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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.”
Illinois could start turning homes and businesses into “virtual power plants” with solar-powered batteries aiding the grid, under a bill that has been gaining momentum in the state legislature.
In Puerto Rico, Vermont, California, Texas, and other states, virtual power plants have helped the grid survive spikes in demand, avoiding outages or the need to fire up gas-fueled peaker plants, and saving consumers money.
Illinois is among the areas expecting electricity demand to grow rapidly because of new data centers; meanwhile, the state is mandated to phase out fossil-fuel generation by 2045, and residential and commercial solar have boomed thanks to state incentive programs. If those solar arrays were paired with batteries, they could provide crucial clean power to the grid during high demand.
HB 4120, an ambitious bill that Illinois lawmakers may consider during an October veto session, would create a basic virtual power plant (VPP) program while mandating that the state’s two largest utilities — ComEd and Ameren — propose their own VPP programs by 2027.
The bill’s plan would offer a rebate to customers who purchase a battery, if they agree to let the battery be tapped for several hours a day during the summer months, when air conditioners drive up electricity use.
The Illinois proposal is less nuanced and comprehensive than VPP programs in other states. For example, in Vermont, Green Mountain Power subsidizes the purchase of batteries, which the utility can then tap while also controlling customers’ smart thermostats, EV chargers, and water heaters whenever the grid is stressed.
But stakeholders in the solar and energy storage industry say Illinois’ proposal is an important first step, opening the door for more ambitious VPP services.
“A utility may want a program to address ‘emergency calls’ to reduce peak load, or deal with a winter peaking issue, or address locational capacity constraints,” said Amy Heart, senior vice president of public policy at Sunrun, a national company that has invested heavily in Illinois solar and that runs VPPs in Puerto Rico, California, and other places. “There is an official pathway and timeline for all of this.”
Energy players in Illinois have been talking seriously about VPPs for several years, during negotiations over what has now become HB 4120. The legislation would incentivize the construction of large-scale energy storage in Illinois, through procurement by the state power agency. VPPs, meanwhile, would provide a decentralized form of storage.
Under the bill’s VPP program, residential customers would get a rebate of $300 per kilowatt-hour on the capacity of the battery they purchase, and then receive at least $10 per kilowatt during scheduled dispatches from 4 p.m. to 6 p.m. on weekdays in June, July, August, and September for a five-year period. “It’s sort of a ‘set-it and forget-it’ program,” said Heart.
Illinois residents already receive a rebate for the same amount when they purchase a battery, but with the new rules, consumers would need to participate in the VPP program to qualify.
All community solar projects with storage would be required to participate in the VPP program, dispatching from 4 p.m. to 7 p.m.
ComEd, which serves northern Illinois, and Ameren, which serves most of the rest of the state, could petition the Illinois Commerce Commission for permission to tap the batteries on a different schedule, for no more than two or three hours a day over 80 days each year.
The basic program would not help with peak demand during unscheduled times — like unexpectedly hot fall weather. But at least utilities would be guaranteed power during the scheduled peaks, said Heart.
“People wanted to move quickly,” on getting a VPP program in the legislation, she added. “You avoid delays [caused by] trying to make this perfect. Industry is talking about how we need stability; nonprofits, ratepayer advocates, utilities, [and] labor are all talking about why we need these investments.”
Illinois, like many states, has demand-response programs that are often considered part of virtual power plants, helping people reduce their energy use during peak demand. And ComEd has already proposed a VPP program to state regulators.
But legislation is crucial for VPPs to really take off, to ensure that programs “feature robust participation, innovation by aggregators, and a wide range of benefits,” said Samarth Medakkar, policy principal for Advanced Energy United, a national trade association of power, transportation, and software companies focused on clean energy.
Illinois’ bill would permit third-party aggregators to manage VPP deployment, a common setup in other states wherein a company, like Virtual Peaker in Vermont, coordinates battery deployment and demand response for the customer and utility.
ComEd and Ameren would be required to file reports by the end of 2028 detailing how many people have enrolled in the VPP program and its effects on energy supply.
By the end of 2027, the companies would have to file proposals for their own VPP programs, which the state regulatory commission must approve by the close of 2028. Those programs would need to include higher incentives for low- to moderate-income customers, “community-driven” community solar projects, and areas targeted for equity investments in Illinois’ existing energy laws.
“VPPs have a huge potential in a state like Illinois, where there are already many capable devices — like smart thermostats and solar systems which can pair with storage — increasing in number at a rate we can accelerate,” said Medakkar.
An analysis conducted by clean-energy think tank RMI found that VPPs could meet most of the expected new demand in Illinois, providing a crucial bridge while more clean-power generation and transmission lines are built.
The report notes that the state will need around 3.9 gigawatts of new generation or energy savings by 2029, as demand grows and old fossil-fueled plants retire.
VPPs could satisfy about three-quarters of that need, the analysis says, if they account for 10% of electricity used during peak demand times by tapping batteries and dialing down customers’ energy consumption.
Plus, it takes much less time to set up a VPP than to build a new traditional power plant. “VPPs can be deployed in as little as six months, nearly three years quicker than the median deployment timelines for utility-scale batteries and natural gas plants,” notes the RMI report, which was produced for Advanced Energy United to inform the legislative process.
The analysis determined that VPPs would save the average Illinois customer $34 a year by reducing the amount of expensive capacity that utilities would have to purchase in the auctions run by regional grid operators. ComEd’s customers especially are seeing their bills skyrocket due to record-high capacity costs in the PJM regional market.
“There’s great untapped potential in demand-response and VPP-type products,” said Sarah Moskowitz, executive director of the Citizens Utility Board, which advocates for Illinois’ electric and gas customers. “It’s disappointing we haven’t seen more opportunities of this sort take root here. But maybe now, with the spiraling energy prices, policymakers will finally see that these are programs that can bring real benefit not just to those who directly participate but to everybody.”
There’s nothing like a shared frustration to bring people together. For a group of Mid-Atlantic and Midwestern states, that’s rising power prices on the grid operated by PJM Interconnection. Both Republican and Democratic governors are calling out PJM’s management and demanding change — a repeat of a cycle that’s been going on for years and has no easy solution.
The U.S. is home to seven regional transmission organizations and independent system operators that are each responsible for managing power transmission and operating energy markets among utilities in their area. PJM is the largest, serving more than 65 million customers across D.C., Ohio, Pennsylvania, Virginia, and 10 other states. And for years, leaders in those states have said it’s not doing a great job.
The crux of the issue is rising electricity prices. This summer, PJM announced a new record in its annual capacity auction, which it uses to secure power resources for the grid. Prices hit $16.1 billion, up from $2.2 billion in 2023, Canary Media’s Jeff St. John reported in July.
There are a few reasons for the spike in costs. For one, PJM expects that it will need a ton more power-generation capacity in the coming years as data centers come online — though experts dispute just how big the AI energy-demand bubble will actually be. PJM does have a massive backlog of clean-power and battery projects looking to connect to the grid and meet that demand. But the operator hasn’t undertaken reforms that critics say could speed interconnections, and is instead campaigning to keep expensive, dirty fossil-fuel power plants online.
PJM member states’ longstanding dispute with the grid operator reemerged this week as 11 of their governors met in Philadelphia. There, Pennsylvania’s Democratic Gov. Josh Shapiro and Virginia’s Republican Gov. Glenn Youngkin both said they would leave PJM if states don’t get a bigger role in the grid operator’s governance.
“This is a crisis of not having enough power, and it is a crisis in confidence,” Youngkin said. “It’s this crisis that demands real reform, real reform immediately — and at the top of the list is that states must have a real say.”
PJM President and CEO Manu Asthana acknowledged that his organization needs to take cost-cutting steps like improving its load forecasting and interconnection processes, but he also put the onus on states to better their own infrastructure siting and permitting rules.
Washington Analysis researcher Rob Rains is doubtful that states will follow through and depart PJM. He said doing so could actually cost customers more in the short term, as the states may have to negotiate their own power procurement at rates even higher than what PJM has secured. Rains predicts that instead of cutting ties with the grid operator, governors will pull other levers to pressure PJM to establish stronger power-market safeguards to keep prices low. Meanwhile, analysts at ClearView Energy Partners suggest states should keep up their push to get more electricity generation developed as soon as possible.
Trump stands alone at the U.N. climate summit
The U.S. set itself apart from the rest of the world at the United Nations’ climate summit this week, and not in a good way. On Wednesday, around 120 countries announced new emissions-reduction plans and climate commitments. That included China, the world’s top carbon polluter, which declared it would aim to cut emissions at least 7% from its peak by 2035. New pledges also came from other major emitters, including the European Union, and from countries with smaller populations and lower gross domestic product.
But the U.S. wasn’t among them. Instead, in a speech on Tuesday, President Donald Trump railed against all things green, clean, and climate-friendly. Climate change is “the greatest con job ever perpetrated on the world,” Trump said — a scientifically unsound statement, to say the least.
The summit came just days after U.N. Secretary-General António Guterres said the Paris climate agreement is at risk of “collapsing” and that countries needed to ramp up their emissions goals to get things back on track.
Utilities are failing on climate, Sierra Club says
For the past four years, the Sierra Club has annually graded the U.S.’s biggest utilities on their clean-energy progress. The marks haven’t been stellar, but utilities were at least taking steps in the right direction. That is, until this year, when the Sierra Club granted utilities a collective “F,” Canary Media’s Jeff St. John reports.
The “Dirty Truth” report examined 75 of the nation’s biggest utilities to see whether they intend to close their coal plants by 2030, whether they plan to build new gas plants, and how much clean energy they expect to build by 2035. In a spot of good news, 65% of utilities have increased their clean-energy deployment plans since 2021. But they’ve slid backward on fossil fuels, increasing their intended gas-plant additions and walking back plans to shut down coal plants.
You say you want a Revolution? A federal judge lets the Revolution Wind offshore project continue construction in a ruling that signals the Trump administration may have trouble defending its attacks on other already-approved wind farms in court. (Canary Media)
Endangerment fight continues: Every Democratic U.S. senator signs on to a letter opposing the Trump administration’s attempt to rescind the endangerment finding, which establishes that greenhouse gases harm human health, while Republican senators urge the administration to repeal it. (The Hill, Kentucky Lantern)
A clear path forward: Glassmaking for windows, beverage bottles, and other products relies on high heat, typically supplied by fossil fuels, but some global manufacturers are exploring alternatives powered by electricity, hydrogen, and biofuels. (Canary Media)
Turbines keep on turnin’: Nearly a decade after the Block Island offshore wind farm began delivering power, residents of the Rhode Island vacation destination say the five turbines have brought them cleaner, quieter power. (New York Times)
“Motherfucking wind farms”: A viral ad promoting offshore wind development featuring Samuel L. Jackson shows how comedy can bring climate change information to everyday audiences — if it’s not silenced under the Trump administration. (Canary Media)
Heat pumps straight ahead: A coalition of states releases a road map for driving widespread adoption of electric heat pumps as they look to cut emissions from fossil-fuel heating systems. (Canary Media)
From the ground up: In 2014, the northeastern Iowa city of West Union became among the first in the country to install a municipal geothermal network; today, the community is saving money and serving as a model for other cities. (Inside Climate News)
The U.S. does not have a big enough power grid to accommodate rising energy demand — a fact that’s making electricity less affordable and reliable nationwide.
But there’s broad public support for growing the grid and allowing more electricity, including cheap, clean energy, to come online.
So says a new survey of likely voters in Ohio and Pennsylvania — two states in the severely backlogged PJM Interconnection grid region — and Arkansas, Mississippi, and Missouri, which are covered by the Midcontinent Independent System Operator (MISO). The survey was conducted by polling firm Cygnal on behalf of the Conservative Energy Network.
Roughly three-fourths of likely voters support expanding the electric grid, the survey found. About two-thirds are in favor of adding more transmission lines to connect clean energy and strengthen grid reliability.
And nearly 90% of respondents are concerned about rising energy costs. A majority of surveyed Republicans, Democrats, and Independents said they are “very concerned.”
“This is not a partisan issue. … You don’t have to appeal to one side or another,” said Chris Lane, a senior partner at Cygnal, who previewed the findings at the National Conservative Energy Summit in Cleveland on Aug. 25.
He noted that the results stand out for their consistency between regions and among different groups — including political parties. Even so, the Trump administration has in recent months worked against grid expansion, not toward it.
Energy costs are climbing in part because of rising power demand from data centers and the electrification of buildings and vehicles. Bringing more electricity generation online — especially quick-to-build, low-cost wind and solar — could increase competition and lower prices under the basic principles of supply and demand.
But just as transportation planners need to make sure highways can handle increased road traffic, the Federal Energy Regulatory Commission and regional transmission operators need to make sure the grid has room for more electrons. That calls for more “lanes” in the form of added transmission lines, plus technologies to squeeze more capacity out of the system overall.
Currently, “there aren’t enough power lines, they’re not all in the right places, and the ones we have are too outdated to meet the rising power demand for electricity,” Evelyn Robinson, director of PJM affairs for the renewable-energy industry group MAREC Action, said during a separate panel at the conference in Cleveland.
While all of the United States faces delays in getting new energy onto the grid, the problem is worst in the PJM region, where hundreds of projects have been stalled in the queue for years. To deal with the backlog, the grid operator switched to a new interconnection process in 2023; as of June, PJM still had about 63 gigawatts of power, mostly clean energy, stuck in that “transition queue.”
Across the country, wind, solar, and battery storage make up most of the resources waiting to come online, and their “levelized cost of energy” is cheaper or on par with other electricity sources.
The Trump administration has called for “the rapid and efficient buildout” of energy infrastructure, including transmission lines and grid-enhancing technologies, “by easing Federal regulatory burdens.”
But the administration’s actions have so far had the opposite effect. A February executive order calling for review of independent agency rulings threatens the Federal Energy Regulatory Commission’s ability to expand transmission. And in July, the Trump administration canceled a $4.9 billion loan guarantee for the Grain Belt Express — the largest transmission line underway in the United States. The project aims to shuttle gigawatts of wind and solar power from the Great Plains to the East, and Sen. Martin Heinrich, D-N.M., has called the cancellation of its federal loan guarantee illegal.
The administration’s policies, including the One Big Beautiful Bill Act, are also expected to more than halve the amount of clean energy built over the next decade, further exacerbating concerns about soaring power prices and rising demand.
The survey results may help the Conservative Energy Network convince decision makers to take steps to expand the grid.
“To the best of my knowledge, this is the first poll that’s been done in the PJM area testing these things, and in the MISO south area,” said John Szoka, the group’s CEO, at the National Conservative Energy Summit.
The polling also gauged the persuasiveness of four statements to support grid expansion. The takeaways could inform how advocates and legislators work to boost public support for clean energy.
Among conservatives in Ohio and Pennsylvania, a message focused on lower costs was about 12 times more likely to shift someone’s opinion than one about preventing blackouts, Lane noted. Messages about increasing American energy production, preventing blackouts, and providing positive job and economic impacts for Americans were more likely to move liberals than one about lowering costs.
Opinions were more divided on whether the federal government, states, or private companies should pay for grid expansion, although a slight majority of respondents in both the PJM and MISO areas said they would be willing to pay a few dollars more per month in the short term if it would reduce outages and lower costs over time.
Respondents were also mixed on who should get to choose how electricity is produced. States, landowners, and local officials all ranked above federal authorities.
Clean energy, meanwhile, received only modest support on its own. About one-fourth of the Ohio and Pennsylvania respondents said using clean energy was one of their top two policy goals, with nearly one-fifth of those surveyed in Arkansas, Mississippi, and Missouri giving that response.
Ultimately, affordability and reliability were the clear consensus energy policy priorities for poll respondents in both the PJM and MISO areas.
With the federal government standing in the way of both grid expansion and clean energy development, however, it will be tough for the voters to get the improvements they want.
Across California, hundreds of homes and businesses have signed up their solar panels, batteries, EVs, and appliances to be part of “virtual power plants” — networks of scattered energy resources that utilities can control to stave off blackouts and cut electricity prices.
Now, utilities are exploring another way to leverage VPPs: Strategically concentrating the systems in certain areas could let the companies defer expensive upgrades to nearby poles, wires, and other infrastructure. But first, utilities need to be 100% sure they can count on customer-owned assets without risking the grid’s reliability.
That’s the challenge that Northern California utility Pacific Gas & Electric is taking on with a pilot program it is running this summer and fall. PG&E has years of experience operating virtual power plants to reduce stress across the statewide grid. But the new Seasonal Aggregation of Versatile Energy (SAVE) program is testing how customers’ batteries and home energy controls can meet grid needs more precisely, down to the neighborhood level.
PG&E hasn’t said how many households it enlisted for the pilot, but in a March press release, the utility said it aimed to enroll up to 1,500 residential customers with solar-charged batteries from companies including Sunrun and up to 400 customers with smart electrical panels from startup Span.
The local “distribution” grids that serve those customers operate under a variety of conditions, including moments of peak demand that push some of the systems to their limits. Using home batteries and energy controls to delay upgrading those grids could make a big dent in the high and rising costs of electricity in California. In fact, a recent analysis indicates tapping the state’s nation-leading fleet of rooftop solar, backup batteries, and EVs for this task could save billions of dollars in grid upgrade costs.
PG&E isn’t delaying upgrades on the parts of the grid it’s testing just yet, said Trevor Udwin, the utility’s VPP and grid optimization manager. But the SAVE project will inform next steps to start doing this kind of proactive, VPP-integrated grid planning at a larger scale.
“At some point, we need to build trust,” Udwin said. “That means someone’s signing something” — a commitment to deliver the grid relief needed during specific times — ”and that a distribution planner is changing their operations based on that commitment.”
Distribution networks are distinct from the huge transmission lines that move the energy produced by power plants over long distances. Local distribution infrastructure instead carries power from substations — the big, fenced-in collections of equipment that lower the voltage of transmission-fed power — along main feeder lines, and eventually to the wires that connect to neighborhoods, homes, and businesses.
Until recently, utilities lacked technologies like smart meters and grid sensors to let them see what’s actually going on on those parts of their grids. That visibility is important, because these distribution networks have unique and fluctuating needs and characteristics — or load shapes, in industry parlance —that determine where and when they may be experiencing problems.
Without that transparency, the traditional utility fix has been to overbuild the system to reduce risks of overloads. But that’s getting expensive as demand for electricity rises. U.S. utilities invest more capital in their distribution grids than in any other part of their business, and those costs are increasing rapidly.
It could be much cheaper to instead get a cluster of customers to use less energy or send solar or battery power back to the grid during the handful of hours a particular distribution system is overloaded.
To test that capability, PG&E and its SAVE partners are using Sunrun’s batteries and Span’s smart electrical panels to modify how homes participating in the pilot consume and provide electricity to match the hour-by-hour constraints of the grid they’re connected to.
That’s an inherently time- and location-specific challenge, since different grid substations and circuits “may have very different load shapes, and they may peak differently at different hours,” Udwin said. And right now, very few utilities have deployed the data-collecting technology needed to reliably coordinate those interactions across their low-voltage distribution networks.
That technology, referred to as a distributed energy resource management system, or DERMS, does exist. California’s big utilities have run multiple DERMS pilot projects over the years, and PG&E has built a DERMS system that it’s using to manage a handful of EV charging hubs and utility-scale batteries participating in “load flexibility” pilots.
But PG&E hasn’t yet integrated that DERMS platform with the communications and controls technology it’s deploying with its SAVE partners, Udwin said. Instead, for this summer’s tests, PG&E is “building communications with the aggregators,” he said, interfacing with software from Lunar Energy and Tesla to control the batteries, and with Span’s software that keeps whole-home energy use below certain thresholds.
All of that software will be tasked with making sure homes with batteries, panels, and other equipment work together to add power or reduce draws at moments when that section of the grid is expected to experience excessive loads. But it also has to make sure it doesn’t leave customers unable to use their batteries and appliances when they need to, Udwin noted.
PG&E and its SAVE partners want to make sure they’re “serving their customers best, and that the load-shaping won’t negatively impact them,” Udwin said. To make that easier, PG&E is delivering its partners week-ahead and day-ahead load shape requests, he said. That gives Sunrun and Span an opportunity to prepare their customers for lengthy demands on their resources.
“They’re taking a really big risk with us,” he said. “I’m thrilled our partners are taking this leap.”
California was one of the first states to push utilities to integrate customer-owned solar, batteries, and flexible EV chargers and appliances into grid planning. Colorado, Hawaii, Illinois, Massachusetts, Minnesota, New York, and others have enacted similar policies over the past decade. The idea is to capture the grid value of distributed energy resources — solar, batteries, EVs, and smart thermostats, water heaters, and appliances that can shift when they use electricity — that homes and businesses are already buying.
Lots of utilities are already using these technologies to reduce system-wide electricity peaks. In fact, demand-response programs have existed for decades. But beyond a handful of projects, utilities have yet to leverage VPPs as a way to defer investments in their distribution grids.
Utilities don’t have much time to act on this opportunity for savings, said Aram Shumavon, CEO of grid analytics company Kevala. Even with these kinds of targeted VPPs in place, overloaded grid circuits will need to be upgraded sooner or later, he said. And once they are, VPPs can no longer defer those costs, evaporating the potential savings.
Missing out on those savings could hurt. A 2023 study by Kevala found that upgrading California’s distribution grids without deploying tech and programs to prevent EV charging from overloading local circuits could cost the state’s three big investor-owned utilities around $50 billion by 2035. Managing EVs to avoid those overloads, by contrast, could cut that price tag roughly in half, according to more recent studies.
Those savings should more than cover whatever utilities need to pay EV owners to commit to those managed charging constraints, Shumavon said. Eventually, the rising electricity demand from all those new EV-owning customers will increase utility revenues enough to cover those new grid costs, lowering rates for customers at large, he added.
To be clear, the lack of uniformity across different parts of the grid makes it hard to pinpoint the precise value of the VPPs the SAVE program is testing. Assessing that value is exceedingly complicated, given the enormous number of variables involved.
VPP advocates argue that utilities and regulators should avoid getting bogged down in those calculations and err in favor of encouraging customers to lend their spare power to help the grid. A new report from Kevala and think tank GridLab found that California could cut energy costs for consumers by up to $13.7 billion by 2030 by fully utilizing distributed resources like EVs and solar panels to defer grid upgrades.
However, utilities need to be able to prove out that a VPP’s benefits outweigh the expense of paying customers for access to their energy resources, Udwin said. “We want to find ways to shape for everything we can shape for — and do so cost-effectively. That’s the rub.”
PG&E is targeting low-income and disadvantaged communities for at least 60% of its SAVE test cases, Udwin said. There’s a sound rationale for that: Data shows that utilities have underinvested in the distribution infrastructure that serves these communities, which has restricted their ability to access rooftop solar and EV charging.
At the same time, PG&E is focusing on parts of the grid where its SAVE partners already have a concentration of customers. California has more rooftop solar, behind-the-meter batteries, and EVs than any other state, which provides a fertile field of latent resources to tap into, said Yang Yu, Sunrun’s director of business development for distributed power plants (another term for VPPs).
“Deploying assets in a small territory can make it difficult [for VPP programs] to reach scale, even with strong customer incentives like a free battery,” he said. But Sunrun has “a ton of assets already deployed,” he said. “That means that, within a specific region — say a substation or even specific feeders — we may have enough penetration at some point to do a local-level peak-load management.”
That’s not just more cost-effective than upgrading utility grids — it’s also faster. “We can stand up a [distributed power plant] in six months,” he said, which is what Sunrun has done for PG&E’s SAVE program.
Michael Gillogly, manager of the Pepperwood Preserve, understands the wildfire risk that power lines pose firsthand. The 3,200-acre nature reserve in Sonoma County, California, burned in 2017 when a privately owned electrical system sparked a fire. It burned again in 2019 during a conflagration started by power lines operated by utility Pacific Gas & Electric.
So when PG&E approached Gillogly about installing a solar- and battery-powered microgrid to replace the single power line serving a guest house on the property, he was relieved. “We do a lot of wildfire research here,” he noted. Getting rid of “the line up to the Bechtel House is part of PG&E’s work on eliminating the risk of fire.”
PG&E covered the costs of building the microgrid, and so far, the solar and batteries have kept the light and heat on at the guest house, even when a dozen or so researchers spent several cloudy days there, Gillogly said.
Over the past few years, PG&E has increasingly opted for these “remote grids” as the costs of maintaining long power lines in wildfire-prone terrain skyrocket and the price of solar panels, batteries, and backup generators continues to decline. The utility has installed about a dozen systems in the Sierra Nevada high country, with the Pepperwood Preserve microgrid the first to be powered 100% by solar and batteries. The utility plans to complete more than 30 remote grids by the end of 2027.
Until recently, utilities have rarely promoted solar-and-battery alternatives to power lines, particularly if they don’t own the solar and batteries in question. After all, utilities earn guaranteed profits on the money they spend on their grids.
But PG&E’s remote-grid initiative, launched with regulator approval in 2023, allows it to earn a rate of return on these projects that’s similar to what it would earn on the grid upgrades required to provide those customers with reliable power. The catch is that the costs of installing and operating the solar panels and batteries and maintaining and fueling the generators must be lower than what the utility would have spent on power lines.
“It all depends on what the alternative is,” said Abigail Tinker, senior manager of grid innovation delivery at PG&E. For the communities the utility has targeted, power lines can be quite expensive, largely due to the cost of ensuring that they won’t cause wildfires.
PG&E was forced into bankruptcy in 2019 after its power lines sparked California’s deadliest-ever wildfire, and the company is under state mandate to prevent more such disasters. PG&E and California’s other major utilities are spending tens of billions of dollars on burying key power lines, clearing trees and underbrush, and protecting overhead lines with hardened coverings, hair-trigger shutoff switches, and other equipment.
But these wildfire-prevention investments are driving up utility expenditures and customer rates. Solar and batteries are an increasingly cost-effective alternative, Tinker said, with the benefits outweighing the price tag of having to harden as little as a mile of power lines.
PG&E saves money either by getting rid of grid connections altogether or by delaying the construction of new lines. Microgrids can also improve reliability for customers when utilities must intentionally de-energize the lines that serve them during windstorms and other times of high wildfire risk — an increasingly common contingency in fire-prone areas.
Angelo Campus, CEO of BoxPower, which built most of PG&E’s remote microgrids, sees the strategy penciling out for more and more utilities for these same reasons.
“We’re working with about a dozen utilities across the country on similar but distinct flavors of this,” he said. “Wildfire mitigation is a huge issue across the West,” and climate change is increasing the frequency and severity of the threat.
Utilities are responsible for about 10% of wildfires. But they’re bearing outsized financial risks from those they do cause. Portland, Oregon-based PacifiCorp is facing billions of dollars in costs and $30 billion in claims for wildfires sparked by its grid in 2020, and potentially more for another fire in 2022. Hawaiian Electric paid a $2 billion settlement to cover damages from the deadly 2023 Maui fires caused by its grid.
Microgrids can’t replace the majority of a utility’s system, of course. But they are being considered for increasingly large communities, Campus said.
Nevada utility NV Energy has proposed a solar and battery microgrid to replace a diesel generator system now providing backup power to customers in the mountain town of Mt. Charleston. Combining solar and batteries with “ruggedized” overhead lines should save about $21 million compared to burying power lines underground, while limiting impacts of wildfire-prevention power outages, according to the utility.
Some larger projects have already been built. San Diego Gas & Electric has been running a microgrid for the rural California town of Borrego Springs since 2013, offering about 3,000 residents backup solar, battery, and generator power to bolster the single line that connects them to the larger grid, which is susceptible to being shut off due to wildfire risk. Duke Energy built a microgrid in Hot Springs, North Carolina, a town of about 535 residents served by a single 10-mile power line prone to outages, on the grounds that it was cheaper than building a second line to improve reliability.
In each of these cases, utilities must weigh the costs of the alternatives, Tinker said. “It’s complicated and nuanced in terms of dollars per mile, because you have to be able to do the evaluation of individual circuits, and what can be done to mitigate the risk for each circuit,” she said.
Whether microgrids are connected to the larger grid or not, utilities need to maintain communications links with them to ensure the systems are operating reliably and safely. PG&E is working with New Sun Road, a company that provides remote monitoring and control technology, to keep its far-flung grids in working order.
It’s important to distinguish remote microgrids built and operated by utilities from other types of microgrids. Solar, batteries, backup generators, and on-site power controls are also being used by electric-truck-charging depots and industrial facilities that don’t want to wait for utilities to expand their grids to serve them. Microgrids are also providing college campuses, military bases, municipal buildings, and churches and community centers with backup power when the grid goes down and with self-supplied power to offset utility bills when the grid is up and running.
Utilities have been far less friendly to customer-owned microgrids in general, however, seeing them as a threat to their core business model. Since 2018, California law has required the state Public Utilities Commission to develop rules to allow customers to build their own microgrids. But progress has been painfully slow, and only a handful of grant-funded projects have been completed.
Microgrid developers and advocates complain that the commission has put too many restrictions on how customers who own microgrids can earn money for the energy they generate when the grid remains up and running. Utilities contend that they need to maintain control over the portions of their grid that connect to microgrids to avoid creating more hazards.
“It is a very difficult balance that PG&E is constantly trying to strike, with the oversight of [utility regulators] and other stakeholders, between safety and reliability and affordability,” Tinker said. “That’s something we’re trying to thread the needle on.”
But as the costs of expanding and maintaining utility grids continue to climb, and solar and batteries become more affordable, utilities and their customers are likely to see more opportunities to make microgrids work, Campus said.
“The cost of building poles and wires and maintaining distribution infrastructure has grown substantially over the past 20 years,” he said. “Look at the cost of distributed generation and battery — it’s an inverse cost curve.”
A correction was made on Sept. 11, 2025: This story originally misstated PG&E’s timeline for installing more than 30 remote grids. The utility expects to install that number of systems by the end of 2027, not 2026.
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