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The cost of keeping California’s power grid up and running is skyrocketing, and in turn, so are households’ energy bills. Virtual power plants, which harness the combined power of lots of rooftop solar systems, home batteries, EVs, and smart-home appliances, can help — especially if utilities use them to relieve pressure at counterintuitive “sweet spots” on the grid.
So finds a new report that examines how the state’s utilities can spend less on new infrastructure by occasionally paying homes and businesses to reduce power use or to inject energy into the system — a concept known as “load flexibility.” Think tank GridLab published the study in collaboration with Kevala, a grid-focused data analytics startup.
One of the main reasons utilities’ expenses are rising is that the companies are putting more money toward their distribution grids — the poles, wires, and transformers that deliver power from electrical substations to homes.
Spending on distribution grids has grown rapidly in the past decade, and made up 44% of total utility spending in 2023, according to data from Lawrence Berkeley National Laboratory. Most of that cash is going toward replacing aging equipment and keeping up with booming demand for electricity.
The distribution grid is an even greater expense in California, according to Ric O’Connell, founding executive director of GridLab. Utilities there must invest heavily in wildfire-prevention measures, and the state’s ambitious decarbonization goals mean the power system needs to support the rapid electrification of homes and vehicles.
If California can defer upgrades to its distribution system, it can produce savings for customers, O’Connell said.
“That’s where the money is,” he said. All things being equal, “deferring the greatest number of highest-cost grid upgrades will save the most money.”
And according to GridLab’s new study, the best way to defer the most upgrades is to find those grid sweet spots — specifically, the areas with circuits, transformers, and substations that are least strained — and rapidly scale up virtual power plant programs to serve them.
Kevala, the startup that partnered with GridLab on the study, has a decent idea of where those sweet spots might be, based on its past analyses of distribution grids in California and nationwide.
The new study looks at the ideal way to deploy the 3.5 gigawatts of “load shift” capacity that California hopes to add to its grid by 2030.
For the research, Kevala compiled data on every feeder line, substation transformer, and substation of California’s three biggest utilities from today through 2030. It then ran three scenarios for using that 3.5 GW of load flexibility to relieve strain on that infrastructure: spreading the VPP effort equally across the grid, targeting the most overloaded parts of the grid first, and prioritizing the least overloaded parts.
That last technique was by far the most cost-effective, the analysis showed. Putting it into practice could reduce grid costs passed on to utility customers by a total of $13.7 billion through 2030 — about $10 billion more than the alternative approaches.
The reason? Taking on the least overloaded circuits first allows the same amount of load flexibility to defer new investments across a wider swath of the low-voltage grid, O’Connell said. The strategy also happens to target more urban areas, where much of the grid is buried underground, making it more expensive and difficult to upgrade.
That result came as something of a surprise.
“At first, we thought you’re going to start with the most heavily overloaded circuits and allocate flexibility to those, and then work your way down,” O’Connell said. “But we found you basically exhaust your flexibility on a handful of circuits — and you’re basically not saving a lot of money.” For those instances, “maybe it makes sense to spend real money on poles and wires.”
VPPs may also struggle to meet the challenge of deferring investments in the most strained parts of the grid, he noted. The history of these efforts appears to bear that out.
For more than a decade, utilities and regulators have been working on so-called “non-wires alternatives” projects — using batteries, energy efficiency, and grid-responsive devices to defer the need for big grid upgrades. Since 2014, California state policy has required regulators and utilities to work toward building these “distributed energy resources” — DERs for short — into their multibillion-dollar annual spending plans.
But beyond some showcase projects like New York utility Con Edison’s Brooklyn-Queens Demand Management initiative, relatively few proposals have moved past the planning phase. In California, despite programs launched over the past decade, “nothing’s really happened,” O’Connell said. Critics say the lack of progress is largely because utilities have proposed grid projects that DERs couldn’t possibly solve within the timeframes and cost restrictions provided.
On the other hand, “there are many circuits that are overloaded on a few hours of very hot days. I just need a little bit of DERs to solve that,” O’Connell said. “If we have a limited amount of valuable load flexibility, we should sprinkle a little bit of it across these lightly overloaded circuits.”
Targeting the least overloaded circuits could also minimize the risk of VPPs falling short of the job, he said. Slightly overloaded transformers and power lines can undergo overload conditions for short periods of time without blowing up or breaking down.
Larger-scale non-wires alternative projects like those that have been targeted in the past have a slimmer margin of error, he said. Utilities have traditionally demanded that any DERs being deployed to solve those grid constraints be made available for that purpose to the exclusion of any other use.
That’s a tough sell for customers of the companies putting VPPs together. Most consumers buy batteries for emergency backup power or to store surplus solar power — not to turn them over completely to utility control.
Customers willing to enroll their EV chargers, air conditioners, water heaters, and other appliances in flexibility programs would likely balk at the idea of being unable to use their devices when they really need to. Past VPP initiatives show that customers are far less likely to stick with them if they aren’t able to “opt out” of particular dispatches when circumstances demand it — say, when they need to charge their EV quickly after work to take their kid to soccer practice, or keep the house cool when elderly relatives are visiting.
With less-overloaded parts of the grid, by contrast, “maybe we can get the utilities a little bit more relaxed about it,” O’Connell said. “They’re always worried about, ‘What if the DERs don’t show up?’”
There’s a big catch when it comes to putting insights like these into action, however, said Kevala CEO Aram Shumavon. Utilities in California and elsewhere haven’t yet built VPPs and DERs into how they plan investments. That makes it much harder for the companies to consider them as options — which means they wind up choosing the traditional grid upgrade instead.
That’s the safer tried-and-true choice — and utilities, with their “extreme aversion to quantify risk, struggle with making innovative decisions,” he said. “But we’re spending a lot of time right now on what feels like baby steps, compared to how this market as a whole will need to function.”
It’s taken years for California utilities to start using the inherent flexibility of these technologies to help with grid operation and planning. But now, after some experimentation, they’re starting to prove that EV charging hubs, distributed solar installations, and utility-scale batteries can operate to fit within the hour-by-hour constraints on the grids they’re connected to. Similar efforts are now underway with customer-owned batteries and home energy control systems.
Still, VPP and DER programs are simply not expanding fast enough to meet California’s needs, Shumavon contends. “Once you move it into a program or procurement that requires a larger amount of situational awareness, we are woefully behind where we should be as an industry.”
Even getting the grid data needed for VPP providers to know where their solar-charged batteries or controllable household loads could do the most good has been a challenge. State legislators recently killed a bill provision that would have required California’s three major utilities to share data to inform how VPPs can reduce grid costs.
But Shumavon thinks that utilities in California are coming around to the need to move faster. The “non-wires alternatives” concept arose decades ago, when electricity demand was largely flat across most of the United States, and utilities had little incentive to support an alternative to investing more in their grids, which is how they earn guaranteed profits.
But that situation has radically changed in the past few years. The AI boom requires grids to handle gigawatts of new power, and utility rates are rising across the country. “The risk they’re facing is that they can’t do the rate increases, and they still have to deploy more capital, which has an upward pressure on rates,” Shumavon said. “That’s the point at which politicians get angry.”
O’Connell agreed that “utilities are much more interested in doing this now. They’re seeing rate pressure being a much bigger deal for them now. Anything they can do, it means that billions less in capital spend will show up.”
But the recent study by GridLab and Kevala “wasn’t going to get into how you design the program and how you pay them,” he said. “It’s more like, ‘You can do this — let’s figure it out.’”
To all the challenges the solar industry is facing today, add one more: cultivating a domestic market for lamb meat. It may seem an unlikely mission for clean-energy developers, but in many states, including Illinois, grazing sheep between rows of photovoltaic panels is considered the most efficient form of agrivoltaics — the combination of solar and farming on the same land.
Solar advocates, researchers, and developers have given much attention to agrivoltaics. The practice includes growing crops like blueberries, tomatoes, or peppers in the shade of solar panels and letting cows or sheep graze around the arrays.
Perhaps the biggest benefit of agrivoltaics is that land is not being taken out of agricultural production in favor of clean energy, a concern that has stoked intense opposition to solar. The Trump administration codified this sentiment when the head of the U.S. Department of Agriculture announced on Aug. 19 that the agency “will no longer fund taxpayer dollars for solar panels on productive farmland.”
Illinois’ sprawling fields of corn and soybeans don’t coexist well with solar panels, but sheep do, making grazing a promising type of agrivoltaics for the state, proponents say.
In a typical solar grazing arrangement, sheep farmers (called grazers) are paid by solar developers to bring the animals to sites hosting large arrays — often farms — where they munch away on the vegetation. Meanwhile, the landowner benefits from lease payments. Grazing is a lower-emissions alternative to mechanical mowing, and sheep can reach corners that mowers can’t.
But to make a living herding sheep, the grazers need to be able to sell the lambs they raise as meat. In the U.S., lamb is sold primarily in halal markets and appears on menus only during Easter holidays. Three-quarters of that meat is imported from Australia and New Zealand.
“What there needs to be, honestly, is more demand for lamb in the country,” said Stacie Peterson, executive director of the American Solar Grazing Association, which offers solar grazing certifications and contract templates. “We’re hoping to help develop more breeding stock, more farmers, more grazers doing this.”
Brooke Watson would like to see demand for lamb soar in the Midwest, in tandem with demand for solar grazing. Brooke’s husband, Chauncey Watson IV, has been raising sheep since he was in 4-H, a program that teaches kids about agriculture. Chauncey’s family has farmed in Illinois since 1856. The couple has raised lambs and sheep for wool, but in 2023 they bought a new flock of “hair sheep,” which don’t need shearing, to give solar grazing a try. “Hooves on the ground” happened last summer, Brooke said. Now they have 500 ewes grazing on over 320 acres at nine community solar sites in six Illinois counties.
Brooke laments that Americans “lost their taste for lamb” after World War II — because veterans had grown tired of wartime canned lamb rations, according to some accounts. (Other historical factors also likely influenced the decline in mutton’s popularity.)
“It has picked up in the last few decades, but more so with immigrant communities, where lamb is that really valuable cultural and religious product,” she said, adding that “traditional beef and chicken consumers” should give lamb a chance. “There’s really a huge, huge potential for both of these industries to grow and evolve together side by side.”
Brooke said solar grazing can also provide a way for younger farmers to stay in the business.
“The landowner most typically is hitting retirement age, and they don’t want to work the land anymore. So solar is a way for them to still maintain ownership of that parcel, and they’re compensated to host the solar on the site” while collaborating with farmers like her and her husband, who are typically “younger, maybe first generation or newer farmers, and they’re excited about the sheep grazing.”
According to a census by the American Solar Grazing Association and the National Renewable Energy Laboratory, sheep solar grazing is concentrated in the West and the South. In 2024, almost 62,000 sheep were grazing over 87,000 acres at 109 solar sites in the South, with more than half of the animals in Texas. In the Midwest, including Illinois, just over 13,000 sheep grazed almost 7,000 acres of solar at 148 sites.
Texas and California have long histories of shepherding, and in many areas sheep are central to the ranching culture. That means grazing sheep under solar panels is continuing these areas’ traditional agriculture.
But in Illinois, there is little history of raising sheep. So converting acres of the state’s primary corn and soybean fields may still raise eyebrows.
“In Europe, solar grazing has taken off, but they are much more into sheep,” said Ken Anderson, director of the Advanced Energy Institute at Southern Illinois University. “When you see sheep move into Illinois, it’s unfamiliar to people; they’re not used to seeing sheep. It’s better with cattle, but cattle are harder — they like to scratch. It can do damage to the panels.”
Solar grazing goats, meanwhile, has been “a disaster,” Anderson said, because they chew wires and other parts of solar arrays. He is working on a proposed agrivoltaics research site that would grow peaches, apples, and other specialty crops amid solar panels on a former military munitions site in Illinois. Anderson prefers growing crops under panels to grazing, but crops need more specialized solar configurations.
Solar panels suited for sheep are “strictly industrial arrays,” he said. “All you’re going to be able to do is graze sheep there in the future, so you need to think about the long haul.”
Sheep may be the state’s best option for large arrays because, Anderson thinks, there’s limited potential for solar panels to occupy the same land as the state’s traditional sprawling corn and soybean fields.
“In my opinion, the economics will never work,” for pairing corn and soy with solar, Anderson said. “When you grow broad-acreage crops like corn and soy, you use very large equipment, so you have to put the panels far apart,” resulting in less energy output.
While solar grazing in Illinois might often replace corn or soybean production, Watson sees it as a positive trade-off.
“So much of that corn is used for ethanol production, and so much of that soy is, quite frankly, exported to other countries,” she said. “So we really look at solar grazing as an opportunity to have more U.S.-sourced energy production and food production as well.”
The Watsons work with a solar developer called Pivot Energy. Since 2021, agrivoltaics has been the company’s main focus, according to director of operations and maintenance Angie Burke. In Illinois, Pivot Energy has 365 sheep grazing at 11 sites, and those numbers are projected to more than double by next year.
“Agrivoltaics is this great way to support those family farmers locally and provide that cost-competitive, locally sourced, and high-protein-value food for those communities that are excited to eat more lamb,” Burke said.
While solar grazing may not be more profitable than mechanical mowing for landowners, it leaves the soil in better condition than if it were left idle under the panels.
“Let’s be delicate — [the sheep] are contributing to the soil” with their excrement, said Anderson.
In climates like Illinois’, sheep must be housed and fed inside during winter — a considerable expense. But Brooke Watson noted that, unlike solar grazers in Western states, she and her husband don’t need to provide much water for sheep in summer, as the lush vegetation and frequent rain suffice. In any state, solar grazing means ensuring that there are safe fences or wires around sites and that predators are kept out.
“In the early days, there were some horror stories where people dropped sheep off and came back at the end of the summer and there weren’t any sheep anymore,” said Ethan Winter, national smart solar director of American Farmland Trust, an organization committed to farmland preservation and sustainable farming practices. “You’re starting to see more professionalization, more formalized best practices for grazers.”
The organization United Agrivoltaics connects would-be grazers with solar developers and provides resources for insurance and contracts, Winter added.
American Farmland Trust’s Midwest solar specialist Alan Bailey noted that existing crop residue or debris must be cleared and specific cover crops planted to prepare for solar grazing, but this can happen while an array is being built. “One of our principles is having some sort of living cover on those sites throughout the entire construction process,” he said.
Because solar grazing’s benefits to the land and environment are well established, Winter said, boosting the lamb market is “the next big step” for expansion.
“There’s both the need and opportunity to think about markets for the lamb,” Winter said, noting that the animals could be sold to wholesale processors or marketed locally. “There may be a real advantage in having the Illinois Solar Lamb label.”
This article was originally published by Yale Climate Connections.
Drawing down carbon from the air and stashing it in underground rock formations has been framed as an essential way to slow and reverse global warming. But new research published in the journal Nature finds there are far fewer suitable places to do this than previously thought.
After screening out “risky” areas, like those that are vulnerable to earthquakes, a team of researchers from Europe and the U.S. found that the Earth can only safely store about 1,460 gigatons of injected carbon in its sedimentary basins. This is an order of magnitude less than previous estimates, and — if you convert stored carbon to an estimated impact on the climate — only enough to cut global warming by about 0.7 degrees Celsius (1.3 degrees Fahrenheit), not the 6 degrees C (10.8 degrees F) described in other research.
Carbon storage “can no longer be considered an unlimited solution to bring our climate back to a safe level,” one of the study’s co-authors, Joeri Rogelj, said in a statement. “Geological storage space needs to be thought of as a scarce resource that should be managed responsibly to allow a safe climate future for humanity.” Rogelj is director of research at the Grantham Institute on climate change and the environment at Imperial College London.
Carbon storage, for the sake of the paper, refers to the injection of carbon dioxide into underground reservoirs where it theoretically can’t contribute to climate change. There are two broad ways to get this carbon: first, by capturing it at the point of emission — say, the smokestack of a fossil fuel-powered cement factory — and second, by sucking it out of the ambient atmosphere.
According to the United Nations’ Intergovernmental Panel on Climate Change, or IPCC, the world’s foremost authority on the topic, at least some carbon storage will be necessary to achieve international climate targets.
But the amount needed is dependent on a number of factors, including how much countries plan to slash emissions versus “offsetting” them, especially from hard-to-decarbonize sectors, and whether they intend to blow past 1.5 or 2 degrees C (2.7 or 3.5 degrees F) of global warming and then return to a more liveable temperature by removing carbon from the atmosphere. The latter is a contentious idea known as “overshoot,” and it would necessitate more carbon pulled out of the air and stored. Some IPCC scenarios involving substantial overshoot assume up to 2,000 gigatons of carbon storage by the year 2100.
According to the study’s authors, no previous global or regional estimate of the Earth’s technical carbon storage potential has taken into account key risk factors that would make some areas undesirable for storage. Starting from an estimate of all potentially available storage sites, their analysis cuts out areas that are too shallow, too deep, and too prone to earthquakes, as well as environmentally protected areas and areas near where people live. This reduces the total available capacity for carbon storage from 11,780 gigatons to just 1,460 gigatons of CO2, 70 percent of it on land and 30 percent on the seafloor.
The authors used an existing conversion rate from the IPCC to translate that gigaton number to about 0.4 to 0.7 degrees C (0.7 to 1.3 degrees F) of reduced global warming.
They also noted some geographical disparities in the potential for carbon storage: While some historical climate polluters such as the U.S. and Canada have lots of space to safely stash carbon, others in Europe don’t. If those countries intend to make carbon storage a significant piece of their climate mitigation plans, they will likely have to look for locations in countries that have done little to contribute to climate change, potentially in Africa.
Sally Benson, an energy science and engineering professor at Stanford University who was not involved in the new research, said its findings should not be seen as “alarming” or “dramatic.” As described in the paper, IPCC scenarios that give the world a 50 percent chance of limiting global warming to 1.5 degrees Celsius by the end of the century would require sequestering about 9 gigatons of carbon per year (assuming that net-zero emissions are achieved around 2050). That means it could be more than 160 years before the world reaches the safe carbon storage limit calculated in the study.
“What that tells me is that this is kind of good news,” Benson said. “Somebody has taken the most conservative of possible approaches to looking at this capacity and concluded, from my perspective, that there’s a lot of capacity relative to what we need.”
The study authors note that the need for storage could continue after their theoretical limit is reached, especially if countries keep needing to offset residual emissions from agriculture or the burning of fossil fuels in some sectors. Climate tipping points could also release more carbon dioxide into the atmosphere than anticipated, necessitating more carbon removal than expected.
But Benson said these risks are too far in the future and that “we need to use all of the technologies available as quickly as possible.”
Both Benson and another independent expert — Jennifer Wilcox, a professor of chemical engineering and energy policy at the University of Pennsylvania’s Kleinman Center for Energy Policy — said the paper’s central estimate for safe and prudent carbon storage is likely too conservative. Wilcox told Grist it “undercounts what carefully pressure-managed projects can safely deliver.”
But Naomi Oreskes, a professor in the history of science at Harvard University, held the opposite opinion. Oreskes said the paper fails to consider governmental, economic, and scientific challenges to actually deploying carbon storage at scale. “When you take those factors into account,” she said, “the potential for carbon storage, particularly in the crucial next decade, is even less.”
Despite significant hype around the technology, only about 0.05 gigatons of CO2 are currently stored via point-of-emission carbon capture each year. So far, most of these carbon capture projects inject carbon into the ground to aid the extraction of even more oil and gas, in a process known as “enhanced oil recovery.” And only 0.00001 gigatons of CO2 are removed from the ambient air each year. That’s less than the stated annual greenhouse gas emissions of Bowdoin College, a small liberal arts school in Maine.
“This new information is consistent with a broader pattern we have observed, of overstating the promise of ‘solutions’ that sidestep the central issue of reducing fossil fuel use,” Oreskes said.
A novel solar power project just went online in California’s Central Valley, with panels that span across canals in the vast agricultural region.
The 1.6-megawatt installation, called Project Nexus, was fully completed late last month. The $20 million state-funded pilot has turned stretches of the Turlock Irrigation District’s canals into hubs of clean electricity generation in a remote area where cotton, tomatoes, almonds, and hundreds of other crops are grown.
Project Nexus is only the second canal-based solar array to operate in the United States — and one of just a handful in the world. America’s first solar-canal project started producing power in October 2024 for the Pima and Maricopa tribes, known together as the Gila River Indian Community, on their reservation near Phoenix, Arizona. Two more canal-top arrays are already in the works there.
In California, the solar-canal system was built in two phases, with a 20-foot-wide stretch completed in March and a roughly 110-foot-wide portion finished at the end of August. Researchers will study the project’s performance over time, while a new initiative led by California universities and the company Solar Aquagrid will push to fast-track the deployment of solar canals across the state.
Proponents of this emerging approach say it can provide overlapping benefits.
Early research suggests that, along with producing power in land-constrained areas, putting solar arrays above water can help keep panels cool, in turn improving their efficiency and electricity output. Shade from the panels can also prevent water loss through evaporation in drought-prone regions and can limit algae growth in waterways.
Plus, solar canals could offer a faster path to clean energy development than utility-scale solar farms, especially in rural parts of the U.S. where big renewables projects increasingly face community opposition. Placing solar panels atop existing infrastructure doesn’t require altering the landscape, and the relatively small installations can be plugged into nearby distribution lines, avoiding the cumbersome process of connecting to the higher-voltage wires required for bigger undertakings.
“Why disturb land that has sacred value when we could just put the solar panels over a canal and generate more efficient power?” said David DeJong, director of the Pima-Maricopa Irrigation Project, which is developing a water-delivery system for the Gila River Indian Community.
The purpose of these early arrays is primarily to power on-site canal equipment like pumps and gates. But such projects could eventually help clean up the larger grid, too. A coalition of U.S. environmental groups previously estimated that putting panels over 8,000 miles of federally owned canals and aqueducts could generate over 25 gigawatts of renewable energy — enough to power nearly 20 million homes — and reduce water evaporation by possibly tens of billions of gallons.
Still, the technology isn’t an obvious choice for many canal operators.
Elevating solar panels over canals is more expensive and technically complex than installing conventional ground-mounted solar arrays on trackers, and it can involve using more concrete and steel. Wider canals may also require support structures for panels within the waterway, which can disrupt the flow of water.
Earlier this year, a senior engineer at Arizona’s Salt River Project recommended that the power and water utility not pursue a solar-canal pilot “based on cost estimates and project concerns,” after comparing the unique design to both rooftop and utility-scale solar alternatives.
Solar-canal developers are hoping they can still gain a toehold in irrigation districts that are grappling with high electricity costs and have limited options for generating cheap power, said Ben Lepley, the founder of engineering firm Tectonicus, which designed the Gila River Indian Community’s 1.3-MW system south of Phoenix.
The initial costs are “definitely higher … but it can actually be really fast as a project,” Lepley said. “By the next year, you can have really cheap electricity, and that gives [irrigation districts] stability over the 30-year life of the project.”
For its part, the Gila River Indian Community is building solar-canal projects as part of its broader mission to “generate enough renewable energy to completely offset the electrical use by the irrigation district,” said DeJong. He noted the district pays about $3 million a year for the 27 million kilowatt-hours of electricity it needs to pump, move, and store water.
The community built its first solar-canal project over the Casa Blanca Canal with a nearly $5.7 million grant provided by the Inflation Reduction Act — part of a $25 million provision that supplied funding for the U.S. Bureau of Reclamation to design, study, and deploy projects that put panels over waterways. Irrigation districts in California, Oregon, and Utah received the remaining funds to develop their own installations.
The Trump administration is unlikely to support future programs, given its focus on gutting clean energy incentives, but a handful of projects are already moving forward without such grants.
DeJong said that construction is 90% complete on the tribal community’s second solar-canal project, a nearly 0.9-MW array built in partnership with the U.S. Army Corps of Engineers, which is slated to go online later this year. The community is self-funding a similar-sized project over the Santan Canal and is developing a floating solar array on one of its reservoirs, with both systems set to be up and running by early 2026. All told, the installations will provide 4 MW in local clean energy generation, he said.
“We have become really familiar with the economics of building these [canal] projects,” said Lepley, whose firm also worked on the Gila River Indian Community’s second and third solar-canal systems. “We have a pretty good playbook of how to continue these projects going forward, even without any grant funding from the federal government.”
Heat pumps can save households money. But the super-efficient, electric HVAC appliances are almost always more expensive to install up-front than gas- or oil-fired options.
Jetson, a Vancouver-based heat-pump startup, thinks it can change that — with a combination of new software, hardware, and a direct-to-consumer approach.
“We are typically anywhere from 30% to 50% below competitive quotes,” said cofounder and CEO Stephen Lake.
The company’s name, which may resonate with certain cartoon-watchers, harkens back to an era when people believed that “technology would enable this exciting, better future for us all,” Lake said.
His roughly 75-person startup, which Lake would only divulge has “raised a bit of money,” launched sales last October to try and deliver on that promise. So far, it’s installed heat pumps — which can both warm and cool spaces — in nearly 1,000 homes in Colorado, Massachusetts, and British Columbia, Canada, and it plans to expand into New York in a few weeks, he said.
Today, Jetson is announcing a move it says will further cut costs: It’s rolling out its very own heat pump, the Jetson Air. The startup has partnered with an undisclosed manufacturer to make the appliance.
Whole-home ducted heat pump projects in the areas where the startup currently operates typically have a price tag of $25,000 to $30,000, Lake said, citing data from bids that customers routinely share with Jetson. Those prices are also about the norm nationwide, according to electrification nonprofit Rewiring America — and are significantly higher than the cost of a new gas furnace ($8,000 to $10,000) plus air conditioner ($3,000 to $5,000), Lake said.
Jetson says its average heat-pump installation cost is way less than the national average: just $15,000.
Many markets also offer thousands of dollars in heat-pump rebates, which the startup deducts from what customers pay out of pocket. In these spots, Jetson can offer heat pumps in some cases for as little as $5,000, Lake said. At that point, it’s a financial no-brainer to choose the electric equipment over a gas furnace.
Bringing down the up-front costs of heat pump adoption is crucial, especially in the U.S., where the federal government is pulling back incentives for the HVAC tech. More than 80 million homes across the U.S. and Canada burn fossil fuels for heat, according to government data. These furnaces and boilers rack up around 3 to 6 metric tons of carbon emissions per household annually, Lake said, and heat pumps are the way to cut that pollution. Swapping a fossil-fueled heater out for a heat pump slashes CO2 about as much as trading in a gas car for an EV.
Jetson is taking a fresh approach to deliver its low heat-pump prices: vertical integration.
Traditionally, equipment manufacturers sell heat pumps to brands, which sell them to distributors, who sell them to HVAC installers, who sell them, finally, to homeowners, Lake explained.
“At each stage, there’s a markup,” said Brett Webster, a principal on RMI’s carbon-free buildings team. “There’s good reason to think that a vertically integrated company could reduce costs.”
Jetson cuts out the middlemen. It buys the heat pumps, stores them in its own warehouses, and has its own in-house installers ride out in the company’s electric vans to put the appliances in homes, Lake said.
Using custom software, Jetson also cuts costs by scoping heat pump projects virtually rather than sending someone out to each would-be customer. Last year, Jetson acquired whole-home decarbonization startup Helio Home and built upon its thermal modeling software that can accurately size heat pump systems remotely. In most cases, the first time an installer comes to an abode is to put in the heat pump. The company additionally uses proprietary software to process rebates.
Jetson’s tech-forward approach flows from Lake’s background. The Canadian entrepreneur previously built a smart-glasses startup called North that Google acquired for an undisclosed amount in 2020. With the climate crisis pressing and heat pumps an undersung solution, Lake and some of his colleagues from North pivoted to HVAC, he said.
Others are also developing software to improve the heat-pump customer experience. Manufacturing startup Quilt uses over-the-air updates to improve its minisplit heat pumps over time. And home-electrification startups, such as Zero Homes, have created software to reduce the cost of heat pump projects.
In the view of RMI’s Webster, Jetson’s vertically integrated approach is “taking the next step.”
Jetson installed a heat pump for Matt Machado, who works as an expert on surface water and groundwater rights at Colorado law firm Lyons Gaddis, for a cost of about $7,000 — a third of what the eight or nine other contractors he got bids from offered. He’ll get another $2,000 off when he claims the federal Energy-Efficient Home Improvement Credit (25C) at tax time. Jetson “made it easy,” Machado told Canary Media. On pricing, “they’re very transparent.”
Jetson’s low cost was thanks in part to the company’s up-front application of state and local rebates, which tallied roughly $6,000, Machado said. Other contractors didn’t make these reductions, which would’ve left him to absorb the cost and file for the rebates on his own.
With the launch of its heat pump, Jetson aims to provide a product that delivers the customer experience of a Tesla or Rivian electric vehicle, Lake said.
The Jetson Air heat pump is “comparable to the best models,” rated to work down to minus 22 degrees Fahrenheit, he added. Brands such as Bosch, Carrier, Lennox, and Mitsubishi already make popular options for cold-climate markets.
What sets Jetson’s appliance apart, Lake said, are its built-in software, sensors, and controls. Homeowners can use these features to schedule their heat pumps to run at times of the day when the grid isn’t strained and power is cheaper. The tech also lets Jetson monitor a system’s performance and reach out if something needs to be fixed.
“What are the amperages being drawn? Is your air filter getting dirty? Are there any error codes coming up? Is anything not running 100%? We can tell all that remotely,” he said. No other heat pump on the market today is capable of that, he noted.
Ultimately, Lake said that these improvements in functionality compound into more savings for the customer.
HVAC “is this very unsexy category, which I love,” Lake said. “So many things we’re doing — applying software to make [products] more efficient and designing better systems — [are] improvements that in other industries have happened a long time ago.” But they’re “completely novel in this HVAC world.”
Talia Boyd was spending over $300 a month to keep her home just outside Asheville, North Carolina, cool this summer. It was an enormous sum for the single-wide trailer she shares with her baby daughter and teenage son.
“We constantly kept ceiling fans going, and I had to get AC units,” she said — multiple ones that ran 24/7 to replace the cold air seeping out from gaps around the windows.
But now, the air leaks have been sealed, a door has been replaced, and a new heat pump has been installed — all at no cost to Boyd. Her monthly utility bill from Duke Energy has been cut in half, she said.
The improvements are thanks to Energy Savers Network, a small nonprofit that serves Buncombe County, where Boyd lives, along with neighboring counties Henderson, Haywood, and Madison.
“They really came out and they helped,” said Boyd, who works in home health care. “They talked. They took measurements. They walked through the whole trailer. I really appreciate the help, and I would love to spread the word.”
Boyd’s home is among the roughly 1,400 that Energy Savers Network has assisted with weatherization since its inception in late 2016. Across the state in the same time frame, thousands of other households have received similar services, mostly from community action agencies deploying federal dollars.
But Boyd’s story is somewhat unique. She’s in a smaller subset of people who’ve benefited from a Duke initiative meant not just to aid the energy burdened in times of crisis, but to permanently reduce their electricity use through home efficiency improvements.
And with politicians at the state and national levels turning against the clean energy transition in low-income communities and elsewhere, Boyd’s experience is rare good news that advocates hope can continue to be replicated.
Energy Savers Network found Boyd through Duke’s Customer Assistance Program. Part of a side deal the utility struck in 2023 to lessen the blow of its rate hikes, the program offers a monthly credit of up to $42 on bills for households at or below 150% of the federal poverty level — about $50,000 for a family of four.
In 2024, Duke began automatically providing the credit to any customers who’d benefited in the prior year from one of two buckets of federal aid: the Crisis Intervention Program, designed to prevent or reverse life-threatening emergencies like utility shutoffs, or the Low-Income Energy Assistance Program, which offers one-time payments to help households with heating bills.
North Carolina’s Department of Health and Human Services manages the two funds and has a data-sharing agreement with Duke, which then enrolls customers in its program — a process that has minimized administrative expenses such as vetting participants for eligibility.
And though in its first year the bill assistance benefited less than half the number of households forecast, experts say that’s because funding for the two buckets of federal aid dropped, not because the need isn’t great. Advocates remain bullish about the prospect for Duke to serve 100,000 customers or more annually.
Totaling over $500 for a year, the bill credit alone is vital for families struggling to make ends meet, aid groups say.
But Boyd’s case demonstrates the full potential of the Customer Assistance Program: Virtually every household receiving help gets referred to a local entity that can assess homes and perform free efficiency upgrades, reducing energy burdens beyond the 12 months of financial aid.
The brainchild and passion project of former financial and utility consultant Brad Rouse, Energy Savers has undergone a few iterations over its nine years of existence. Its throughline is providing energy-efficiency retrofits, usually in a day’s time, via a team of volunteers guided by a professional.
When everything is running smoothly, that means the group can perform upgrades — such as adding insulation and sealing air leaks — for at least three homes a week, according to Rouse. But in its early years, Energy Savers sometimes struggled to meet that mark.
“The problem is we had a lot of client cancellations,” said Rouse, who today serves as Energy Savers’ executive director. If they were last-minute, the group didn’t always have a backup client ready to take advantage of assembled volunteers and staff. In that case, Rouse said, “we lose the day.”
But now, the organization has almost eliminated that problem. “The Duke Customer Assistance referral is one big reason why,” he said.
That’s because the utility sends so many referrals that it’s easier to find clients who will be ready by the time the Energy Savers team arrives, reducing the likelihood of cancellations. And when a client does fall through, there’s a waiting list ready to be tapped.
The group identifies households in need through multiple channels, including farmers markets, community events, and word of mouth. But its largest source of referrals these days is the Customer Assistance Program, said Steffi Rausch, director of operations.
“We send out a bulk mailing to [potential clients] first and then we try to follow up with phone calls to get them scheduled,” Rausch said.
Boyd, for instance, first got help paying her utility bills through Asheville Buncombe Community Christian Ministry, which accessed one of the federal crisis assistance funds for her. She was soon enrolled in Duke’s $42 bill-credit program and then referred to Energy Savers. “They popped up at my doorstep,” Boyd said.
In the last 11 months, 26% of Energy Savers’ referrals have come from the Duke Customer Assistance Program, according to Rausch. So far, 36 of those referred families have made it through the weatherization process.
“I’m very impressed with Duke at this point,” Rausch said. The utility, which funds the majority of the services provided by Energy Savers, always makes sure the group gets reimbursed, she said. “We’ve never been stuck with the bill.”
To be sure, Duke and advocates for low-income customers are still working out kinks in the bill-credit scheme. One challenge is waning funding for the two federal crisis assistance initiatives that are used to automatically enroll individuals in the Customer Assistance Program. Another hurdle is connecting the dots for recipients, who often don’t realize they’re getting the bill credit or that they’re getting referred to groups like Energy Savers.
Most of all, advocates are mindful that the Customer Assistance Program is in the middle of a three-year pilot phase, and they want to extend it one way or another — as a feature of Duke’s next three-year rate increase, as a condition of the merger of the company’s two North Carolina utilities, or as part of some other case before state regulators.
Boyd knows as well as advocates that the need for long-lasting energy savings is substantial. She’s now trying to get help for her 93-year-old Aunt Viola, whose electricity bill tops $400 a month.
“It’s only her in the house,“ Boyd said. “She could really use this program.”
LAS VEGAS — On Monday night in a subterranean hall under the Las Vegas Convention Center, Tesla released an upgraded version of its grid-battery product that will allow developers to build bigger energy-storage projects faster. That kind of acceleration is sorely needed as the storage industry positions itself to meet historic grid demand in the next few years.
While better known for its pioneering electric-car business, and the polarizing antics of CEO Elon Musk, the company is also a pacesetter in the fast-growing U.S. energy-storage industry.
Tesla’s white boxy Megapack product, which stitches together lithium-ion batteries inside a large container, has been a top competitor for years. Around the U.S., Megapacks play a crucial role in keeping the lights on: In Oahu, they enabled the safe retirement of Hawaii’s last coal plant; in Oxnard, California, they allowed the city to avoid building a gas plant on its coastline; across Texas, they’re helping lower electricity prices and avoid shortfalls during record heat waves, as are batteries from companies like Fluence and Wärtsilä.
But the storage industry is still young, with plenty of room to streamline operations and bring down costs. That’s what Tesla hopes to do with the new Megablock, which packages four Megapacks around one transformer.
One of these blocks holds 20 megawatt-hours of power, which can be discharged for up to four hours at peak capacity. Scaled up for a large project, 248 megawatt-hours can fit into an acre (for comparison, the Oxnard project packed in about 200 megawatt-hours per acre using earlier-generation Megapacks back in 2021).
Tesla is taking orders for Megablocks now and expects to ship starting in late 2026. The firm will manufacture them near Houston, with lithium-iron-phosphate batteries from multiple sources, including a 7-gigawatt-hour-per-year manufacturing line planned to be completed at the company’s Nevada Gigafactory in early 2026.
The timing is no coincidence. Tesla’s new announcement comes as AI computing gobbles up electricity in unfathomable quantities. The rapid construction of new power sources has emerged as a defining imperative for America’s tech industry as it races to achieve what it sees as the transformative benefits of advanced AI. President Donald Trump has claimed that global AI supremacy is a key priority, even as his administration has taken aggressive steps to choke off development of the nation’s fastest-growing sources of energy.
Tesla says the Megablock design will allow developers to deploy 1 gigawatt-hour’s worth of storage in just 20 business days. That’s an astonishing rate, if borne out in real-world conditions. The firm has made bold claims in the past that have failed to materialize on time if at all, like its visions of a widely adopted solar roof or a huge autonomous taxi fleet. But the Megablock doesn’t hinge on a fundamentally new product; it’s another step in the steady evolution of a flagship technology.
The Megablock’s main innovations are that it reduces the amount of electrical work required in the field while also packing in battery cells as densely as possible without going over the weight limit that triggers expensive specialized shipping protocols.
“For us, one of the key metrics was, what’s the maximum percent cell mass you can get?” said Mike Snyder, Tesla’s VP of energy and charging, in an interview after his presentation. “Because the cells are what matters. So we made sure we increased that. It’s an 86,000-pound box, and 75% of that is cell.”
A giant battery installation requires thousands of perfectly executed electrical connections, and mishaps can cause major problems. Megapacks come with their batteries pre-wired, allowing for factory-grade quality controls. But currently, each pack then needs to be connected to a medium-voltage transformer to ship power in and out, which takes up to 24 individual connections per pack.
“That’s just a lot of labor in the field, and it’s a lot of places where something can go wrong,” Snyder said. “One of those bolts, one of those cables, it causes downtime and you have to go fix it.”
The new Megablock, in contrast, needs just three connections per pack.
Tesla timed the unveiling for the opening night of RE+, the bustling solar and clean energy industry conference, but hosted it on Musk-affiliated turf: a station for his side project boring holes under the Las Vegas Convention Center. Attendees were invited to experience the thrill of being chauffeured in a manually driven Tesla through a one-lane tunnel — not necessarily a harbinger of the future of transport, but it was lit by colorful LEDs.
Musk himself was not on hand, but Snyder addressed the crowd from a stage that was also lit by LEDs and flanked by Cybertrucks and Tesla’s new humanoid automatons. The screen behind him lit up with sharply produced drone footage of massive Megapack installations in lush locales.
The spectacle offered an implicit riposte to the Trump Department of Energy, which a few days earlier had tweeted, “Wind and solar energy infrastructure is essentially worthless when it is dark outside, and the wind is not blowing.” The claim reflected either a remarkable ignorance of energy storage, a longtime research and deployment priority of that very same department, or a desire to pretend batteries don’t exist.
Batteries accounted for 23% of new grid-scale capacity built in the U.S. last year, compared to just 4% of new capacity that came from the fossil-gas plants much admired by the Trump administration.
While Tesla’s CEO spent hundreds of millions getting Trump elected and a few months slashing the federal civil service, Tesla’s engineers kept hacking away at the problem of making better batteries.
The attention to detail goes down to the paint job.
If you look at enough photos of grid battery projects, they blur into beige anonymity. But seeing the Megablock up close, the coat of white paint held more allure than it does from afar, more of a pearlescent sheen. A Tesla tour guide told me the shade was selected to maximize reflection of heat from the sun, thus reducing the energy needed to keep the batteries cool. The central chamber of the Megapack features a supercharged version of a Model Y heat pump, borrowed from colleagues on the automotive side of the company to chill liquid cooling streams that keep Megapack batteries and inverters safe.
Also taking in the sight was Tyler Norris, a Duke University doctoral student and leading researcher on how the U.S. might power its data-center boom. He noted that speed to market has become the premium that large energy customers are clamoring for.
“The U.S. is just in a major capacity crunch right now,” Norris said. “We’re going to need all sources of peaking capacity that we can get, and battery storage and the Megapack solutions are a critical option.”
The U.S. is expected to build 18 GW of batteries this year, per federal data, up from 13 GW last year, with California and Texas continuing to lead the way. Trump’s actions have injected deeper uncertainty into the market in 2025, with tariff fluctuations and new anti-China regulations. But the big tax-and-spending law passed by Republicans in July kept energy-storage tax incentives in place for years to come, even as it gutted wind and solar tax credits, meaning the outlook for storage is less muted than it is for the renewables it’s often paired with.
Meanwhile, data centers haven’t yet become big installers of on-site batteries, Norris added, but that could start to happen in the next couple of years. The typical four-hour duration of commercially available batteries today doesn’t lend itself to a round-the-clock power supply, so data-center developers are still figuring out how best to slot batteries into their energy portfolios.
Also viewing the big white box was Jesse Peltan, known for his spirited and data-rich defenses of clean energy on X, the Musk-owned social media platform.
“I think Megapack is the most underrated product that Tesla has by far, and I think Megablock is going to make it easier, cheaper, faster to interconnect Megapacks into the grid,” he said.
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.
Two of the leading startups working on advanced geothermal energy just struck deals with established industrial giants — moves that will help the companies accelerate their efforts to harness the potentially abundant source of carbon-free energy from underground.
Last week, Fervo Energy said it had picked oilfield services giant Baker Hughes to provide crucial equipment for the startup’s Cape Station geothermal plant in Utah, a selection that brings the 500-megawatt project closer to its 2028 completion goal. Baker Hughes will design and deliver equipment for five power-generating units totaling 300 MW in capacity, which will operate with Fervo’s fracking-based “enhanced geothermal system.”
The news followed an Aug. 28 announcement that startup Sage Geosystems is partnering with Ormat Technologies, a major global developer of conventional geothermal plants. The agreement will enable Sage to deploy its next-generation technology at one of Ormat’s existing sites in Nevada or Utah.
Teaming up with Ormat accelerates Sage’s timeline to build its first commercial power-generation facility by about two years. It’s now targeting to bring the plant online by late 2026 or early 2027, said Cindy Taff, CEO of Sage.
“For us, the ability to scale faster with Ormat is huge,” Taff told Canary Media. “But it’s also a great opportunity for Ormat to reach a deeper [geothermal] resource than what they’re targeting now.”
Geothermal energy represents only about 0.4% of total U.S. electricity generation — largely because existing technology is constrained by geography. Today’s geothermal plants rely on naturally occurring reservoirs of hot water and steam, found only in places like Northern California and Nevada, to spin their turbines and generate power.
Technological advances are making it possible to deploy geothermal in less obvious areas, breathing fresh life into the decades-old industry. In recent years, the carbon-free energy source has seen a surge of investment and bipartisan policy support amid soaring demand for electricity from data centers, factories, and electric vehicles.
Fervo and Sage, both based in Houston, have previously inked deals to supply the tech giants Google and Meta, respectively, with hundreds of megawatts of clean, around-the-clock power for their sprawling U.S. operations.
Next-generation geothermal also benefits from the fact that it shares the same workforce and supply chain as oil and gas companies, an industry now heavily favored in Washington, D.C. The sweeping budget law that President Donald Trump signed in July largely preserves key tax credits for geothermal power plants — despite slashing incentives for wind and solar — and the Trump administration is pushing to fast-track environmental reviews for all types of geothermal projects.
“Geothermal has always enjoyed support from both sides of the aisle,” said Taff, who was previously a vice president at fossil fuel company Shell. “But now there’s a lot of momentum for the industry.”
Sage’s approach to geothermal energy involves tapping into both heat and pressure from hot, dry rocks found deep underground. To start, the company drills wells and fractures rocks to create artificial reservoirs that it pumps full of water. Sage cycles the water in and out of the fracture — like inflating and deflating a balloon — and can jettison the liquid to the surface to drive turbines and produce electricity.
The startup’s partnership with Reno, Nevada-based Ormat will allow Sage to access land and power-plant equipment and to connect to the grid far more quickly than if the startup set up a new site on its own. The companies are looking to install the next-generation system at a facility where Ormat’s older conventional wells are declining in capacity.
“In general, plants may operate below capacity due to a combination of factors, such as changes in the geothermal resource over time,” said Smadar Lavi, Ormat’s vice president and head of investor relations and ESG planning and reporting. “These sites are well-suited for piloting Sage’s technology, as it offers the potential to unlock additional production from existing assets.”
Terra Rogers of the nonprofit Clean Air Task Force said that Ormat’s decision to expand beyond its traditional hydrothermal resources and into next-generation tech represents “an important step, and we’ve all been waiting for it.” Rogers, who leads the advocacy group’s superhot rock geothermal program, called Ormat the “grandparents of geothermal,” given that the company has been around for 60 years and operates more than 190 geothermal plants globally.
As part of the agreement, Ormat can license Sage’s technologies for power generation as well as energy storage. The startup uses a similar setup to store excess grid energy. But instead of drilling deep into high-temperature rocks, Sage pumps water into shallower formations that aren’t as hot, since heat isn’t needed for storage. Pressure builds up underground and can be released later, when power demand spikes, to spin a pinwheel-like Pelton turbine and send electricity back to the grid.
“The idea that [Ormat] chose Sage specifically, with their storage technology, is also very telling for the needs of the grid in the West,” Rogers said, adding that it “complements existing or intermittent forms of renewables” like wind and solar.
Sage recently finished building its first commercial storage project on the site of a coal plant owned by San Miguel Electric Cooperative in Christine, Texas. The facility, which is expected to connect to the Texas grid in December, will be able to discharge 3 MW for four to six hours at a time, according to Taff.
The startup plans to perform a demonstration of its electricity-generating tech in the first quarter of 2026 in Starr County, Texas, in partnership with the U.S. Air Force. Sage is also evaluating potential sites east of the Rocky Mountains to develop its 150-MW project with Meta.
Fervo, meanwhile, continues drilling away at its Cape Station project in Beaver County, Utah, which has been under construction for almost two years.
The eight-year-old company said an initial 100-MW installation is poised to start delivering power to the grid in 2026. An additional 400 MW is slated to come online in 2028, a portion of which will use the new equipment from Baker Hughes. The startup’s recent supply deal comes just months after Fervo said it secured $206 million in new financing for the Cape Station project.
“Fervo designed Cape Station to be a flagship development that’s scalable, repeatable, and a proof point that geothermal is ready to become a major source of reliable, carbon-free power in the U.S.,” Tim Latimer, Fervo’s CEO and cofounder, said in a Sept. 2 statement.
Three bills have advanced through the California Legislature that are meant to increase the use of virtual power plants as a way to rein in energy costs. While good news for utility customers, that welcomed progress comes with its own dose of bad news: The most ambitious proposals were stripped out of one of the bills in a secretive process inaccessible even to the bill’s author.
Two of the bills, AB 44 and AB 740, cleared a key legislative hurdle with only minor alterations that will not significantly reduce their impact, according to Edson Perez, who leads California legislative and political engagement for clean-energy trade group Advanced Energy United.
But SB 541, the most pioneering of the three bills in question, was “gutted” last week via an opaque legislative maneuver, Perez said. Those amendments stripped the bill of important provisions that would have required the state’s biggest utilities to provide data to enable them to build virtual power plants into their grid investment plans.
Those provisions “would have helped California get the most out of its existing grid while saving ratepayers billions,” Perez said. “At a time of skyrocketing electricity bills and reliability challenges, California can’t afford to sideline tools that make the grid cleaner, more resilient, and more affordable.”
California has the highest electricity rates in the nation outside of Hawaii. Virtual power plants, which stitch together distributed energy like rooftop solar, home batteries, and EVs, can’t solve that problem on their own. But they can certainly help: A new report from think tank GridLab and Kevala, a grid-data analytics startup found that California could cut energy costs for consumers by $3.7 billion to $13.7 billion in 2030, compared to a base case, by using home batteries, EV chargers, and smart thermostats to avoid or defer costly upgrades to power lines and other infrastructure.
The changes made to SB 541 will dramatically reduce the savings it could offer, according to Sen. Josh Becker, the Democrat who authored the bill and chair of the Senate energy committee.
“We’re very disappointed,” he said.
The bill still includes measures to spur utilities to expand their use of VPPs, “so we can avoid overbuilding to meet the highest peaks in demand,” he said. “But we’ve missed an opportunity to do so much more by focusing on the other half of the problem — all this spending on upgrading poles and wires that can be avoided if we take better advantage of distributed energy resources.”
Becker said he didn’t know who was responsible for excising that portion of the bill or why they did it. The amendments were introduced during a process known as “suspense,” during which the Legislature’s appropriations committees can amend or shelve bills with no debate or transparency into how changes are made or by whom. Last Friday’s process ended up culling more than a quarter of the 686 bills under consideration, including high-profile ones like a proposal to streamline permitting for high-speed rail.
“We’re pursuing every avenue to keep that language alive,” Becker said of the removed text. But there’s little time for lawmakers to secure revisions before Sept. 12, the last day for the Legislature to pass bills this year.
For a handful of hours every year in California, often on the hottest days, electricity use soars beyond the usual day-to-day level and hits what’s known as peak demand. To meet these peaks, utilities have historically opted to build more power plants and power lines than they need on a daily basis — an expensive choice that is responsible for a large portion of utility bills.
But California can reduce demand peaks and make a big dent in those costs by taking advantage of solar-charged batteries, smart thermostats, EV chargers, and other devices scattered across homes and businesses. Individual customers are compensated for allowing the rest of the grid to use their energy resources, but if done right, a VPP’s benefits outweigh those payments.
A 2024 analysis from The Brattle Group found that VPPs could shave about 15% of California’s peak demand by 2035, saving utility customers about $550 million each year. Most of those savings would flow to those whose clean energy assets are enrolled in the programs, but customers at large would also see costs decline because utilities wouldn’t have to build as much infrastructure.
California badly needs to cut those costs. Average residential electricity rates in the state increased 47% from 2019 to 2023 and now stand at nearly twice the national average, largely driven by the effort to prevent power lines from sparking deadly wildfires. Pressure to expand power grids to serve data centers, EV charging, and home electrification is set to push rates higher still.
In the face of these rising costs, “making better use of what’s already on the grid rather than building something from scratch is a pretty important consideration,” said Ryan Hledik, a principal at Brattle and lead author of the study.
But California is not on track to meet its VPP targets. In 2023, the California Energy Commission (CEC), acting to comply with a law passed the previous year, set a “load-shift” goal of 7 gigawatts by 2030 for the state. But the CEC’s June progress report found that California’s demand-flexibility capacity barely grew over the past two years and remains at just over 3.5 gigawatts, or about half the 2030 goal.
The state isn’t likely to reach its 7-GW target under “business-as-usual” conditions, the CEC report found. That’s especially true if the policymakers decide to eliminate programs created after grid emergencies in 2020 and 2022, which have grown fastest in recent years compared to utility-managed VPPs. The report concludes that California needs “additional near-term strategies” to close the gap.
SB 541 was designed to help fill that gap.
In particular, the bill was meant to do two main things to incorporate load flexibility into how California manages its grid costs, Becker explained: Track progress toward state goals and embed VPPs into how the state’s major utilities invest in their power grids.
The amended bill still requires the California Energy Commission to create regulations to track the progress toward the 7-GW goal by utilities, community energy providers, and other “load-serving entities” supplying power to customers. “We need to know which load-serving entities are doing a good job of it, and learn from the best practices,” Becker said.
But the original version of SB 541 also called on the California Public Utilities Commission to create regulations to require the state’s three major utilities to share data on their low-voltage distribution grids, and use that data to discover how VPPs can reduce the cost of managing that infrastructure. Last week’s amendments entirely cut this portion of the bill.
Brad Heavner, executive director of the California Solar and Storage Association trade group, said that’s a missed opportunity. Today’s VPPs and demand-response programs are triggered to reduce pressure on the state’s transmission grid and generator fleets when energy demand exceeds supply, he said. In other words, they’re “focused on times when we may not have enough energy statewide,” which is “obviously important.”
But as originally written, SB 541 would have required a more proactive approach that integrates VPPs into grid planning.
“From an affordability perspective, most of the reason our rates have increased is due to utility overspending on the distribution grid,” he said. “VPP programs should be equally focused on using networked batteries to avoid the cost of expanding substations and other big infrastructure.”
Getting utilities to do this has been a longtime challenge. For more than a decade, California regulators have been under state mandate to press utilities to integrate rooftop solar, batteries, and other distributed energy resources — DERs in industry parlance — into how they invest in and manage their grids.
But as Hledik told a California Assembly committee in July in testimony supporting SB 541, “attempts to use load flexibility as a distribution system resource have had limited success.” Existing programs aimed at requiring utilities to seek out DERs that can replace or defer grid investments have failed to result in any significant projects.
SB 541 was designed to overcome those previous pitfalls, Hledik said, by requiring that “load flexibility opportunities be considered earlier and more comprehensively in distribution planning.”
The other VPP bills don’t take on distribution grid costs. AB 740 would require the CEC to adopt a virtual power plant deployment plan by November 2026, in collaboration with state grid operator CAISO, the utilities commission, and an advisory group representing disadvantaged communities.
”It doesn’t require them to implement anything specifically,” said Perez of Advanced Energy United. “But it does require that cross-agency deep dive that is just not happening right now.”
AB 44, which Advanced Energy United also supports, is “more surgical,” Perez said. It would order the CEC to adopt a method to value VPPs as a means of reducing “resource adequacy” requirements — the calculation of the grid resources needed to meet peak demand in future years.
Resource adequacy costs are rising across California. A handful of community choice aggregators (CCAs), the city- and county-level entities that procure clean energy for a growing number of the customers of California’s big three utilities, have worked with CEC to prove that their VPPs function well enough to count toward resource adequacy. The CEC has then reduced their requirements accordingly, which has allowed CCAs to cut their customers’ energy bills.
That’s a useful route to capturing the value of VPPs, Perez said. But it’s largely been done on an ad-hoc basis to date, and “there’s no clear process” for other CCAs to follow suit, he explained. “AB 44 tries to make that process more transparent.”
None of the bills have passed yet. If they can clear the Legislature by mid-September, Gov. Gavin Newsom (D) will have until Oct. 12 to sign the legislation into law.
This isn’t state lawmakers’ first attempt to pass VPP bills.
Similar efforts failed to advance in last year’s legislative session, as did bills aimed at restricting utility spending. Utilities earn guaranteed profits for every dollar they spend on power grids and other capital infrastructure, which incentivizes them to resist VPP policies that might reduce those expenses — and California’s utilities have political heft in state government.
But Becker, who is also pushing legislation to offset utility spending through public financing in this year’s legislative session, said the state’s utilities are already struggling to expand their grids quickly enough to serve large new customers like EV charging depots and data centers.
In other words, they can’t spend money fast enough to build the grid that’s needed right now. “We’re just trying to align the rules of the game to reward good behavior,” he said.
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