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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.
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.”
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.
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