and industrial growth companies,” Yilmaz said. “It’s a win-win for everyone.”
Consumers can already reduce their peak demand with tools like smart thermostats that turn down HVAC usage, smart plugs that turn off devices, or smart chargers that delay when an electric vehicle refills its battery. But those techniques generally impose some inconvenience, like a warmer home during peak hours or a task delayed to later.
“People tend to think about energy efficiency in isolation and don’t think that cooling is a people-centric issue,” Kalanki said. “HVAC systems are enabling people to feel comfortable on the hot, humid days of the year. In trying to solve for efficiency or the emissions problem, you can create a thermal comfort problem, which should not be the case.”
Also, for many households, Yilmaz noted, the air conditioner is the biggest purchase after a home and a vehicle.
“We have such a big investment from the homeowner, and when they need it the most, the hottest day of the year, you ask them to [dial it back],” he said. “It is very counterintuitive. We think we can do better.”
The software to accomplish this will be powered by Carrier’s acquisition of Viessmann Climate Solutions, a home-energy-management company from Germany. That team includes a large group of software engineers who manage everything from solar to batteries and heat pumps in Europe, Yilmaz said, providing Carrier expertise to lean on as it works to control batteries in the U.S.
The residential battery market, led by brands like Tesla and Enphase, keeps setting records: Last year, homes in the U.S. installed more than 1,250 megawatts of capacity. But the scale of home air-conditioning adoption is staggering compared to residential batteries so far.
Two-thirds of U.S. households use central air conditioning (or heat pumps), and those systems need to be replaced every 10 to 15 years. That translates to around 7 million home HVAC units getting swapped out every year, and Carrier alone sells about 2.5 million of those. The average peak HVAC consumption is 3 kilowatts, Yilmaz said. That math works out to an average of more than 20 megawatts of new electricity demand installed every day from Carrier HVAC alone.
Put another way, if Carrier can get to the point of selling batteries alongside just 16% of its U.S. HVAC units, it would singlehandedly match the current rate of home battery deployment nationwide. Something like that seems eminently doable, over a few years, if Carrier can bring along a handful of the biggest utilities and their regulators.
The company also has to convince customers to participate, even if the battery is free. Domitrovic, from EPRI, noted that the Carrier batteries come with “limited” or “potentially undetectable” impacts on the consumer, while conferring good things like bill savings and greater grid reliability.
The bill savings could be significant, provided that the customer pays different rates for electricity during peak and off-peak times. That approach has been adopted via “time-of-use” rates in some utility territories. Carrier envisions that the batteries would charge up during the hours when customers pay a lower rate, then would reduce consumption in the hours when power prices surge. (Some energy is lost in the process of storing and retrieving electricity, but Yilmaz said utilities can compensate customers so they aren’t negatively affected.)
Volunteering for an HVAC battery also could incrementally reduce the risk of local outages during extreme weather, but is that something that motivates the average person to raise their hand? Perhaps an up-front cash bonus would do the trick. Carrier is considering a range of possible incentives, and finding the right consumer-psychology strategy will be a crucial step for the plan to succeed.
After years of failed attempts, California lawmakers have cleared the way to create an electricity-trading market that would stretch across the U.S. West. Advocates say that could cut the region’s power costs by billions of dollars and support the growth of renewable energy. But opponents say it may make the state’s climate and clean-energy policies vulnerable to the Trump administration.
Those are the fault lines over AB 825, also known as the “Pathways Initiative” bill, which was signed into law by Democratic Gov. Gavin Newsom on Sept. 19 as part of a major climate-and-energy legislative package. The law will grant the California Independent System Operator (CAISO), which runs the transmission grid and energy markets in most of the state, the authority to collaborate with other states and utilities across the West to create a shared day-ahead energy-trading regime.
Passage of this bill won’t create that market overnight — that will take years of negotiations. CAISO’s board wouldn’t even be allowed to vote on creating the market until 2028.
But for advocates who’ve been working for more than a decade on plans for a West-wide regional energy market, it’s a momentous advance. “We’ve shot the starting gun,” said Brian Turner, a director at clean-energy trade group Advanced Energy United, which was outspoken in support of the legislation.
Today, utilities across the Western U.S. trade energy via bilateral arrangements — a clunky and inefficient way to take advantage of cheaper or cleaner power available across an interconnected transmission grid. An integrated day-ahead trading regime could drive major savings for all participants — nearly $1.2 billion per year, according to a 2022 study commissioned by CAISO.
That integrated market could create opportunities for solar power from California and the Southwest and wind power from the Rocky Mountains and Pacific Northwest to be shared more efficiently, driving down energy costs and increasing reliability during extreme weather.
Lower-cost power more readily deliverable to where it’s needed could also reduce consumers’ monthly utility bills — a welcome prospect at a time of soaring electricity rates.
The regional energy market plan is backed by a coalition that includes clean-energy trade groups such as Advanced Energy United and the American Clean Power Association; environmental groups including the Sierra Club, Union of Concerned Scientists, and the Natural Resources Defense Council; business groups including the California Chamber of Commerce and the Clean Energy Buyers Association; and the state’s major utilities. It also has the backing of U.S. senators representing California, Oregon, and Washington, all states with strong clean-energy goals.
Assemblymember Cottie Petrie-Norris, a Democrat who authored AB 825, said in a statement following its passage that it “will protect California’s energy independence while opening the door to new opportunities to build and share renewable power across the West.”
But consumer advocates, including The Utility Reform Network, Consumer Watchdog, and Public Citizen, say the bill as passed fails to protect that energy independence. The Center for Biological Diversity and the Environmental Working Group share their concerns. They fear a new trading market will allow fossil fuel–friendly states like Idaho, Utah, and Wyoming to push costly, dirty coal power into California — and give an opening to the Trump administration to use the federal government’s power over regional energy markets to undermine the state’s clean-energy agenda.
The arguments for a day-ahead energy-trading market can be boiled down to a simple concept, Turner said — bigger is better. Being able to obtain power from across the region could reduce the amount of generation capacity that individual utilities have to build. And tapping into energy supplies spanning from the Pacific Ocean to the Rocky Mountains would allow states undergoing heat waves and winter storms to draw on power from parts of the region that aren’t under the same grid stress, improving resiliency against extreme weather.
A Western trading market could also serve as a starting point for even more integrated activity between the dozens of utilities in the region that now plan and build power plants and transmission grids in an uncoordinated way. A 2022 study commissioned by Advanced Energy United found that a regional energy organization could yield $2 billion in annual energy savings, enable up to 4.4 gigawatts of additional clean power, and create hundreds of thousands of permanent jobs.
CAISO proposed this Extended Day-Ahead Market (EDAM) concept six years ago as an expansion of the real-time energy trading it already conducts with utilities across the West. CAISO’s EDAM scheme is competing with another prospective day-ahead market being promoted by the Southwest Power Pool, a regional grid operator based in Arkansas that serves 14 Midwest and Great Plains states.
For advocates of a Western market, the chief challenge has been to design a structure that doesn’t give up California’s control over its own energy and climate policies, but allows other states and their utilities a share of decision-making authority over how the market works. Taking a lead on that design work has been the West-Wide Governance Pathways Initiative, a group of utilities, state regulators, and environmental and consumer advocates.
Regional-market boosters tried and failed to pass enabling legislation in California in 2017 and 2018 in the face of opposition from environmental groups that feared the plan would clear the way for coal-fired power to come in from other states. Labor unions representing California utility workers also opposed those earlier bills on the grounds that cheaper out-of-state power could lead to less clean energy being built in California.
But many of these prior opponents, including the Sierra Club and key unions, came around to support the latest plan.
With the passage of AB 825, “we’re looking at a fairly rapid and clear rollout of the organization, so that Western states and utilities can begin to get engaged,” Turner said.
But by engaging in a regional energy market, California could risk losing some control over its climate and clean-energy progress, critics say. They argue that the final version of AB 825 doesn’t have enough protections against this outcome.
“We’re strongly opposed,” said Matthew Freedman, staff attorney at The Utility Reform Network (TURN). Previous versions of the bill “had a bunch of provisions we thought would have protected California’s sovereignty and prevented the federal government from weaponizing its authority. Most of those protections were stripped from the bill, inexplicably.”
In particular, in May, TURN and its allies pushed to add an amendment that would have created an oversight council including California lawmakers that would have had the authority to pull the state out of the market if they determined it would raise energy costs or work against the state’s carbon-emissions goals.
“It’s about retaining the state’s sovereignty,” said Jamie Court, president of Consumer Watchdog. “This is our last political check on when we get into the market and when we get out of the market.”
But the provisions in that amendment were “poison pills” for other states considering membership in the market, said Merrian Borgeson, California policy director for climate and energy for NRDC, which supported the legislation. “That would have made it far too unstable.”
The final version of AB 825 still gives California lawmakers the authority to pull the state out of the regional day-ahead market, said Turner of Advanced Energy United — just not via the hair-trigger structure that opponents had sought. “At any time, the Legislature could say, ‘This market is no longer in the interest of California. We’re going to order the Public Utilities Commission to order the utilities to stop participating in this market,’” he said.
The bill’s authors argue that they got the balance right. State Sen. Josh Becker, a Democrat whose bill initially contained the Pathways proposal before it was shifted into AB 825, said that the final structure “provides the accountability that some folks wanted but that’s also enticing to market participants.”
However, TURN and Consumer Watchdog say that the risks outweigh the benefits — particularly if an expanded market exposes the state to federal interference. The Trump administration has been using federal emergency powers to prevent regional grid operators from closing coal plants set for retirement, and it may seek to force the Federal Energy Regulatory Commission to abandon its historically apolitical approach to governing regional energy markets, which could “frustrate key state environmental, resource-planning, reliability, or other public-interest policies,” Freedman said.
“Why California should give up its governance over that regional market is a mystery to me,” he said. “We have no faith that federal agencies will act with good faith or common sense or the law.”
Turner at Advanced Energy United disagrees with that assessment. “CAISO is currently a FERC-regulated market, and this will not increase its exposure to FERC regulation,” he said.
In the end, AB 825 won the support of what Becker described as a “broad and unprecedented coalition spanning environmental organizations, labor, business, and consumer advocates.”
In fact, joining with other states might actually strengthen California’s position against Trump administration overreach, Turner argued. “We understand the federal government may try to distort the free market in ways that benefit their preferred technologies,” he said. “There is a very credible argument to be made that joining shoulder to shoulder with other states improves our ability to defend ourselves against those kinds of things.”
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