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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.”
What is A-CAES?
Advanced compressed air energy storage (A-CAES) is a technology that stores energy by compressing air and later releasing it to generate electricity. It is an enhanced form of traditional compressed air energy storage (CAES), which has been in use in California and other parts of the world for decades. Hydrostor’s key advancement is that A-CAES captures and stores the heat generated during the compression phase and uses it to reheat the air during expansion, which significantly improves efficiency while eliminating the use of fossil fuels for daily operations. This patented technology makes it a much more environmentally friendly and cost-effective method for large-scale, long-duration energy storage.
Take a look at how Hydrostor’s Willow Rock Energy Storage Center (WRESC) project in Kern County, California, is contributing to the state’s energy priorities:
From drawing board to full operation: a phased approach
Construction of the Willow Rock project is anticipated to take 60 months from the time the project breaks ground until it goes online. The construction work will take place in six phases:
Preconstruction
Before any physical work can begin on a project of this scale, Hydrostor does substantial preliminary work to ensure there are minimal impacts to the surrounding communities and environment. Preconstruction assessments completed for the Willow Rock Energy Storage Center evaluated potential impacts on air quality, cultural resources, geologic conditions, soil health, water quality, and other factors and included recommendations on how to mitigate those impacts. An extensive permitting process will involve consulting with the local community, state agencies, and federal agencies before construction begins. A-CAES facilities have a smaller physical and environmental footprint than other energy infrastructure, using five to 20 times less water than pumped hydro and more than 10 times less land than solar for an equivalent amount of energy.
Cavern Construction
The first parts of an A-CAES facility to be built are the underground cavern and its associated air, water, and construction shafts. The storage cavern is constructed in bedrock approximately 2,000 to 2,500 feet belowground. This subsurface work is the most time-consuming portion of construction, taking roughly three years.
Topside Construction
Once the subsurface construction is underway, topside construction begins. This phase includes installing turbines, thermal storage tanks, and the rest of the facility’s aboveground equipment in addition to constructing the transmission line.
Transmission
The Willow Rock Energy Storage Center is located near the project’s transmission interconnection point, the SCE Whirlwind Substation, thereby reducing the time, cost, and complexity of building the transmission infrastructure.
Once construction is complete, all project equipment will be rigorously tested for safety and efficiency before Willow Rock officially begins providing reliable power to millions of Californians.
Willow Rock’s 50-Plus Year Commercial Life Span
Once operational, A-CAES facilities like Willow Rock — unlike many other energy storage technologies — will operate with zero efficiency loss over its expected commercial life span of 50 years or more. This means Hydrostor’s work in host communities—and the jobs it creates to operate each facility—are long-term commitments that provide lasting local and regional benefits.
A-CAES projects' flexible siting, energy density, environmental attributes, and community benefits make them an excellent fit for many regions across the U.S. Learn more about Hydrostor's growing project pipeline here.
California has labored for years to build enough clean energy to wean itself off fossil fuels. Now the effort is paying off in an undeniable way.
President Donald Trump’s Department of Energy might tweet that solar plants are “essentially worthless when it is dark outside.” But in California, batteries are proving the opposite, by shifting ever more solar into evening and nighttime hours. Consequently, solar generation hit new highs in the first half of the year, and fossil-gas generation has fallen rapidly in turn.
From January to July, as noted by Reuters, solar generation delivered 39% of the state’s generation, a record level, while fossil fuels provided just 26%, a new low since the dawn of modern gas power. In April, a temperate shoulder month, gas generated less than 20%. For context, across all of last year, solar provided 32% of California’s power — the highest rate of any U.S. state — nearly unseating gas as the largest source of power.
These trends have resulted in numerous clean energy records this summer. In the California Independent System Operator’s grid, which serves most of the state, solar delivered a record 21.7 gigawatts just past noon on July 30. Two days later, at 7:30 p.m., the battery fleet set its own record, nearing 11 gigawatts of instantaneous discharge for the very first time (it has since beat that record).
California’s electricity supply increasingly diverges from the nation’s. Gas has predominated since 2016, and now accounts for more than 40% of U.S. generation; coal, meanwhile, has fallen to around 16%. The carbon-free cohort includes nuclear and renewables at around 20% each. Solar, including rooftop systems, provided about 7% of U.S. electricity last year, according to Ember.
Initially, California’s billions of dollars in solar subsidies and suite of supporting policies couldn’t overcome the state’s gas dependency. The solar systems cranked out excess power through the sunny hours, much of which got curtailed for lack of simultaneous demand, then California turned to fossil fuels to keep the lights on at night. That addiction at times overpowered the state’s environmental ethos: California even opted in 2020 to waive enforcement of a regulation protecting marine life because it would have shuttered a number of coastal gas plants that the grid wasn’t ready to lose, despite having a decade to prepare for the rule.
Such desperation gave temporary succor to solar skeptics and gas boosters. But when an energy system starts to change, snapshots in time are less instructive than the trend lines. And California’s trend lines have been pointing in one direction.
While the state hasn’t been building new gas generation, it has connected gigawatts of new solar and batteries each year. These resources are nearly free to operate once built, while gas plant owners have to buy fuel to combust and keep complex machinery in fine working order. And the price of gas has been going up, amid greater demand both at home (due to data center expansion) and abroad (with liquefied exports going to the highest bidder). Now California’s gas plants have more competition in the peak hours from cheaper, cleaner resources; they’re getting squeezed toward fewer hours of intense demand.
But it would be a mistake to think that these trends stop at the Sierra Nevada. Indeed, these patterns are playing out nationally: Very little new gas capacity is getting built, quite a lot of solar and batteries are, and gas prices are going up.
Some regions allow developers to respond nimbly to these trends, namely Texas, which indeed has leapt ahead of California in its pace of solar and storage installations. Other regions obstruct such dynamism and face the consequences, like the mid-Atlantic wholesale markets run by PJM, where skyrocketing capacity auctions are pushing costs to crisis levels.
California’s grid overhaul has been a long time coming, and one lesson here is that big changes — like redesigning the energy system for the world’s fourth largest economy — take time. But other states won’t have to wait as long: They can tap into a mature supply chain that scaled up thanks to California and other early adopters, plus the industrial expertise to design and manage large solar construction efforts and the financing options de-risked by years of data from earlier projects.
The federal government is trying to stymie renewables however it can. But California is demonstrating the rewards for getting solar to escape velocity, and that momentum is set to carry forward in the coming years.
About 30 miles off the coast of Virginia Beach, Virginia, workers have been building America’s largest offshore wind farm at a breakneck pace. The project will start feeding power to the grid by March — the most definitive start date provided by its developer yet.
“First power will occur in Q1 of next year,” Dominion Energy spokesperson Jeremy Slayton told Canary Media. “And we are still on schedule to complete by late 2026.”
In an August earnings call, Dominion Energy CEO Robert Blue provided a vague window of “early 2026” when asked when the 2.6-gigawatt Coastal Virginia Offshore Wind (CVOW) project would start generating renewable power for the energy-hungry state.
As of the end of September, Dominion had installed all 176 turbine foundations — “a big, important milestone,” per Slayton. That accomplishment involved pile-driving 98 foundations into the soft seabed during the five-month stretch when such work is permitted. Good weather helped the work move along quickly, as did the Atlantic Ocean’s unusually quiet hurricane season.
Speed is key when building wind projects under the eye of a president who has called turbines “ugly” and “terrible for tourism” — and who has followed up with attempts to dismantle the industry.
Had CVOW not finished foundation installation by the end of this month, turbine construction would have been delayed until next spring. Federal permitting restricts pile-driving to a May-through-October window to protect migrating North Atlantic right whales. Such a delay would have made CVOW more vulnerable to the wrath of the Trump administration, which has already issued stop-work orders to two offshore wind farms under construction.
But Slayton said the threat of President Donald Trump’s interference doesn’t concern him. CVOW is, after all, one of only two in-progress offshore wind projects that hasn’t been directly attacked by the president.
“Our project has enjoyed bipartisan support from the beginning,” he said, pointing to backing from some of the state’s leading Republicans, including Gov. Glenn Youngkin and U.S. Rep. Jen Kiggans.
Kiggans, who represents the politically moderate Virginia Beach area, brought her concerns about Trump’s escalating war on wind to the House floor last month, when Congress returned from recess. She called CVOW “important to Virginia,” and House Speaker Mike Johnson (R-Louisiana) later told reporters that he relayed Kiggans’ message directly to Trump.
“I understand the priority for Virginians and we want to do right by them, so we’ll see,” Johnson told Politico’s E&E News, in a comment that broke from an anti–offshore wind narrative that’s taken root among many of his fellow House Republicans.
The project is crucial for helping the state meet a deluge of new electricity demand, as Virginia is at the center of the nationwide boom in data-center construction. CVOW will provide a huge amount of carbon-free power to the state and Dominion, its largest utility — helping both keep pace with rising demand without having to burn more polluting fossil fuels.
Kiggans also tied the success of CVOW to the needs of Virginia’s military installations.
“I always speak about that project in light of the national security benefit and that benefit to Naval Air Station Oceana,” Kiggans said last month in an interview with WAVY, a Virginia news station, noting that a partnership with Dominion is “giving Naval Air Station Oceana a $500 million power grid upgrade.”
Dominion has already spent $6 billion on the monumental effort to build CVOW, which has been 12 years in the making. Almost $1 billion of that investment has flowed to the local economy, creating 802 full- and part-time jobs in the state’s Hampton Roads region, according to G.T. Hollett, Dominion Energy’s director of offshore wind.
CVOW’s benefits are being felt nationwide too.
“The project has already created 2,000 direct and indirect American jobs and generated $2 billion in economic activity, strengthening the nation’s manufacturing supply chains and our regional economy,” said Katharine Kollins, president of Southeastern Wind Coalition.
Now Dominion will turn to the final phase of construction: turbine installation. The work is made possible by Charybdis — the first U.S.-built, Jones Act–compliant wind-turbine installation vessel — which arrived in Virginia’s Portsmouth Marine Terminal last month.
“When Charybdis is loaded up, it will have all the components to install four turbines with each trip,” said Slayton, who noted that the pace of the build is well timed given Virginia’s data-center boom. The state is facing “record growth and energy demand … maybe you’ve heard.”
See more from Canary Media’s “Chart of the week” column.
Renewable energy just notched a major milestone.
Worldwide, renewables produced more electricity than coal across the first half of this year — a first, according to clean-energy think tank Ember.
The global revolution in solar deployment made the milestone possible. The energy source more than doubled its share of global electricity generation over the last four years alone, rising from 3.8% in 2021 to 8.8% in the first half of 2025. Wind power also grew modestly during the first half of the year.
Taken together, the two clean-energy sources increased fast enough to not only meet all new electricity demand in the first six months of 2025, but to displace a bit of fossil fuel use as well.
Despite the progress, coal remains the single largest source of electricity in the world. No renewable-energy source on its own — be it wind, solar, hydro, or bioenergy — measures up to coal. And although renewable energy on the whole has now surpassed coal, it’s not like coal generation is plummeting. Power plants still plowed through more coal in the first half of this year than they did in the first half of 2021.
But coal power is stagnant. Meanwhile, renewables, and solar in particular, are ascendant. This latest milestone is worth celebrating not because fossil fuel use has been dealt a fatal blow, but because it’s a clear illustration of the trajectory each energy source is on.
For the world to truly reorient itself around energy sources that don’t bake the planet and spew toxic fumes into the air, those trends must not only continue but accelerate. Coal — and eventually gas — will need to decline as assuredly as renewables soar. Let’s call this a step in that direction.
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
The specter of additional, deeper federal funding cuts is haunting the clean-energy sector. A Department of Energy list shared this week with Canary Media suggests the agency is thinking about canceling a whopping $23 billion worth of energy projects.
Well, maybe.
Here’s what we know for sure: Last week, the DOE terminated $7.56 billion in federal funding for grid upgrades and energy projects, which were largely set to benefit Democratic-voting states. Right after, Energy Secretary Chris Wright called the announcement a “partial list” and promised that more cuts were coming — in both blue states and red ones.
From there, it gets fuzzier.
On Tuesday, sources shared a leaked spreadsheet with Canary Media that looks a lot like a follow-up to last week’s hit list. It lists the word “terminate” next to not only the 321 grant cancellations from last week, but hundreds of other projects too.
But despite headlines declaring this a new wave of grant cancellations, the exact nature of the list remains murky. A former DOE official who spoke on condition of anonymity told Canary Media’s Jeff St. John that the list is legitimate and that it represents the grants DOE officials have recommended for cancellation to the White House.
DOE, meanwhile, hasn’t confirmed the list’s authenticity and denies that it has yet decided to cancel any of the projects that appear only on the second list. In a statement, the DOE said it is still conducting an “individualized and thorough review of financial awards made by the previous administration,” and that “no determinations have been made other than what has been previously announced.”
Recipients who appeared only on the second list also say they haven’t heard that their grants will be canceled.
Vikrum Aiyer, global policy head at carbon-capture startup Heirloom, whose major direct-air capture project was included on the second list, told Canary Media’s Maria Gallucci that the company wasn’t “aware of a decision from DOE” to cancel its federal award.
Alliant Energy, a utility holding company whose Wisconsin Power and Light subsidiary was listed on the new spreadsheet, said in a statement that it has not been made aware of changes to its DOE grants.
And aside from the two blue-state hydrogen hubs whose funding was cut last week, several of the firms working on the other five hubs have yet to receive cancellation notices, Alexander C. Kaufman reports.
At best, the latest leaked list is just another layer of chaos and uncertainty for federal funding recipients, who are stuck trying to get answers about the status of their projects from a department that has been depleted by layoffs. At worst, though, it’s a harbinger of billions more in cuts to come for innovative American energy projects.
— Jeff St. John, Kari Lydersen, and Alexander C. Kaufman contributed reporting.
State and federal hurdles pile up for community solar
Community solar is in trouble, and it’s not just because of federal shakeups, Canary Media’s Alison F. Takemura reports. These shared arrays help make solar power accessible to those who can’t put panels on their own roofs, whether that’s because they rent, can’t afford them, or face other barriers. That power can in turn help households reduce their bills.
But the One Big Beautiful Bill Act signed in July set an early sunset for tax credits that can cover as much as half of a community solar array’s cost. And states are also contributing to the decline. Developers in New York, a major community solar market, are facing higher costs for land and permitting, while in Maine, developers have to reckon with changes to its solar net-metering program, as well as lowered compensation and new fees for community solar projects.
Those state challenges, combined with the looming threat of more federal funding cuts, have all led Wood Mackenzie to reduce its forecast of new community solar installations by 8% through 2030.
Global clean energy keeps growing
Two new reports contain some good news for clean energy around the globe. For starters, solar and wind installations outpaced global power demand growth in the first half of this year, according to an analysis out this week from think tank Ember. And in a first, renewables also generated more power than coal over the same period.
The International Energy Agency meanwhile predicts renewables’ global expansion will continue. Renewable power installations will more than double by 2030, it forecasts, with solar accounting for 80% of that new generation. That’s some fast growth, but it’s still well short of the tripling the agency has called for to mitigate the worst effects of climate change.
Clean power down under: Australia’s grid operator says replacing its coal-dominated system with 100% renewables is not just a climate-conscious choice, but the lowest-cost choice as well. (Canary Media)
Actual good news for wind: Dominion Energy’s Virginia offshore wind project is on track to start delivering power by March 2026, and is set to be the country’s biggest by far when it’s completed at the end of 2026. (Canary Media)
Tesla’s new price point: Tesla announces a cheaper version of its Model Y SUV and its Model 3 sedan, both with base models starting below $40,000. (CNBC)
Fighting for solar: A labor union, solar installation companies, nonprofits, and other groups sue the Trump administration over its rollback of the $7 billion Solar for All program. (Associated Press)
Coal’s collapse: A low bid for a federal coal lease and the early shutdown of New England’s last coal power plant showcase how the fuel’s economic case continues to shrink even as the Trump administration tries to prop the industry up. (Associated Press, Canary Media)
A windfall for storage: Battery storage startup Base Power raises $1 billion to expand its mission of building home battery systems that it leases to households and uses as a grid resource. (Canary Media)
Weatherization works: Efficiency programs in New England and New York are set to save residents tens of billions of dollars, even as states face pressure to cut spending on such efforts in the name of short-term bill savings, a new report concludes. (Utility Dive)
A correction was made on Oct. 10, 2025: Heirloom has a direct-air carbon capture project, not a hydrogen-hub project.
In July, China launched the world’s largest green hydrogen plant. One month later, India’s government backed 19 projects designed to make the country a leader in producing green hydrogen, which could help decarbonize everything from steel to shipping. Saudi Arabia and the United Arab Emirates are pumping billions of dollars into infrastructure to produce and export the fuel over the next few years.
The United States, meanwhile, is yanking funding for some of its most ambitious clean-hydrogen projects.
Last week, as part of a list of 321 grants revoked in the name of saving $7.5 billion in spending, the Department of Energy rescinded $2.2 billion in awards to two of the seven hydrogen regional hubs established under the bipartisan Infrastructure Investment and Jobs Act. Unlike the five other hubs, the law designed the terminated projects, in California and the Pacific Northwest, to focus exclusively on hydrogen made with renewable electricity, making them an easy target as the Trump administration slashes Biden-era clean energy projects.
Now this week a second Energy Department list shared with Canary Media indicates the agency is considering whether to pull funding from all seven hydrogen hubs, including those in Texas, Appalachia, and the mid-Atlantic and two in the Midwest.
It’s not certain whether the entire $24 billion worth of awards on the new list will be eliminated. Companies whose projects appeared only on the second list, including utilities and carbon removal firms, have yet to receive notice of cancellation. While federal officials gave companies involved in the West Coast hubs a warning before announcing the cuts last week, three separate producers involved in the other five hubs had not heard from the administration as of Thursday, according to California Hydrogen Business Council CEO Katrina Fritz, who checked in with the sources.
But already, the potential cuts are sowing doubt within the emerging sector — and in the clean energy space more broadly.
“Any amount of uncertainty in funding is really detrimental to private-sector investment, and that’s just not a good way to spur innovation domestically and compete on a global stage,” said Rachel Starr, the senior U.S. policy manager for the hydrogen program at the Clean Air Task Force. “Plenty of other countries are investing in this. We’re going to lose our competitive edge if we stop.”
“Yeah, I’m worried”
It remains unclear whether the document outlining a fuller list of cuts, which a lobbyist told E&E News was weeks old, represents an expansion of the previous cuts or a maximalist proposal from which the earlier terminations were whittled down.
In a statement, the Energy Department said it was “unable to verify” the list but that the agency “continues to conduct an individualized and thorough review of financial awards made by the previous administration.”
A former Energy Department official with direct knowledge confirmed that the list is legitimate and said that it represents the grants DOE officials have recommended for cancellation to the White House. The official suggested that the agency is obfuscating its plans to pull the grants to regional hubs in red states until after a federal budget is passed, an effort to prevent congressional Republicans from adding an amendment that preserves the funding into the budget.
“They can’t do that in the middle of a government shutdown,” the official, who spoke on condition of anonymity, told Canary Media. “I do expect them to cancel these funds … [but] not until there’s a full-year appropriations [bill].”
Already, key Republican lawmakers have expressed concern.
“Yeah, I’m worried,” Senate Environment and Public Works Committee Chair Shelley Moore Capito told E&E News when asked about the possibility of losing funding for West Virginia’s hydrogen hub. “It’s a big deal for us.”
The uncertainty only adds to the challenges facing the hydrogen industry.
The Biden administration created a two-pronged hydrogen strategy via the bipartisan infrastructure law and the Inflation Reduction Act. The IRA’s tax credit for clean hydrogen production, known as 45V, was meant to help spur supply of the fuel. The policy survived the rollbacks in the One Big Beautiful Bill Act that Trump signed in July, but Republicans shortened the timeline for the write-offs from 10 years to two.
The hydrogen hubs, meanwhile, were meant to coordinate producers and offtakers to create regional ecosystems that could someday be interconnected with pipelines and other infrastructure. Even before the cuts, however, the hubs were struggling to generate enough demand.
“Low demand explains why the West Coast hydrogen ambitions have never amounted to much,” Martin Tengler, the analyst who heads the hydrogen research team at the consultancy BloombergNEF, wrote in a memo to investors Monday. “Low demand stems from a lack of incentives such as the quotas or carbon prices that are present in Europe, combined with a focus on sectors where hydrogen use is highly uneconomical.”
As a result, he argued, the decision to slash funding for those two hubs “has little direct impact on the pipeline of projects BloombergNEF has expected to come online by 2030.”
Of the six commercial green hydrogen projects larger than 1 megawatt that the consultancy tracked in its latest outlook report, four have reached a final investment decision and just one is operational. “All five are very small,” the investor note stated.
In an email to Canary Media, Tengler said the impact of eliminating funding for all the hubs “would be negative, but the most important things are the tax credits.”
Back to the States
The hubs won’t necessarily fall apart without the federal grants.
California’s regional hub, known as the Alliance for Renewable Clean Hydrogen Energy Systems, or ARCHES, plans to continue without the financing and could turn to state funds to make up the difference. The Golden State’s newly overhauled cap-and-invest program is one potential source. The state Clean Truck and Bus Vouchers program, known as HVIP, and the California Energy Commission’s Clean Transportation Program Investment Plans could bolster offtakers.
“California has been a hydrogen hub for many years, and it’s getting bigger and bigger,” Fritz said. “It’s already in application. There are people riding on hydrogen fuel-cell buses every day in California.”
Roxana Bekemohammadi, executive director of the U.S. Hydrogen Alliance, said it’s possible that Congress could extend the 45V tax credit before it expires at the end of 2027. But in the meantime, she said, “state-level hydrogen incentives are the most stable path forward.”
Whether states can deliver a green hydrogen industry at scale, however, remains to be seen — and removing billions in federal funding certainly doesn’t make the task easier.
“The cuts to these hubs seem shortsighted and ultimately will result in the loss of jobs in our country,” said Carrie Schoeneberger, an industrial analyst who covers hydrogen for the Natural Resources Defense Council. “This will put the U.S. a step back and threaten U.S. leadership, which is against the stated aims of the current administration for American energy dominance.
Jeff St. John contributed reporting.
The first wind farm slated to plug into New York City’s grid has already endured one political catastrophe this year. Now, a logistical crisis looms on the horizon.
Equinor’s Empire Wind is a 810-megawatt project being built about 20 miles off the shore of Long Island, promising enough energy to power 500,000 homes once completed in 2027. The Trump administration halted construction in April, but allowed it to resume in May. The latest challenge came on Thursday with the unexpected cancellation of a contract for the massive new wind-turbine installation vessel that Equinor had been planning to use on the project next year.
Two shipbuilding companies broke out into a public skirmish — one unexpectedly cancelling a contract and the other threatening legal action — over the construction of the specialized ship. The fate of the vessel, which is already more than 98% complete and floating in Singapore’s waters, is now uncertain.
The cancelled $475 million agreement leaves Equinor scrambling to figure out how to maintain progress and bring Empire Wind online on schedule.
“We have been informed by Maersk of an issue concerning its contract with Seatrium related to the wind turbine installation vessel originally contracted by Empire Offshore Wind LLC for use in 2026,” said an Equinor spokesperson via email. “We are currently assessing the implications of this issue and evaluating available options.”
Only a handful of vessels in the world are capable of lifting, carrying, and piecing together the massive steel components of offshore turbines.
Thursday’s news highlights the complexity of bringing just one U.S. offshore wind farm over the finish line, given the combination of logistical difficulties and political obstacles put up by the Trump administration.
In an email to Canary Media, a Maersk Offshore Wind spokesperson confirmed that the company terminated its building contract with Seatrium “due to delays and related construction issues.” The spokesperson declined to comment further.
Seatrium told Reuters it was evaluating its options for the vessel, including via ongoing talks with Empire Wind, and considering legal action.
Singapore-based Seatrium is fresh off the monumental achievement of berthing a first-of-its-kind offshore-wind installation vessel in U.S. waters. In September, the company delivered the $715 million Charybdis from its Brownsville, Texas, shipyard to the Portsmouth Marine Terminal in Virginia. The American-made vessel is owned by utility Dominion Energy, which immediately put it to work building the largest offshore wind farm in the U.S. The ship’s smooth delivery is a major reason why the Coastal Virginia Offshore Wind farm is progressing fast enough to have a new March 2026 launch date.
The ship’s hull is 472 feet long and 184 feet wide, making it one of the biggest vessels of its kind in the world. And, more importantly, it was built to serve the entire U.S. sector — not just Dominion Energy’s project. In other words, the Charybdis could be a solution to Equinor’s new problem.
“Upon the completion of its charter with [Coastal Virginia Offshore Wind], the versatile Charybdis will be available to support a variety of projects, including offshore wind and other critical heavy lift shoreline projects, such as salvage operations or other energy projects,” said Jeremy Slayton, a Dominion Energy representative, in an email to Canary Media.
An Equinor spokesperson provided no comment about Charybdis but reiterated that the company is exploring all options. Having survived the recent political storm, the company is well positioned to navigate these latest headwinds.
London, 7 October 2025 – Solar and wind outpaced the growth in global electricity demand in the first half of 2025, resulting in a very small decline in both coal and gas, compared to the same period last year. New analysis from Ember shows that record solar growth and steady wind expansion are reshaping the global power mix, as renewables overtake coal for the first time on record.
“We are seeing the first signs of a crucial turning point,” said Małgorzata Wiatros-Motyka, Senior Electricity Analyst at Ember. “Solar and wind are now growing fast enough to meet the world’s growing appetite for electricity. This marks the beginning of a shift where clean power is keeping pace with demand growth.”
Global electricity demand rose 2.6% in the first half of 2025, adding 369 TWh compared to the same period last year. Solar alone met 83% of the rise, thanks to record generation growth in absolute terms (306 TWh, +31% year-on-year).
Solar and wind grew quickly enough to meet rising demand and start to replace fossil generation. Coal fell by 0.6% (-31 TWh) and gas by 0.2% (-6 TWh), only partly offset by a small rise in other fossil generation, for a total decline of 0.3% (-27 TWh). As a result, global power sector emissions fell by 0.2%.
For the first time ever on record, renewables generated more power than coal. Renewables supplied 5,072 TWh of global electricity, up from 4,709 TWh in the same period in 2024, overtaking coal at 4,896 TWh, down 31 TWh year-on-year.
The 0.3% (-27 TWh) drop in fossil fuel generation was modest but significant, indicating that wind and solar generation are growing quickly enough that in some circumstances they can now meet total demand growth. As their exponential rise continues, they are likely to outstrip demand growth for longer and longer periods, cementing the decline of fossil generation.
The world’s four largest economies – China, India, the EU and the US – continued to shape the global outcome.
China and India both saw fossil generation fall in the first half of 2025 as clean power growth outpaced demand. China remained the leader in clean energy growth, adding more solar and wind than the rest of the world combined, helping to cut China’s fossil generation by 2% (-58.7 TWh) in the first half of 2025.
In the same period in India, growth in clean sources was more than three times bigger than demand growth. However, demand was exceptionally low at 1.3% (+12 TWh), compared to the same period last year at 9% (+75 TWh).
India’s record solar and wind expansion, combined with lower demand, drove down fossil fuels in the country, with coal falling 3.1% (-22 TWh) and gas 34% (-7.1 TWh).
By contrast, fossil generation rose in the US and the EU. In the US, demand growth outpaced clean power, driving up fossil generation. In the EU, weaker wind and hydro output led to higher gas and coal generation.
With half the world already past the peak of fossil generation, Ember finds clean power can keep pace with rising electricity demand, but progress is uneven. In most economies, faster deployment of solar, wind and batteries could bring benefits.
This analysis confirms what we are witnessing on the ground: solar and wind are no longer marginal technologies—they are driving the global power system forward. The fact that renewables have overtaken coal for the first time marks a historic shift. But to lock in this progress, governments and industry must accelerate investment in solar, wind, and battery storage, ensuring that clean, affordable, and reliable electricity reaches communities everywhere.
-- Sonia Dunlop
CEO, Global Solar Council
We are seeing the first signs of a crucial turning point. Solar and wind are now growing fast enough to meet the world’s growing appetite for electricity. This marks the beginning of a shift where clean power is keeping pace with demand growth. As costs of technologies continue to fall, now is the perfect moment to embrace the economic, social and health benefits that come with increased solar, wind and batteries. As costs of technologies continue to fall, now is the perfect moment to embrace the economic, social and health benefits that come with increased solar, wind and batteries.
-- Malgorzata Wiatros-Motyka
Senior Electricity Analyst, Ember
California lawmakers managed to pass a slate of bills aimed at controlling the state’s high and rising electricity costs in the final days of the legislative session this month. But the last-minute negotiations left one key money-saving measure on the cutting-room floor — continued funding for what might be the world’s largest virtual power plant.
Now, companies like Sunrun and Tesla that have enrolled tens of thousands of customers in that VPP program don’t know if they can pay them to participate next year, because it’s unclear if any other state funding can be cobbled together. If not, they’ll have to put those customers on hold — and California could lose hundreds of megawatts of cost-effective grid relief.
Lawmakers “are consistently undervaluing what distributed solar and storage can deliver for the system,” said Kate Unger, senior policy advisor for the California Solar and Storage Association, a trade group that supports the program. “We find this to be very shortsighted and frustrating, because DSGS is a cost-saving measure.”
DSGS stands for the Demand Side Grid Support program, which pays utility customers to help relieve costly peaks in electricity demand during extreme events like heat waves. They do this by cutting their own power consumption with devices like smart thermostats or by feeding extra power to the grid from backup batteries that have been charged by rooftop solar. Customers have already installed and paid for those systems, so making use of them is cheaper than building new power plants or grid infrastructure to manage those peaks.
DSGS has grown quickly since its 2022 launch to more than 1 gigawatt of grid-relief capacity, Unger said, about 700 megawatts of that from batteries in homes and businesses, which can be deployed rapidly. That’s much bigger than other similar programs in the state.
Backers say that’s because DSGS, which is administered by the California Energy Commission, is far less onerous for participants than VPP programs run by the state’s utilities.
It’s also more cost-effective, according to an August analysis from consultancy The Brattle Group. That report, which was commissioned by Sunrun and Tesla, found that solar-charged batteries in DSGS could deliver between tens of millions and hundreds of millions of dollars in net savings to all California utility customers over the next four years. Those projected savings are predicated on the program nearly doubling its current capacity, which is a credible goal given that California residents are adding backup batteries in increasing numbers.
But instead of expanding its funding to achieve that growth, state lawmakers cut it this year in the face of budget shortfalls, just like they did last year. A provision that lawmakers inserted in August into a bill reauthorizing the state’s greenhouse-gas cap-and-trade program would have provided DSGS with a stable funding stream into the middle of next decade, but it was stripped from the bill that emerged from closed-door negotiations between Gov. Gavin Newsom (D) and legislative leaders days before it was passed. That leaves DSGS with a dwindling pool of previously committed funding that is very likely to be depleted this year.
The remaining budget currently stands at about $64 million, according to the program administrator. DSGS would need at least $75 million more to continue operating in 2026, according to a letter sent to California lawmakers in August by dozens of companies, trade groups, and advocacy organizations.
DSGS backers are hoping the program might be able to secure a slice of the $1 billion in reserves to be disbursed annually from the state’s newly reauthorized cap-and-trade program. But Unger warned that competition for that money will be fierce — and lawmakers won’t make decisions on that spending until next year.
Without new funding, companies that have been active in DSGS will likely have to tell their customers they won’t be able to participate in 2026, said Brad Heavner, executive director of the California Solar and Storage Association. “How do you put your customers in a program if you don’t know they’ll get paid?”
The failure to fund DSGS is particularly frustrating, Heavner said, because it’s the rare example of a successful virtual-power-plant program in the state. Though California has ostensibly prioritized VPPs, it has little else to show for its efforts.
For more than a decade, the state has required its major utilities to incorporate rooftop solar systems, backup batteries, smart thermostats, and other distributed energy resources (DERs) into their grid operations and planning. But utilities have done very little to actually tap these devices beyond launching pilot projects (and terminating many of them), even as the number of DERs in the state has grown dramatically. A June progress report from the California Energy Commission found the state has barely expanded its demand-side capacity over the past two years, and remains far from hitting its goal of 7 gigawatts by 2030.
“California is really excellent at deploying DERs, but really lags in DER utilization,” said Gabriela Olmedo, regulatory affairs specialist at EnergyHub, a company that manages demand-side resources and virtual power plants in the U.S. and Canada. Many of those programs have grown to play a significant role in reducing stress on utility grids during peak demand, she said, including a large-scale initiative in neighboring Arizona. But California’s “fractured, overlapping, and confusing load-flexibility programs really preclude scale,” she said.
DSGS, one of many programs created in response to California’s grid emergencies in 2020 and 2022, has broken that pattern, said Ben Hertz-Shargel, global head of grid-edge research for analytics firm Wood Mackenzie and lead author of a recently released report on virtual power plants. In particular, DSGS has avoided the types of problems that have limited customer participation in other VPP programs, he said.
First, under DSGS, customers can be paid for sending power to the grid from their home batteries that have been charged up by rooftop solar, he said. Most other VPPs in California only allow homes to reduce their consumption from the grid to zero, not to send power back to the grid. That’s a legacy of these programs’ genesis as traditional demand-response offerings that reward customers for reducing power use.
DSGS is also superior to the Emergency Load Reduction Program (ELRP), the other large-scale VPP program created as a response to California’s grid emergencies, Heavner said. One of the biggest differences is that ELRP is triggered only during specified grid alerts, warnings, or emergency declarations by the California Independent System Operator, which manages the state’s energy markets. Those emergencies are relatively rare, so participants are idle most of the time.
DSGS, by contrast, is triggered whenever wholesale prices on the state’s transmission grid exceed a threshold of $200 per megawatt-hour, so it plays a more active role in suppressing the price spikes that drive up costs for utilities and customers, Heavner said.
DSGS is also open to customers of all utilities in the state, unlike ELRP and most of the state’s other VPP programs, which are managed separately by each of California’s three large investor-owned utilities. Companies that have participated in both sets of programs say it’s easier to sign up customers and get them paid promptly under DSGS than under utility-managed efforts.
A set of laws passed this year instructs state regulators to develop new VPP plans and programs, which could augment the current limited options. But “it will take years to establish that,” Heavner said. Meanwhile, “companies that have invested in dynamic grid response are left holding the bag right now.”
California may miss out on big money-saving opportunities as a result, he said. A 2024 analysis from The Brattle Group found that VPPs could shave more than 15% of the state’s peak demand by 2035, saving utility customers about $550 million each year.
The loss of funding for DSGS is particularly galling given the scale it has achieved, Heavner said. In a July test of the DSGS and ELRP programs, California’s three major utilities were able to dispatch about 540 megawatts of power from Sunrun and Tesla batteries, in what utility Pacific Gas & Electric described as “the largest test of its kind ever done in California — and maybe the world.”
Most of those batteries were enrolled in the DSGS program. Sunrun batteries alone accounted for at least 360 megawatts of capacity. As Sunrun CEO Mary Powell pointed out in a LinkedIn post, that’s more capacity than many of the state’s fossil-gas power plants provide.
Sunrun had enrolled more than 56,000 customers with solar-battery systems to participate in California VPP programs as of May, the majority of them in DSGS. The company offered participants up to $150 per battery enrolled in the 2025 season.
“We are concerned that California is walking away from its leadership position running the largest and most successful distributed power plant in the country,” Lauren Nevitt, Sunrun’s senior public policy director, told Canary Media.
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