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Australia has put itself on a realistic path to achieving what climate activists around the world have long dreamed of: running its power grid entirely on renewable energy.
The Australian Energy Market Operator oversees the nation’s power markets. Chief among them, the National Electricity Market serves about 90% of customers, minus remote areas and the west coast. At its peak, the system uses 38 gigawatts of power — more than New York state’s peak consumption. Over the last five years, AEMO has rigorously studied how the country, whose coal fleet is aging and which banned nuclear energy decades ago, can run this grid on renewables alone.
“This is not a climate-zealot kind of approach,” AEMO CEO Daniel Westerman told Canary Media. “Our old coal-fired power stations are breaking down; they’re retiring,” he said. “They’re getting replaced by the least-cost energy, which is renewable energy, backed with storage, connected in with transmission. We’ll have a bit of gas there for the winter doldrums. That is just what’s happening.”
Australia’s efforts could offer a proof of concept for how a nation with a bustling, modern economy can rapidly shift its electricity from fossil fuels — mostly coal with some gas — to wind, solar, storage, and other renewable sources like hydropower.
“There’s nothing impossible about 100% renewable supply,” said Jesse Jenkins, a Princeton University professor who has studied net-zero pathways for the U.S. “Australia has a better chance of this than almost anywhere.”
So far, renewables have surged to about 35% of annual electricity production, while coal still leads with 46%, according to the International Energy Agency.
Because this transition is primarily driven by market forces, rather than a legislative or regulatory requirement, Westerman couldn’t say for sure when Australia will hit the 100% mark. He does expect 90% of Australia’s coal generation will be gone by 2035, and the rest could shutter later that decade.
The more pressing milestone, though, will be the country’s first day with no coal generation on the system, which could happen far sooner due to some combination of competitive forces and mechanical trouble at the aging plants. It’s a landmark Westerman has experienced before: He operated the U.K. electricity network in 2017 when it ran without coal for the first day since the Industrial Revolution. The last British coal plant shut down seven years later, in 2024.
AEMO has developed a clear sense of what is needed to keep the lights on whenever coal power flickers out, he said. It’s a matter of getting “kit installed in the ground,” especially the unsexy machinery that can maintain a stable grid in the absence of big fossil-fuel-powered generators.
“It’s now a physical problem rather than an intellectual challenge, a ‘no one knows how to do this’ challenge,” Westerman said. “We can deal with that.”
Australia’s renewables outlook is strong for a few key reasons.
For one, it enjoys distinct geographical advantages, Jenkins noted: It spans a sunny, windy landmass the size of the contiguous United States, but with just 27 million people to provide for. (The U.S. has nearly 13 times more.)
It also has policy advantages. Australia has a national market governing the power sector, which allows technologies to proliferate faster than in places with patchwork regulations (like the U.S.) or strong incumbent monopoly utilities (also like the U.S.). Furthermore, Australia has avoided U.S.-style clean-energy trade protectionism, so cheap Chinese imports are plentiful.
Last month, the National Electricity Market topped out at more than 77% renewable generation for a half-hour period, Westerman said. Grid constraints kept that number from being even higher. The state of South Australia regularly generates more electricity from renewables than it consumes, shipping the excess to neighbors.
Australia doesn’t just excel at big renewables and big batteries. Four million homes produce rooftop solar; a few weeks ago, those households temporarily supplied 55% of demand on the National Electricity Market, Westerman said.
“Australians have an absolute love affair with rooftop solar,” he said. “We have the highest rooftop PV penetration in the world, and it’s one of the driving forces of our energy transition.”
Westerman flagged one big technical obstacle to reaching 100% renewables, and it’s not what many people expect.
The key hurdle to unlock a completely renewable system is to build up “rotating machines on the grid that don’t necessarily produce power,” Westerman said.
The physical spinning mass of the old coal plants’ generators delivered “essential system services” beyond just the kilowatt-hours. These services aren’t known to many people beyond grid engineers, but they go by names like voltage support, frequency regulation, synchronous inertia, and reactive power. Westerman describes them as “shock absorbers … to withstand the bumps and disturbances that we get all the time.”
“The consequence of not having system security is Spain and Portugal,” he said, referring to the nationwide blackouts this spring that have been traced to failure to control voltage levels.
If the coal plants are headed for extinction, something else needs to take on these responsibilities. Batteries can replicate some services. But Westerman worries about a service called fault current, which is necessary to operate the grid-scale version of fuses or breakers that protect equipment from issues like short circuits.
One way to do this is by building devices called synchronous condensers, which include a rotating hunk of metal that can spin without fossil-fuel combustion. But constructing new single-purpose infrastructure is expensive, especially when the energy-only markets don’t currently reward this grid service on its own.
Westerman has been talking up another option largely absent from decarbonization discourse in the U.S.: install a clutch on existing gas plants, on the shaft between the fuel-burning turbine and the spinning generator. The clutch isolates the generator, so it can keep spinning with a relatively minor jolt of electricity and without burning fossil fuels. This approach also keeps the gas plant around to produce power on what Westerman described as “cold, dark, and still” days, when the renewable fleet falls short. Such plants could eventually switch to biofuels or clean hydrogen instead of fossil gas.
“[The clutch] is like 1950s technology — it’s really boring,” Westerman said (“boring,” for grid operators, is the highest form of praise). “The marginal cost of putting this in is like nothing compared to the cost of the plant.”
A company called SSS has built these clutches for decades. One is nearly operational in the state of Queensland at the Townsville gas-fired plant, which Siemens Energy is converting into what it calls a “hybrid rotating grid stabilizer.” Siemens says this project is the world’s first such conversion of a gas turbine of this size.
That particular retrofit took about 18 months and involved some relocating of auxiliary components at Townsville to make room for the new clutch. So it’s not instantaneous, but far easier than building a new synchronous condenser from scratch, and about half the cost, per Siemens.
Some novel long-duration storage techniques also provide their own spinning mass. Canadian startup Hydrostor expects to break ground early next year on a fully permitted and contracted project in Broken Hill, a city deep in the Outback of New South Wales.
Broken Hill lent its name to BHP, which started there as a silver mine in 1885 and has grown to one of the largest global mining companies. More recently, the desert landscape played host to the postapocalyptic car chases of Mad Max 2. Now, roughly 18,000 people live there, at the end of one long line connecting to the broader grid.
Hydrostor will shore up local power by excavating an underground cavity and compressing air into it; releasing the compressed air turns a turbine to regenerate up to 200 megawatts for up to eight hours, serving the community if the grid connection goes down and otherwise shipping clean power to the broader grid.
But unlike batteries, Hydrostor’s technology uses old-school generators, and its compressors contribute additional spinning metal.
“We have a clutch spec’d in for New South Wales, because they need the inertia,” Hydrostor CEO Jon Norman said. “It’s so simple; it’s like the same clutches on your standard car.”
Transmission grid operator Transgrid ran a competitive process to determine the best way to provide system security to Broken Hill in the event it had to operate apart from the grid, Norman said. That analysis chose Hydrostor’s bid to simply insert a clutch when it installs its machinery.
The project still needs to get built, but if up-and-coming clean storage technologies could step in to provide that grid security, it wouldn’t all have to come from ghostly gas plants lingering on the system.
“It’s a different feeling [in Australia] — there’s a can do, go get ‘em, ‘put me in coach’ attitude,” said Audrey Zibelman, the American grid expert who ran AEMO before Westerman. “When you’re determined to say how best to go about this, as opposed to why it’s hard or why it doesn’t work, the solutions appear.”
See more from Canary Media’s “Chart of the week” column.
Globally, investors are pouring more money into renewable energy than ever — even as they pull back on spending in the U.S.
Over the first six months of this year, a total of $386 billion flowed to projects ranging from small rooftop solar installations to massive offshore wind farms, according to research firm BloombergNEF. That’s 10% higher than what investors doled out in the first half of 2024.
But the story is very different when you zoom in on the U.S.
As President Donald Trump enacts a scorched-earth campaign against renewables — particularly offshore wind — clean-energy investors are fleeing the nation’s increasingly volatile market. Spending was down by 12% compared to the first half of last year.
To an extent, the U.S.’s loss may have been Europe’s gain, according to BNEF. The European Union saw investment jump by 27% in the first half of this year, due in large part to major offshore wind developers shifting their focus from beleaguered projects on America’s East Coast to those in Europe’s North Sea. In the U.K., another offshore wind hot spot, investment tripled compared to the first half of last year, rising to $6.6 billion.
That increasing interest in erecting turbines in European waters helped buoy global investment figures. The offshore wind sector may be crumbling in the U.S. under Trump, but worldwide, it attracted more money in the first six months of this year than in all of last year.
Small-scale solar is also quickly gaining ground, especially in China, where investment in the energy source almost doubled even as funding for utility-scale solar fell by 28% due to policy changes that make those larger projects less lucrative.
Overall, the investment figures are trending in the right direction: up. But the growth remains sluggish compared to the blistering pace needed for the world to shift away from planet-warming fossil fuels.
This week, the Trump administration announced its most ambitious pro-coal plans yet — a multipronged effort to resuscitate the industry, despite the financial, health, and climate case against doing so.
The administration’s Monday announcement included three big pledges: The Department of Energy promised $625 million to prop up coal power plants, the Interior Department will open up 13 million acres of federal land for coal mining, and the EPA is delaying seven deadlines related to wastewater pollution from coal plants.
That promised DOE funding includes $350 million for recommissioning or modernizing coal power plants — an indication that the DOE will continue to force such facilities to stay open past their prime. The administration has already kept Michigan’s J.H. Campbell plant open for months beyond its planned retirement in May, racking up $29 million in costs to utility customers in just five weeks. At that rate, the plant would cost consumers $279 million each year to keep open, according to a recent Grid Strategies report.
J.H. Campbell is just one of roughly 30 coal plants that are supposed to retire through the end of 2028, when President Donald Trump’s term ends. Keeping them and other aging fossil-fuel plants open past their planned retirement could cost consumers as much as $6 billion each year, per Grid Strategies.
There’s a cheaper, and not to mention cleaner, way forward: According to a 2023 Energy Innovation report, every single soon-to-retire coal plant could be replaced with solar panels, wind turbines, and battery storage at a net savings to consumers. The rollback of clean-energy tax credits weakens that calculation, but renewables remain the cheapest, quickest way to add new power generation to the grid.
The Interior Department’s expansion of coal mining lands, meanwhile, ignores the fact that coal production has tanked in the U.S. since its peak in 2008, and that coal plants are already well stocked as it is.
And then there’s the administration’s focus on coal-plant wastewater — a critical piece of the industry’s operations, as burning coal produces coal ash, which can contaminate groundwater with deadly toxins. The Biden administration’s EPA had cracked down on loopholes that let power-plant operators avoid responsibility for these pollutants. Monday’s actions are among the Trump administration’s latest efforts to undermine those rules and let coal-plant owners off the hook for contamination.
Coal’s climate and health impacts — the worst among any U.S. electricity source — went unmentioned in any of the departmental plans. No surprise there: Late last week, it was also reported that the Energy Department has directed employees to avoid the use of pesky terms like “emissions” or “climate change.”
Fossil-fuel permitting keeps rolling amid shutdown
The U.S. government ran out of funding Wednesday after Congress failed to pass a stopgap bill, but the Trump administration is seemingly picking and choosing how to implement the shutdown.
At the EPA, where the administration has already implemented mass layoffs, about 89% of staff is set to be furloughed. Depending on how long the shutdown lasts, that reduced capacity could stymie Administrator Lee Zeldin’s deregulatory agenda.
Meanwhile the Interior Department will keep fossil-fuel permitting rolling along. More than half of the Bureau of Land Management’s staff will stay onboard to approve fossil-fuel projects under the Trump administration’s “energy emergency,” relying on money generated by permitting fees. The Bureau of Ocean Energy Management will similarly keep processing fossil-fuel permits and working on upcoming oil and gas lease sales, but “will cease all renewable energy activities,” according to a federal document.
EV tax credits are dead. What’s next?
Federal EV tax credits met their end this week, and automakers are already adapting to the new normal. Hyundai announced Wednesday that it’ll reduce the price of its popular Ioniq 5 by as much as $9,800 now that $7,500 federal rebates have ended. Tesla meanwhile took the opposite approach, raising lease prices for its models.
The looming expiration juiced EV sales for Hyundai, as well as Ford, General Motors, and Tesla, which all reported quarterly records from July through September. The longer-term impact of the tax-credit rollback remains uncertain, but it’ll be especially acute in the Southeastern U.S., Canary Media’s Elizabeth Ouzts reports. The region has deservedly been nicknamed the “battery belt” over the last few years as the Inflation Reduction Act spurred a wave of EV and battery manufacturing plants in Georgia, North Carolina, and beyond.
Inside the DOE cuts: The Trump administration says it’ll claw back $7.56 billion in grants for clean-energy projects, largely in states that voted for Kamala Harris in the 2024 presidential election, though grid-boosting projects that would’ve benefited red states are also on the chopping block. (Canary Media)
Hydropower’s looming crisis: Nearly 450 U.S. hydropower facilities are scheduled for relicensing over the next decade, but mounting costs and layers of bureaucracy could lead many to shut down instead. (Canary Media)
Deregulatory side effect: An Energy Innovation analysis finds Americans will end up paying more to fill their gas tanks if the Trump administration rolls back tailpipe-emissions rules that incentivize automakers to make more efficient vehicles. (The Verge)
Storage stays strong: Utility-scale battery storage set a quarterly record of 4.9 gigawatts installed in the U.S. in the second quarter of this year, though installations could fall as much as 10% in 2027 as federal support wanes. (US Energy Storage Monitor)
Battery-based breeze: Legacy air-conditioning giant Carrier is pairing AC units with batteries to relieve stress on the grid when lots of customers need to keep cool. (Canary Media)
Community solar cools: Community solar installations slowed 36% in the first half of 2025 from the same period last year, and the end of federal incentives suggests deployment will continue to fall. (Wood Mackenzie)
Trash or treasure: A billion dollars’ worth of aluminum cans end up in U.S. landfills every year, but with producers looking to curb their emissions and tariffs raising the price of virgin materials, that waste is becoming more and more valuable. (Canary Media)
America’s Lithium: The U.S. Energy Department says it’ll take 5% stakes in both Lithium Americas and the firm’s Thacker Pass project as the mine shapes up to become a key domestic source of lithium. (CNBC)
Curtains for coal: New England’s last coal-burning power plant, Merrimack Station in New Hampshire, shuts down after 65 years in operation. (Concord Monitor)
A correction was made on Oct. 3, 2025: Hyundai announced the price drop for its Ioniq 5 on Wednesday, Oct. 1, 2025, not on Thursday, Oct. 2.
Americans toss out roughly a billion dollars’ worth of aluminum drink cans a year — a valuable heap that the U.S. aluminum industry has long been working to keep from landfills. Recycling old metal into new products requires dramatically less energy than producing aluminum from scratch, giving companies a cheaper and lower-carbon way to make the versatile material.
Now, U.S. trade policy is lending new urgency to the effort to rescue discarded metal from junkyards and garbage bins across the country.
In June, the Trump administration raised tariffs on imports of aluminum and steel from 25% to 50% to bolster domestic production of both metals. About half of all aluminum used in the United States comes from other countries, primarily Canada, putting pressure on U.S. manufacturers to start churning out more aluminum and aluminum products at home.
Scrap metal, as a result, is an increasingly hot commodity. American companies are both importing more of it — the tariffs don’t apply to scrap — and scouring the country for domestic reserves of crumpled beverage cans, spare car parts, and bent-up building beams.
Demand for recycled aluminum was already rising before the tariff hike. Everyone from electric-vehicle makers and construction firms to solar-panel companies and packaging producers has been sourcing more of the relatively clean material as they work to reduce carbon emissions from their own supply chains.
“Recycling is the fastest-growing segment of the industry today, and it’s the cheapest, most effective way to make the United States more self-sufficient for its aluminum needs and less reliant on imports” of new metal, said Kelly Thomas, president and CEO of Vista Metals, which makes specialty aluminum products for vehicles, buildings, and industrial facilities.
Underlying all these trends is the fact that the U.S. makes far less primary, or nonrecycled, aluminum than it used to, with only four of the nation’s smelters still operating today. Each of the facilities can gobble enough electricity annually to power a mid-sized U.S. city, whereas recycling operations use only about 5% of the energy needed to run smelters.
Thomas, who is vice chair of the Aluminum Association, was speaking on a Sept. 18 call with reporters. The trade group had just released a report on the U.S. aluminum market for the first six months of 2025, which found that inventories of aluminum scrap rose 14.7% compared to the same period last year in response to tariffs. (More recent data show that levels continue to spike, with inventories up 35% in July compared to the same month last year.)
Still, it’s unclear how President Donald Trump’s trade policies will affect low-carbon aluminum production in the long run. While some recyclers stand to immediately benefit from the increased reliance on scrap, the results across the industry have been murkier.
Total aluminum shipments from U.S. and Canadian facilities fell 4.5% year-over-year through June as wider economic uncertainty and rising commodity prices weakened overall demand for the metal, according to the Aluminum Association. At least one downstream supplier, Wisconsin Aluminum Foundry, has reportedly laid off more than a hundred workers as a result of unfavorable market conditions.
“It’s too early to say if it’s a blip or something more systemic,” Murray Rudisill, vice president of operations at Reynolds Consumer Products and chair of the Aluminum Association, said on the press call. “As tariff impacts start to make their way into the market, we will be carefully monitoring demand numbers to see if this softening continues or accelerates,” he said, adding that the report “is a reminder that we are not immune to broader economic headwinds.”
The reactions from America’s two remaining primary producers have been similarly mixed.
Pittsburgh-based Alcoa has criticized the 50% tariff, warning that — far from revitalizing the U.S. industry — the higher prices on imported aluminum will lead to “some type of demand destruction” as consumer appetite slows, Bill Oplinger, the company’s CEO, recently told Bloomberg. Alcoa also produces aluminum in Canada and imports it to the U.S., and the tariffs have reportedly increased the company’s annual expenses by $850 million.
Century Aluminum, by contrast, has applauded the trade policy. In August, the Chicago-based manufacturer said it is ramping up production in response to tariffs. Century will invest about $50 million to restart over 50,000 metric tons of idled production at its Mt. Holly smelter in South Carolina by June 2026. The company will purchase additional electricity for the restart from the utility Santee Cooper, which gets most of its energy supply from coal, fossil gas, and nuclear power plants.
Century and another company, Emirates Global Aluminium, are both planning to build entirely new smelters in the U.S., which together would nearly triple the nation’s primary-aluminum capacity. However, the smelters likely won’t come online for several years or more, meaning they won’t help reduce the supply crunch or price pain facing the industry right now.
In the meantime, the U.S. aluminum industry is accelerating its hunt for scrap. The startup Amp, for instance, said it has deployed around 400 robotic sorting systems, mainly in the U.S., that pluck aluminum from waste-handling facilities; the firm raised $91 million last year to expand its fleet. And a can-collection company called Clynk was just acquired by Norway’s Tomra as it works to deploy more of its automated bag-drop stations across the country.
The Aluminum Association, meanwhile, is continuing to lobby for measures that would boost the nation’s recycling rate — which, when it comes to drink cans, is at its lowest point in decades. State “bottle bills,” for example, provide a small financial incentive for returning cans to official redemption centers. Only 10 states have adopted them to date.
“When we look at the Midwest, or areas like Texas, that don’t have any sort of policies around recycling … we’re reframing this as an economic matter,” Henry Gordinier, president and CEO of Tri-Arrows Aluminum, said of the policy push. He noted that aluminum is one of the top three industries in Kentucky, where Tri-Arrows is based.
“It’s bringing awareness to say, ‘Hey, recycling metal is actually vital to the economy of the state,’” he said.
Community solar has thrived in Illinois, thanks to clean-energy laws passed by state legislators in 2016 and 2021. Now, though, one major utility’s especially slow process for reviewing applications could jeopardize further progress. Developers stuck in the interconnection queue may not be able to access key federal tax credits that were sent to an early grave by the GOP’s One Big Beautiful Bill Act.
The beauty of community solar is that it allows anyone, even those who can’t put photovoltaic panels on their own properties, to access solar energy via subscriptions to a larger array sited elsewhere. Until congressional Republicans passed their budget law this summer, the companies building community solar could tap federal tax credits into the 2030s; now, projects must begin construction by July 2026 or be placed in service by the end of 2027 to qualify.
Before any power-generating project can connect to the grid, it needs to undergo a lengthy review. Utilities must determine the project’s viability and the cost of grid upgrades that it might require, which the developer usually pays for and needs to know ahead of time to secure financing. Though the process is notorious for taking too long, the actual length of time a proposal spends in this interconnection queue can vary greatly depending on the utility.
Advocates are calling out Ameren, which serves central and southern Illinois, for taking longer than the norm. One major reason is that the utility only studies community solar applications one at a time. At that rate, it takes years or even decades for proposals to be reviewed and ready for construction.
By contrast, ComEd, the utility that serves northern Illinois, reviews multiple project proposals concurrently and “typically performs hundreds of studies every month,” according to the ComEd team that specializes in interconnection and distributed energy resources.
Ameren currently has over 1,700 projects pending review in its interconnection queue, the vast majority of which are community solar, according to Ameren spokesperson Marcelyn Love.
The utility is moving toward studying proposals concurrently, like ComEd does, but the policy won’t be fully in place until January 2027, said Love. That’s too late for projects depending on the federal tax credit to make their finances work.
“I think we’ll see a lot of projects that can’t meet these deadlines and just fall off,” said Jessica Collingsworth, central policy director for Nexamp, a community solar developer with headquarters in Chicago and Boston. “Every developer is trying to start construction on as much as possible.”
Illinois currently ranks among the top five states for community solar capacity. Illinois lawmakers kick-started this development in 2016, when they created a state program now called Illinois Shines to incentivize development of the shared arrays.
About 768 megawatts of community solar are already operating statewide, according to a report by consultancy Wood Mackenzie and the Solar Energy Industries Association, a trade group. But far more proposals are pending, meaning Ameren and ComEd have needed to quickly figure out how to add increasing amounts of community solar to their grids.
ComEd now has about 200 community solar projects totaling more than 430 MW of generation in its territory, according to utility spokesperson David O’Dowd. In 2025 so far, the utility has received 442 requests for new community solar projects. It is dealing with about 750 pending applications in all, including around 80 that have interconnection agreements but are awaiting a customer signature, O’Dowd said.
Even with the glut of applications, ComEd said it has managed to complete interconnection studies and agreements in a timely fashion, in part because it studies projects concurrently.
Developers agree with that assessment. Nexamp, for example, “has experience in over a dozen markets and finds concurrent studies to be the fastest way to get local solar to the grid,” Collingsworth said. The firm has 31 community solar projects operating in ComEd territory and a number of proposals pending in Ameren territory.
“We need certainty around interconnection costs before we can feel confident beginning construction on projects,” said Collingsworth. “Anything that delays getting that certainty is a problem we need to solve quickly.”
Love said that Ameren is increasing its “internal and contractor resources” to be able to do multiple studies at the same time — in other words, the utility is bringing on more experts to review proposals.
“These improvements have already helped us advance 20 applications that were second in line, allowing us to both test out the concurrent study process and get more applicants information about their projects,” she said.
But the utility must balance the benefits of hiring more people to do the studies with the costs for those hires, which customers will ultimately pay for in their bills, she added.
Ameren is also working to address other reasons for interconnection delays.
For example, sometimes the utility spends a lot of time reviewing a project, only to ultimately decide it cannot be approved at all. To avoid this unnecessary use of resources, Love said Ameren is “studying the limits of what different circuits and substations on the grid can handle, to be able to more quickly predict when an application for connecting community solar in that area will be denied because the grid has reached its maximum capacity.”
The utility is “redesigning our approach to identify projects that have a high propensity for approval,” Love added, so that agreements can be signed more quickly, leaving detailed cost analyses until later in the process.
This means that Ameren “can get more projects through the pipeline and avoid spending time and resources on applications that are unlikely to move forward, due to high costs or other factors,” Love said.
Collingsworth said that more information and transparency from the utility make developers’ jobs easier, since they know which proposals to prioritize.
Love said Ameren has made maps and queue reports more user-friendly, so that developers will have a better idea of which projects are worth pursuing. The utility is also offering companies “a one-time opportunity to reduce the size of their project to help manage anticipated interconnection costs,” Love said, meaning that developers can change their proposal without having to resubmit it and lose their place in line.
While delays have not been a major problem in ComEd territory, according to developers, the utility has also taken steps to reduce interconnection wait times. It is allowing the use of a letter of credit or escrow account instead of cash as the deposit needed before construction can begin, and it is connecting developers seeking to do projects on the same part of the grid, so they can potentially collaborate to reduce costs.
A clean-energy bill that state legislators may consider during an October veto session aims to hasten the interconnection process across Illinois. The legislation would create a working group composed of utilities, developers, and other stakeholders that would report to the Illinois Commerce Commission, the body that regulates energy.
The state’s 2021 clean-energy law called for an interconnection working group, but “it hasn’t been a very productive space,” Collingsworth said. The newly proposed committee would be required to study and report to the Commerce Commission on certain issues, including interconnection timelines, cost-sharing between developers, and ways to create more transparency around the process. The Commerce Commission could then codify such concepts as binding rules and policies.
While the bill’s passage likely wouldn’t help projects meet the July 2026 construction-start deadline for federal tax credits, Collingsworth said it is important for the future of community solar in Illinois. Along with establishing the interconnection committee, the legislation would create a virtual power plant program, providing extra revenue to battery-equipped community solar projects that send power to the grid at times of peak demand.
Professionals in the solar industry said that the impending loss of federal tax credits underscores the importance of such state-level programs and policies.
“The tax credit is a key economic driver in Illinois, and without it, there is a much larger need for the incentives in the Illinois Shines program to fill the gaps,” said Nick Theisen, director of business development for TurningPoint Energy, which has more than 40 community solar projects built or in the works in Illinois, all in ComEd territory.
Andrew Linhares, who leads Midwest policy work for the Solar Energy Industries Association, echoed Theisen’s sentiment. “The bottom line is that state-level leadership on clean energy is more important than ever as federal policies and red tape are raising energy prices and making it harder to meet rising energy demand.”
For nearly a century, the Kelley’s Falls Dam in Manchester, New Hampshire, generated as much as 2,400 megawatt-hours of electricity per year. When the small hydroelectric station in a downtown park came up for relicensing in 2022, its owners faced what many dam operators now expect when trying to extend the lifespan of these power generators: strict requirements that would force them to spend millions on upgrades to qualify for a new operating permit. Instead, Green Mountain Power made a choice that has become common among hydroelectric operators. The utility simply surrendered its licenses.
Last year, the plant shut down.
Nearly 450 hydroelectric stations totaling more than 16 gigawatts of generating capacity are scheduled for relicensing across the United States over the next decade. That’s roughly 40% of the nonfederal fleet (the government owns about half the hydropower stations in the U.S.). The country is now on the verge of a major shift in hydropower. The facilities could be relicensed to supply the booming demand for electricity to power everything from data centers to aluminum smelters. Tech and industrial giants could even help pay for the costly relicensing process with deals like the record-setting $3 billion contract Google inked with hydropower operator Brookfield Asset Management in July for up to 3 gigawatts of hydropower. Or, as has been happening for years, the U.S. could continue to lose gigawatts of power as hydroelectric facilities shut down rather than absorb the high costs of relicensing — especially with cheaper competition from gas, wind, and solar.
The fleet of dams that helped electrify the nation starting in the late 1800s provides the second-largest share of the country’s renewable power after wind, and by far its most firm. But the average age of U.S. dams is 65 years, meaning the bulk of the fleet wasn’t built with newfangled infrastructure to enable unobstructed passage for fish and other wildlife. As seen in New Hampshire, the cost of upgrading facilities to allow for that passage can soar into the tens of millions of dollars — on top of the expense of upgrading custom-built equipment for each plant. Complicating matters further, after decades of decline in the hydropower sector, the manufacturing muscle for turbines and other hardware that make a dam work has largely atrophied in the U.S.
The biggest obstacle to a hydropower comeback may be the relicensing bureaucracy. The problem is that the Federal Power Act — passed in 1920 to regulate hydroelectric facilities — does not give any single agency full authority over hydropower the way the Nuclear Regulatory Commission has over atomic energy. The Federal Energy Regulatory Commission issues the key permits on the national level, but other agencies also play a role. The Fish and Wildlife Service, for example, may require a National Environmental Policy Act review to examine a dam’s effects on a specific fish species, a process that involves assessing multiple spawning cycles. And once that’s done for salmon, the agency may undertake yet another multiyear study on trout. FERC, meanwhile, can’t issue its licenses until state agencies overseeing waterways approve permits. That alone can eat up years.
As a result, it takes eight years on average to relicense an existing hydropower facility, according to the National Hydropower Association, the leading U.S. trade group. That’s more than five times slower than licensing for the typical atomic power station. (Nuclear, hydroelectricity’s closest competitor for clean, always-available power, is also notorious for its slow permitting timeline.)
“It takes longer to relicense an existing hydro facility than a new nuclear facility,” said Malcolm Woolf, the National Hydropower Association’s chief executive. “It takes just 18 months to get a new license for a nuclear plant.”
With no central body in charge of permitting hydropower plants, multiple state agencies have been known to take advantage of the once-in-a-generation certification process — eliciting support for tangentially related projects from dam owners who once represented a big and growing business.
“This is major infrastructure. These facilities cost billions of dollars,” Woolf said. “They’re like bridges and roads. They get a license for 50 years. The state agencies view [the relicensing process] as an opportunity to extract concessions from what they view as a deep pocket.”
At times, those concessions have little to do with the functioning of the hydropower plant itself. Woolf cited examples of dam owners pressed to build an amphitheater for Boy Scouts, and to fund the construction of regional roads that wouldn’t even go to the plant.
“One … regulator was requiring a facility to pay for a feral-pig-eradication program,” Woolf said.
“In the 1970s, maybe the industry was a deep pocket,” he added. “But now, with the low cost of other fuels like wind and solar and gas, it’s driving these facilities to bankruptcy and to surrender licenses.”
The eight-year timeline for relicensing is just an average.
In Idaho, the Hells Canyon hydroelectric plant has gone for 20 years without a permanent license. In Maryland, the Conowingo Dam’s relicensing process has also stretched on for two decades. In Massachusetts, the Northfield Mountain plant is in the middle of a 15-year permitting slog.
To continue operating, hydroplant owners obtain one-year extensions as they inch toward full licenses. “But if they don’t have a long-term license,” Woolf warned, “they’re not about to invest millions in upgrades.”
One potential bright spot in the relicensing quagmire has been a shift in federal tax policy. For years, the wind and solar industries have benefited from a rule that treats facilities as new if owners reinvest at least 80% of the plant’s market value into upgrades like new turbines or panels, making them eligible for bigger federal write-offs. In January, the Biden administration’s Treasury Department granted hydroelectric facilities the same flexibility.
But so far, no hydroelectric facility has made use of the federal investment tax credit except one small plant that was destroyed in a flood, thus requiring a total reconstruction. That’s because until recently the industry still lacked clear guidance on how to apply the tax credit.
“The question in the hydropower industry was, if you think of the Hoover Dam, is it 80% of the electric generating equipment? Or 80% of the whole Hoover Dam and the reservoir? So that’s what the Treasury clarified,” Woolf said. “It’s 80% of the electric generating equipment. So if you replace a 50-year-old generator with a new generator, you’re going to satisfy that.”
While renewables face ongoing opposition from the Trump administration, the president specifically named hydropower as a key priority in his Day 1 executive orders on energy. In July, Donald Trump signed the One Big Beautiful Bill Act, preserving hydropower’s access to key federal tax credits for the next eight years. If a hydro project is built in a designated “energy community” and uses domestically manufactured equipment, the tax credit can cover as much as half the investment.
Providing safe passage for fish through dams is a perpetual challenge, especially at older facilities that lack proper infrastructure. But dams that have been updated with newer, thinner turbine blades are also an issue, as the blades become guillotines for trout and salmon navigating through. American eels pose an even greater problem, as the snake-like fish — which can make up as much as half the biomass in rivers across the country — migrate downstream to spawn as breeding-age adults.
One of the simplest and most widely used tools to prevent fish from being killed in a dam’s turbines is a screen that blocks them from entering the plant’s water intake. Other methods include fish ladders or elevators that allow wildlife to ascend rising water to reach the other side. Less practical are trap-and-haul systems where fish are manually captured and set free above the dam.
“Fish-passage solutions can be extraordinarily expensive,” said Jennifer Garson, the former director of the Department of Energy’s Water Power Technologies Office. “The problem is the burden falls completely on hydropower operators to make these upgrades.”
The key to overcoming the issue may be marrying the refurbishment of hydropower stations with environmental upgrades. In 2019, the startup Natel Energy, which designs fish-safe hydropower turbines, installed its pilot project in Maine, then another in Oregon the following year. Natel’s technology — based on thicker blades that don’t sever fish as they move through the dam — was validated by the Pacific Northwest National Laboratory. The company won $9 million from the Energy Department to scale up its supply chain.
While the fish-safe blades are thicker than traditional turbine blades, Natel claims that its equipment is more efficient than the older equipment it’s replacing. Compared with turbines that are nearly 40 years old, CEO Gia Schneider said, the new Natel units produce more electricity per spin on average.
“They’re going to modernize, get fish-safe turbines that will safely pass eel, salmon, and herring that need to go through the plant, and they’ll get 5% more energy,” Schneider said.
Even replacing newer blades comes with little loss in efficiency.
“At another plant where we’re working on the design, the turbines are pretty young – only installed 10 years ago,” she said. “There, we’re going to get maybe 0.2% less energy out.”
On balance, Schneider noted, plant owners get more out of the facility, because even with new traditional turbines, dams require very fine exclusion screens and other equipment that restrict water flow enough to reduce energy output by anywhere from 5% to 15%.
“You’re losing a lot more from these bolt-on solutions,” she said. “At the end of the day, if you get 0.2% less on the turbine side, … on the whole-plant level, you’re coming out ahead.”
At the moment, hydropower finds itself in a similar position to that of nuclear energy a few years ago, where existing facilities risk closure due to relicensing costs amid competition from cheaper newcomers. The U.S. is now actively looking to restart its nuclear program, with the once far-fetched prospect of new large-scale reactors under serious consideration. Even if hydropower can similarly flip its fortunes, few in the industry anticipate an appetite in the U.S. for a Hoover Dam–size project. Still, there is ample opportunity for new hydroelectric capacity.
Just 3% of the nation’s 80,000 dams generate electricity. In 2012, an Energy Department report found that the U.S. could add 12 gigawatts of new power by overhauling those facilities to produce electricity. More than a decade later, “none of it was built,” Woolf said.
There are plenty of hydropower critics who welcome that stagnation. The history of damming rivers is rife with ecological destruction that fish-passage routes don’t entirely solve, as well as social upheaval from land seizures that uprooted poor, Black, and Indigenous communities from their homes to make way for new reservoirs.
And in parts of the U.S. where water is growing more scarce as the climate warms, reservoirs are drying up. Hydropower output in the American West hit a 22-year low last year after below-average snowfall, according to analysis by the Energy Information Administration. Yet other parts of the U.S., such as the Northeast, are getting wetter as the planet heats up.
While debate over hydropower continues in the U.S., nations overseas are moving ahead with new dam projects. In July, China started construction on what will, upon completion, be the world’s largest power station, a giant hydroelectric facility in Tibet. Last month, Brazil held its first auctions for new small- and medium-size dams with hopes of turning $1 billion in investments into more hydroelectricity. And Ethiopia just opened its megadam project meant to alleviate electricity issues in the country, despite pushback from Egyptians who say the facility could negatively impact the flow of water on the Nile.
The U.S. could get in on the game, or at least work to clear away hurdles preventing the country from taking advantage of the infrastructure that already exists. As the Trump administration looks to re-shore heavy industry through tariffs, Woolf said, “hydropower is a great resource for colocating manufacturing because you’ve got energy infrastructure and you’re typically in fairly rural areas where land is less expensive.” For data centers, reservoirs could offer the additional service of providing water for cooling hot computer servers, along with electricity. And when the U.S. still had 33 operating aluminum smelters in 1980, many of them relied on publicly owned hydropower facilities to provide cheap power. These plants could, in theory, play that role again as new demand for domestically produced aluminum — to manufacture electric vehicles and clean-energy equipment — puts strain on the remaining six smelters.
“We know we’ve got load growth. We know we’ve got grid variability from renewables and extreme weather. The flexibility of hydropower offers clean, firm generation that is unique,” Woolf said. “At the same time — through quirk of history — we’ve got so much of the fleet at relicensing and at risk of surrendering permits. This could be an amazing opportunity.”
At the turn of the millennium, France had one of the lowest-carbon electricity grids in Europe (and the world). While countries like the UK and Germany emitted well over 500 grams of CO₂ per kilowatt-hour of electricity, France emitted just 80 grams — six times less. This was mostly thanks to nuclear power.
In the 1980s and 1990s, France rapidly expanded its power grid, and almost all of this growth came from new nuclear plants. The chart shows this: in the 1980s alone, nuclear power grew from 60 to over 300 terawatt-hours.
By 2000, nuclear power supplied almost 80% of the country’s electricity, making it much cleaner than its neighbors, mostly relying on coal and gas.
France still has one of the cleanest grids in Europe, although it has added very little nuclear power in the 21st century. It has opened just one plant in the last 25 years, in Flamanville, following long delays and cost overruns.
In the last decade, solar and wind power have grown the most.
See what countries produce nuclear energy, and how their generation has changed over time →
Earlier this year in tiny Liberty, North Carolina, a multibillion-dollar Toyota plant began shipping batteries for use in the auto giant’s hybrid and electric vehicles. Expected to ultimately create at least 5,000 jobs, the facility is the largest investment to date in the Southeast’s burgeoning “battery belt,” which leads the nation in plans for the manufacturing of electric vehicles and their components.
The Liberty plant — along with other projects in the EV supply chain — was a bright spot in a recent assessment of the region’s electric transportation sector, which also highlighted record growth in EV sales and rapid deployment of fast chargers. The question is whether that momentum can survive gale-force federal headwinds, including today’s expiration of tax credits for EV buyers.
The two groups behind the report, Southern Alliance for Clean Energy and Atlas Public Policy, say the answer now depends on key players outside of Washington, from utilities to consumers to automakers. But the organizations cast themselves as cautiously optimistic.
That may seem counterintuitive given that congressional Republicans, led by President Donald Trump, have dealt blow after blow this year to the policies meant to hasten the nation’s shift to clean transportation.
Generous tax credits for purchasing new and used electric passenger cars now end Sept. 30 instead of in 2032, as do inducements to buy commercial EVs, thanks to the GOP budget bill signed into law this summer. The measure also scales back incentives for manufacturing EVs and their components, like batteries.
In May, Congress voted to revoke California’s long-held authority to set its own tailpipe pollution standards, which have nudged automakers away from combustion engines and created demand for EVs nationwide. Trump signed the legislation in June.
At the same time, the Trump administration has moved to roll back the national version of those tailpipe rules and stalled the nationwide buildout of electric vehicle charging infrastructure — which was authorized in bipartisan fashion in 2021.
There are few state policies in the Southeast to counteract this federal backsliding. In fact, due to added registration fees and the like, EV owners across the region pay more into state coffers than do owners of combustion vehicles who drive the same amount. Of the six states covered in the new report, from North Carolina to Alabama to Florida, only the latter has no such punitive fees.
Advocates involved with the analysis are clear-eyed about these roadblocks for passenger EVs. But they also say there is cause for guarded hope — starting with consumer behavior.
The fact remains that EVs are gaining popularity in the region, growing in market share in each of the six years that the report has been produced. EV sales in Florida — hardly a bastion of clean-energy policy — have led the way, making up more than a tenth of new car purchases in the first half of 2025, above the national average. The state’s mild temperatures and flatlands are especially conducive to EV driving, but the growth is still telling.
What’s more, drivers appear relatively undeterred by state EV taxes. Florida leads the region, but Georgia and North Carolina are neck and neck in EV adoption, even though the former has higher fees.
“There’s no clear correlation between those taxes and buying an EV,” said Stan Cross, electric transportation program director at Southern Alliance for Clean Energy and a report author.
Publicly accessible charging ports are also rising sharply across the region, with fast chargers jumping 41% and slower Level 2 chargers increasing by 24% over the last year, according to the study. That growth appears poised to continue. After what critics said was an illegal pause by the Trump administration, money for the National Electric Vehicle Infrastructure program is set to start flowing again. As soon as it does, Cross predicts quick action.
“States have already done the planning, and EV charging companies and the businesses hosting the chargers are chomping at the bit to compete for contracts, get the stations in the ground, and meet the charging demands of eager EV drivers,” Cross said.
The deployment of EVs aligns with the self-interest of the investor-owned monopoly utilities that dominate the region: Electric vehicles can both increase their sales and provide other benefits to the grid. For instance, plug-in cars and buses can act as batteries, storing power that can be discharged during times of high demand. Outlays by Southeastern utilities experimenting with these uses have lagged behind those in the rest of the country — representing just 7% of the nation’s $6.6 billion in approved investments. But utilities in the region, say advocates, are at least moving in the right direction.
Perhaps more than any other player, the automakers themselves will make the biggest difference in how EV deployment unfolds — in the Southeast and across the U.S.
One decision automakers face is on the front end: Do they retreat from, or double down on, the investments they’ve already made in battery and electric vehicle production? The report notes that companies have already canceled plans for seven facilities in the region, worth a total of $3.5 billion, in the last year. But others are proceeding more or less as planned, including the Toyota facility in Liberty.
If major carmakers continue their commitment to produce vehicles and their components in the United States, consumers will likely benefit from lower prices.
“The most expensive part of an EV is the battery,” said Matthew Vining, policy analyst at Atlas Public Policy and an author of the report. The Liberty plant, he noted, has already made Toyota cars produced in the U.S. more affordable.
That trend could persist since Congress spared incentives for battery manufacturing from devastating cuts in this summer’s budget law.
“From the federal government, there’s actually a good amount of support for the battery and the critical minerals industry,” Vining said. “That will have a downward pressure on the price of the vehicles, making them more appealing to drivers.”
Automakers also face choices on the back end. Riding high off a burst in sales from buyers rushing to take advantage of the expiring tax credit, they may keep their prices low for a while longer.
No matter what, transportation is electrifying across the globe. One in four new cars purchased this year will be electric, Vining said, and China already has about 60% of the market. The question is whether carmakers in the United States will try to catch up or retrench to fossil fuels, he said.
“Are these automakers going to rise to the challenge?”
XGS Energy, an advanced-geothermal startup, says it has completed crucial testing that proves its novel technology can operate reliably at commercial scale — without losing a drop of water in the process.
The milestone, announced on Tuesday, will allow Houston-based XGS to begin financing and building its first next-generation geothermal energy project, according to the company. XGS is partnering with Meta and the utility PNM to develop 150 megawatts of around-the-clock clean electricity in New Mexico that will supply the tech giant’s data centers.
“We’re really off to the races now,” said Josh Prueher, the CEO of XGS. The startup is slated to deploy the project’s first 5 MW by around 2027 and bring the remaining megawatts online by 2029, he added.
XGS is part of a fast-growing industry that’s working to harness the world’s abundant geothermal resources to meet soaring electricity demand. Dozens of U.S. companies are developing cutting-edge technologies that promise to access Earth’s heat in drier, deeper, and hotter conditions than is technically or economically feasible for conventional geothermal plants. Another of these firms, Sage Geosystems, is also partnering with Meta to build its own 150-MW geothermal facility somewhere east of the Rocky Mountains.
Today, geothermal energy represents about 0.4% of total U.S. electricity generation, and most facilities are concentrated around geysers and hot springs in Northern California and Nevada.
The next-generation geothermal projects that are currently in development fall into one of three buckets. Enhanced geothermal systems, like the ones that Sage and Fervo Energy are building, involve fracturing rocks and pumping them full of water to create artificial reservoirs far below the earth’s surface. Superhot geothermal, which scientists are studying in Iceland, aims to tap into extreme resources like magma chambers to extract gargantuan amounts of heat.
XGS’s approach falls into the third bucket: closed-loop systems, which entail placing pipes deep underground and sealing them off so that they operate like radiators. As water circulates within the system, it collects heat from the hot rocks below and brings it to the surface, where the heat produces steam that drives electric turbines.
What sets XGS apart from its closed-loop competitors, such as Canadian startup Eavor, is the “thermally conductive” cement alternative that the company places between the hot rock and pipe system. XGS claims its proprietary material, which includes a naturally occurring mineral, can increase the total amount of heat it pulls from the subsurface by 30% to 50%, allowing the company to use simpler and cheaper well designs to access hotter rocks with existing drilling technologies.
XGS completed its first pilot project in late 2024 with a 100-meter-deep well in central Texas. Earlier this year, the startup began operating a full-scale prototype using an idled well at the Coso geothermal field in the Western Mojave Desert region of California. The well runs more than 1,000 meters deep — a standard depth for commercial geothermal wells — and reaches subsurface temperatures of around 200 degrees Celsius (392 degrees Fahrenheit).
For 3,000 hours, or 125 days, XGS continuously ran its closed-loop system while adjusting key variables, such as the rate at which liquid flows and the amount of heat extracted at the surface. The idea was to simulate how the technology performs in different operating conditions, in order to prove it can withstand various types of stress while also demonstrating the company can accurately predict the system’s performance.
The startup claims the prototype’s actual performance fell within 2% of its predictions, results that XGS later verified with independent engineers, Prueher said. Being able to accurately predict how a project will perform — and for how long — is an essential step for the company to be able to raise the many millions of dollars in debt financing it needs to build its first geothermal power plants, he added.
“This unlocks a huge commercial pipeline that has been accumulating in parallel,” Prueher said of the test results. Along with the 150 MW it’s developing with Meta, the startup has lined up over 3 gigawatts of projects “mostly in the Western United States, where water sensitivity is a huge issue, and where there’s a strong demand signal from data centers and other types of clean energy consumers to build this as quickly as we can.”
XGS has raised $55 million so far from private investors to develop its heat-harvesting technology. One of its biggest backers is VoLo Earth Ventures, which focuses on early-stage climatetech companies.
Joe Goodman, a managing partner for VoLo, said his firm identified XGS “as one of the leading geothermal solutions” about a year and a half ago after reviewing its experimental lab data, and Goodman later joined XGS’s board of directors.
By boosting the system’s overall energy output, XGS’s thermally conductive materials could be the key to making closed-loop geothermal more economically viable, he said, adding that the technology also sidesteps the concerns around water-supply constraints facing enhanced geothermal systems.
“We’re quite optimistic about what we’ve seen,” Goodman said.
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.
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