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Maine is sprinting to build clean energy projects before federal tax credits expire.
State utility regulators are fast-tracking plans to procure nearly 1,600 gigawatt-hours of renewable energy, with the goal of getting projects started before key incentives disappear under the budget law signed by President Donald Trump this month. Developers were given just two weeks to submit proposals, with a deadline of July 25.
These projects should help the state make up for clean-energy developments derailed by the pandemic, and ultimately progress toward its newly mandated target of 100% clean energy by 2040.
“This is an opportunity to get some things done that Maine had every intention of getting done a handful of years ago,” said Eliza Donoghue, executive director of the Maine Renewable Energy Association, a nonprofit industry group. “It’s good news.”
The move comes as the clean-energy industry pushes other states, including New York and California, to help speed up wind and solar deployments before subsidies expire in the coming years.
For its part, Maine is looking for enough bids to meet roughly 13% of its annual electricity usage. Preference will be given to developments that make use of property contaminated by toxic PFAS, following the discovery in recent years that at least 60 Maine farms have unsafe levels of these “forever chemicals” in their soil and water.
This specification is a win for renewable energy, wildlife, and farmers whose land has been rendered unusable for agriculture, said Francesca Gundrum, director of advocacy for Maine Audubon.
“This work to help deploy solar and other renewable technologies is exactly the kind of siting we need to see more of in Maine,” she said. “Whatever we can do to minimize the turnover of habitat is something we’re going to be supportive of.”
The current procurement has its roots in a bill the Maine Legislature passed in 2023, calling for the state to source renewable energy from installations sited on PFAS-contaminated land. A request for proposals was issued in August 2024, but none of the initial bids were deemed cost-effective, and none were selected. This year, the Legislature went back to the drawing board, tweaking details about how solar and storage projects can enter proposals.
The amended bill was enacted in June with an “emergency preamble,” allowing it to become law immediately, rather than waiting the typical 90 days after the legislative session adjourns. That move required the approval of at least two-thirds of lawmakers in both the state Senate and House, which is an encouraging sign of support for renewables across political divides, said Dan Burgess, director of the Maine Governor’s Energy Office.
“It’s really exciting that a bipartisan coalition of legislators sees this as an opportunity to bring on low-cost clean energy in Maine,” he said.
Previous renewable energy procurements in 2020 and 2021 chose 24 wind and solar developments to buy power from. Many of these projects, however, fell apart when the COVID-19 pandemic disrupted global supply chains and drove up inflation, Burgess said. This latest solicitation is a great opportunity to make up some of that lost ground, he said.
Maine was an assertive early adopter of the “renewable portfolio standard,” a state-level regulation that requires utilities to obtain a certain percentage of their power supply from renewable resources. When Maine adopted the policy in 1999, it required 30% of the electricity sold to be renewable (a number it hit immediately because of the high concentration of hydropower in the state). The total requirement increases over the years; the state is now aiming for 90% renewables by 2040 with the final 10% coming from non-emitting but not necessarily renewable sources, like nuclear.
Today, about 32% of Maine’s electricity comes from gas-fired power plants, and another 31% from hydropower. Solar and wind together contribute roughly one-quarter of the supply.
Studies suggest that Maine’s commitment to renewable energy has already saved residents significant sums and stands to create even more financial benefits. A 2024 report on the impact of the renewable portfolio standard found that utility customers saved a total of about $21.5 million each year from 2011 to 2022. An analysis released in January concluded that reaching 100% clean energy by 2040 would save the average Maine household around $1,300 per year.
The current procurement is to be the last under the existing regulatory structure, in which the state Public Utilities Commission is the body that runs such solicitations. Legislation signed this month will create a cabinet-level energy department — currently Maine has only an energy office — with the authority to run regular procurements as needed to advance the state’s renewable energy goals.
“Instead of doing these one-off procurements specifically directed by the Legislature, we’re now getting to have that predictability,” Donoghue said.
Southern California’s grid needed help in the fall of 2016. The region was still reeling from the calamitous Aliso Canyon gas leak, and its power plants faced a potential shortfall of that fuel to meet air-conditioning demand when the next summer rolled around. The state took a chance on a new grid technology, lithium-ion batteries, to fill in the gaps.
Big names like Tesla and AES stepped in to help, installing storage at record speed, but so did a little-known firm called Powin. Joseph Lu had founded the Oregon-based company years earlier to import consumer products from China and Taiwan. Sensing a new business opportunity, Powin won a bid and installed 2 megawatts of batteries in a warehouse it owned in Orange County.
This proved to be a launchpad for the firm, which rose to the upper echelons of the booming U.S. battery industry before crashing down to earth last month.
After that Orange County installation, Powin refocused on importing battery cells from China and integrating them into grid storage systems, fully packaged with inverters, controls, and safety systems. Powin went on to deliver battery enclosures for many pathbreaking projects: It supplied the first utility-scale battery in Mexico, a landmark utility-endorsed battery fleet in Arizona, and a truly mammoth system in Australia, to name just a few of Powin’s self-reported 11.3 gigawatt-hours of installed systems. It raised some major outside equity rounds to keep growing and last fall obtained a $200 million debt facility from investment giant KKR.
And then in June, Powin filed for bankruptcy, alerting the state of Oregon of mass layoffs at its Tualatin campus, outside Portland. The news jolted the storage industry, since so many major grid storage plants run on Powin’s hardware and software. The bankruptcy proceedings are ongoing, but storage software specialist FlexGen has placed a bid to buy Powin’s assets at auction in early August, offering Powin customers a way to keep their batteries running.
Cleantech bankruptcies have flourished under the second Trump presidency, and the storage sector is uniquely exposed. The industry runs almost entirely on imported battery cells from China, making it vulnerable to rapidly shifting trade policies. The Biden administration raised tariffs on Chinese batteries, and President Donald Trump cranked the overall rate on Chinese imports as high as 145% in April, though he has altered the rate repeatedly in the opening months of his presidency. Trump’s budget law preserved tax credits for installing grid batteries but added a new bureaucratic regime to regulate the amount of China-derived equipment in those storage plants.
“The business model of integrating batteries into a full storage system is one of these classic high-volume, low-margin businesses,” said Pavel Molchanov, a Raymond James analyst covering cleantech companies. “Margins were low even before Trump and these new tariffs on China, and now it’s a safe bet that their margins have been squeezed even further.”
Nonetheless, Powin’s collapse stands out for the scale of the company’s reach — and raises serious questions. Is Trumpian chaos enough to unseat a leading battery supplier, even as the market for grid batteries continues to surge? Or did Powin’s leadership make choices that ultimately led to its early demise? And perhaps more important, what’s going to happen to those 11.3 gigawatt-hours Powin installed before it went bankrupt?
Powin got to the big leagues by spotting technological trends before they hit the energy-storage mainstream.
That started with the rapid-fire California installations in 2016, when hardly anyone was building large-scale storage. At the time, American developers looked to a handful of Tier 1 battery suppliers, like LG, Samsung, and Panasonic. Powin instead scoured China for manufacturers that American buyers hadn’t discovered yet but that could match key quality metrics. Powin signed an early supply deal with a firm called Contemporary Amperex Technology Co., or CATL, which has since become far better known in the West as the world’s largest battery maker.
Powin also focused on the then-lesser-known lithium ferrous phosphate (LFP) chemistry, which executives hailed as safer and longer-lasting than the mainstream nickel-based chemistries handed down from the electric vehicle supply chain. Powin imported these LFP cells from trusted vendors in China, installed them in engineered metal cabinets in Tualatin, then delivered them to project sites across the U.S. and, later, the world.
By the 2020s, U.S. storage installations were growing at a shocking rate. To keep pace with soaring demand, Powin raised $100 million in February 2021 from investors Trilantic Capital Partners and Energy Impact Partners, followed by $135 million in 2022, led by Singapore’s sovereign wealth fund GIC.
The firm’s first major public setback came when a Powin-supplied battery system in Warwick, New York, burst into flames after a summer storm in 2023. Days later, authorities responded to fumes emerging from another Powin-supplied system in that town.
Developer Convergent Energy and Power owned both systems, and its investigation concluded that a manufacturing flaw in that generation of Powin’s Centipede battery container let water leak in and start electrical fires. Those incidents prompted the Warwick Village Board to freeze local battery development, and they undercut Powin’s reputation for safety, which the company previously had promoted after other companies’ battery fires elsewhere in the country. A spokesperson for Convergent did not respond to requests for comment.
It’s unclear what kind of financial impact the fallout from those fires had on Powin, but the firm subsequently found itself locked in a legal dispute with none other than its longtime supplier, CATL. That company sued Powin in Oregon Circuit Court in December 2024 for $44 million in allegedly unpaid bills, following an earlier arbitration on the matter in Hong Kong.
The circuit court noted in February that Powin “does not deny that they owe money to CATL” and that “it is apparent to the court that the amount of money Powin owes to CATL exceeds the value of the assets Powin holds in Oregon.” That’s not a great sign for a company’s metabolism.
In a subsequent filing, Powin’s lawyers asserted that, actually, CATL was refusing to honor the contracts and instead tried to spring non-contracted price hikes at the last minute: “CATL effectively held Powin hostage to choosing between negotiating a solution with CATL or breaching contracts with its customers.”
In the same suit, the Powin lawyers proposed a nefarious explanation for the souring relationship with CATL, one that sheds light on a broader challenge Powin faced in the maturing storage market.
“Powin finds it highly suspect that the timing of this filing for pre-judgment remedies comes as CATL is aiming to compete directly with Powin to supply complete energy storage systems, moving beyond its historical business model of supplying subcomponents to Powin and others like Powin.”
Powin championed CATL’s battery cells to the U.S. market when buyers still had hang-ups about sourcing high-quality batteries from China. But CATL, recently valued at more than $180 billion, did indeed move beyond simply shipping cells and began competing directly with Powin. CATL launched a containerized storage product in 2023, and in May it rolled out a new 9-megawatt-hour, double-decker grid battery enclosure called TENER Stack.
“The past few months have presented considerable headwinds for system integrators, even without considering company-specific challenges,” said Ravi Manghani, senior director of strategic sourcing at data firm Anza Renewables. “The increasing number of battery [original equipment manufacturers] entering the U.S. market with attractively priced DC blocks and AC solutions has put pressure on the traditional value proposition of system integrators.”
Other sources in the grid storage industry noted that Powin’s quality had suffered in the scale-up, lowering customer interest in its products. The company had always had a smaller balance sheet than competitors like Tesla, Fluence, and Wärtsilä, all of which are publicly traded and worth billions.
Longtime Powin CEO Geoff Brown, who led the company from 2016 through its dynamic growth phase, departed in 2023. He was replaced by Jeff Waters, who touted his leadership at solar panel manufacturer Maxeon during its spin-off from SunPower. Those accolades look less auspicious from today’s standpoint: SunPower went bankrupt last year, and Maxeon’s valuation has tumbled precipitously from its 2023 levels.
Last fall, Powin turned to the credit business at KKR, a private-equity trailblazer famous for record-busting leveraged buyouts like RJR Nabisco in the 1980s and utility TXU in the 2000s.
“The facility will be instrumental in supporting Powin’s working capital needs, driving continued innovation, and further enhancing the company’s financial flexibility as it expands its leadership position in the storage industry,” KKR said in a press release from October announcing the $200 million facility.
It’s a strange thing when a company that just secured ample working capital then runs out of working capital just a few months later. Sources familiar with Powin’s business said the debt package, paradoxically, hastened the company’s demise.
Powin drew on only about $25 million of the available debt, but the deal company leadership accepted was “very ugly” and “poorly structured” for Powin’s purposes, said one former Powin customer granted anonymity to speak on sensitive business matters. Another grid storage veteran, who also spoke on condition of anonymity, likened the situation to a payday loan: “They got upside down, and KKR called it in.”
KKR declined to comment on the specifics of Powin’s debt facility.
Powin wouldn’t be the first cleantech company that failed after getting behind on its debt payments. Major rooftop solar provider Sunnova increasingly turned to corporate debt to raise cash as the market soured, then struggled to find cash for debt payments and fell into bankruptcy in June. Electric bus maker Proterra piled up corporate debt before its bankruptcy filing in 2023. When it’s time to pay the tab, even a promising customer pipeline is no legal tender.
Powin’s financial collapse triggered an existential question for all the storage plants out there running on its hardware and software.
“Everyone’s trying to figure out how to maintain their products and solutions and not have bricked systems,” the former customer said.
Software needs updates, as anyone with an iPhone is repeatedly reminded, and the same goes for the systems that tell huge banks of batteries when to charge and discharge. Energy market rules change; hardware trips up. If Powin simply ceased to exist, it would jeopardize the reliability of all the critical power plants running on its control systems.
But those anxious battery owners may soon get some relief now that software startup FlexGen became a stalking horse bidder in June, proposing to buy “substantially all” of Powin’s assets for $36 million. It’s also lending money to keep Powin operating in the meantime. There will still be an auction, and other firms could bid more. But if all goes according to plan, this process will conclude by early August.
FlexGen CEO Kelcy Pegler said he had great respect for Powin, and “gratitude for them being an early mover” in the grid storage industry.
“Powin was such a substantial part of the market,” Pegler told Canary Media. “FlexGen’s interest is in making sure the customers have a successful path to continuous operations.”
FlexGen, based in Durham, North Carolina, employs some 120 software engineers to constantly maintain and improve its storage management software, Hybrid OS, Pegler noted; that product works on whatever storage hardware the customer wants to operate. If the bid goes through, FlexGen will first provide Powin customers with a “continuity plan” that keeps systems running as they are, and customers will have the option to sign new long-term service agreements with FlexGen.
Customers will have good reason to switch over to FlexGen’s flagship product, Pegler added: An independent market study by cleantech data firm Orennia found that batteries running on FlexGen software performed better than those running on that of Powin (and other competitors) in the wholesale markets of Texas and California in 2023.
As for the business of buying battery cells and turning them into storage plants, Pegler is happy to leave that to the existing field of storage manufacturers. He plans to stick to software and services.
Powin has let go of much of its staff. The founders will lose their stakes, and the venture capitalists and private-equity investors won’t rake in a multiple on their few hundred million dollars invested. But a sale to FlexGen would protect Powin’s physical legacy: The gigawatt-hours of batteries installed across the world could keep on humming, as the energy storage market careens ever onward.
New Hampshire’s new state budget redirects an estimated $15 million from a dedicated renewable energy fund into the general fund, likely signaling the end of plans to expand a popular pilot supporting municipal solar developments.
While some New England states have moved to strengthen clean energy policy in the face of President Donald Trump’s efforts to quash renewable power development, New Hampshire has taken a different path: The provisions of the latest budget leave just $1 million in the renewable energy fund each year for programs that, in fiscal year 2024, cost more than $5 million to administer.
“This is a big step backward for renewable energy in the state. There’s going to be very little left over,” said Nick Krakoff, senior attorney in New Hampshire for the Conservation Law Foundation. “That means there would be basically nothing left for this municipal program.”
The renewable energy fund, established in 2007, receives money from electric service providers that are unable to meet their obligations to source a certain level of renewable power each year. Most years, the fund takes in anywhere from $2 million to $8 million. The money has traditionally supported a handful of renewable energy incentives, and revenues have generally exceeded spending. At the beginning of fiscal year 2024, the fund had a balance of nearly $15.3 million.
Earlier this year, the state energy department started laying out plans to use some of this money to support solar projects developed by municipal governments. Such developments have both financial and environmental benefits, saving money for towns — and thus taxpayers — while cutting greenhouse gas emissions from electricity generation in a region that relies heavily on natural gas to fuel its power plants.
Still, municipal solar projects can be a hard sell for voters in New Hampshire, a state with a reputation for frugality. The state has no sales tax or income tax, so government operations are funded mainly by hefty property taxes. It is also home to many small towns with constrained budgets. Though solar installations can save a town money, voters are generally reluctant to approve the upfront cost, which could increase their property taxes.
“The reality for New Hampshire residents is that municipal budgets are very, very, very tight, and property taxes keep going up,” said Sarah Brock, director of the nonprofit Clean Energy New Hampshire’s Energy Circuit Rider program, which helps towns develop clean energy and energy efficiency projects. “Every year at town meeting, there’s a pretty substantial reluctance to approve money for just about anything.”
In 2024, the state launched the Municipal Solar Grant Program to help towns overcome those hurdles and install solar panels on municipal property. The pilot program has a specific focus on small or economically disadvantaged towns that would have a harder time funding such projects on their own. The initiative uses $1.6 million in funding that the state received through the federal Bipartisan Infrastructure Law, passed in 2021.
Thirty towns applied for the funding through the pilot; 16 were selected to receive grants between $45,000 and $200,000. Staff with the Energy Circuit Riders program identified perhaps 20 more towns that might also be interested in future funding opportunities.
“We had over 50 towns in our active project pipeline that would want to go after this funding,” Brock said. “We know the demand is there.”
The plan was to follow up with a permanent program paid for by the renewable energy fund. In the spring, the state energy department asked for comments on the proposed program and ideas about how to modify the approach used in the pilot.
The annexation of the renewable energy fund, however, could put an end to these plans, advocates said. With only $1 million available each year, there would not be enough money available to continue existing offerings like its nonresidential competitive grant program and rebates for wood pellet stoves at current levels. Adding an entirely new initiative may be a nonstarter.
“No one is telling us the program is dead, but it is possible that it will be impossible to run if there isn’t funding for it,” Brock said.
Neither the office of Gov. Kelly Ayotte nor the state energy department responded to requests for comment about the future of the program.
The first project completed under the pilot was a 26-kilowatt solar array atop the town hall in Kensington, New Hampshire, in the southeastern corner of the state and home to about 2,000 people. Kensington has an annual budget of just $2.6 million, so voters were unlikely to approve a nearly $100,000 investment, even if it promised savings in the long run, said Zeke Schmois, chair of the town’s energy committee. So the local solar boosters turned to the state.
The town received about $92,000 for the project. The final panels went up in early July, making Kensington the first place to complete an installation as part of the grant program.
“This isn’t a solar farm, but it’s huge for a town like ours with such a small budget and such a small population,” Schmois said.
Kensington expects the installation to offset about 70% of the town hall’s annual electricity use, Schmois said. But those savings are just the beginning of the impact: The town historical commission was involved with the approval process and realized that modern solar panels can blend inconspicuously with roofing. The group is now eager to collaborate on future solar projects, Schmois said.
Other towns hope for similar benefits. Dublin, New Hampshire, received a grant of about $43,000 for a solar array that should meet all the town fire station’s power needs once it is installed later this summer, said Susan Peters, the chair of Dublin’s select board and founding member of its energy committee. She hopes the installation’s location along a major state highway will help normalize the idea of solar, and help build support for another project under consideration: a ground-mounted array near a capped landfill.
“The fact that we’re doing this project strengthens people’s interest,” she said.
Rooftop solar costs way more in the United States than it does elsewhere in the world. That’s long been a headache for the sector to navigate. But now with Republicans in Congress killing off the decades-old tax credit for rooftop solar, it’s a life-or-death problem.
So says Andrew Birch, a 25-year industry veteran who’s built a career on cutting solar projects’ “soft costs,” which make up roughly two-thirds of the price of a rooftop solar installation in the U.S. and consist of everything other than equipment costs.
Some of those factors are under a solar company’s control, like how much it spends on acquiring customers and managing projects. Others aren’t, like the expense associated with navigating complex permitting and interconnection processes that differ from city to city and from utility to utility.
Those costs rise when solar systems are accompanied by batteries, something that is becoming increasingly common as households look for backup power and respond to new incentive structures that prioritize storage, as is the case in California, the nation’s largest rooftop solar market.
Big upfront costs are the No. 1 reason Americans decide not to put solar panels on their rooftops. The forthcoming spike in installation costs created by the new GOP megabill will only make that hurdle higher. After this year, households will lose access to tax credits for 30% of the cost of solar, batteries, and other home clean-energy equipment, and companies that offer solar systems under third-party ownership models will face a set of uncertain restrictions that could choke off that part of the market.
In order for the U.S. to keep installing rooftop solar at a healthy rate — something that’s key to combatting climate change and helping people manage rising electricity costs and electrify their cars and homes — the industry needs to figure out how to prevent costs from ballooning once the incentives disappear.
“We’re now being forced to operate as an industry without subsidies,” Birch said. That puts the onus on the industry to both tighten its belt in areas that are under its control and press state lawmakers, local government officials, and utility regulators to reform their parts of the equation.
“We can survive and thrive — if we can reduce soft costs,” he said.
Birch, a native Australian known as “Birchy” in the solar world, is working on just that himself.
He helped launch SolarAPP+, an “instant permitting” software platform being used by more than 160 cities and counties across the U.S. to process solar permits in hours rather than weeks. OpenSolar, the company he co-founded and leads, offers free solar project design and management software to installers, paid for by equipment manufacturers and dealers eager for the increased sales it can bring.
There’s plenty of evidence that lowering these costs is possible: The soft-cost problem is a bit of a uniquely American phenomenon. In other places with high rooftop solar penetration, like Australia, the world’s rooftop solar leader, these costs are far lower.
Solar companies in Australia can quote, sell, and install a 7-kilowatt solar system with a 7 kilowatt-hour battery for about $14,000 in a matter of days, Birch estimated. In the U.S., that same system costs about $36,000, and getting permits and interconnections can take months — long enough to kill a fair number of installs before they can be completed, he said.
When it comes to cutting soft costs, local permitting reform is a big target.
Permitting regulations and processes vary widely across the roughly 23,000 city, county, and other local authorities that have jurisdiction over building permits, electrical code enforcement, and other must-haves for a solar or battery installation. Permitting can add roughly $1 per watt to the cost of a typical solar installation, according to the industry trade group Solar Energy Industries Association (SEIA).
Some do a good job of making the process smooth and straightforward. Others can be far less helpful and efficient. Slow or cumbersome permitting takes a toll on solar installers, stretching the time it takes to complete current projects and move on to the next.
“If you can ensure you’re making it through in three weeks versus three months, you’re operating much more efficiently,” said Barry Cinnamon, CEO of Northern California solar and battery installation firm Cinnamon Energy Systems. On the other hand, “in cities where the permitting is slow, you inevitably get them coming back in two weeks saying, ‘You’re missing a dash in that form — send it back,’ and then two or three weeks later saying, ‘We’re not sure the battery can go in that spot. Try again.’”
It’s hard to standardize permitting across local authorities, which range from well-staffed big-city departments to tiny towns with one or two people working on it. But software that can reliably complete the tasks of permitting officials can save time and reduce errors for big and small permitting authorities alike.
In 2018, SEIA and nonprofit the Solar Foundation launched the Solar Automated Permit Processing initiative and enlisted the U.S. National Renewable Energy Laboratory to develop an automated permitting platform. SolarAPP+ was the result. After pilot tests in 2020 proved it dramatically sped up permitting without sacrificing quality, the platform was made available at large.
Automated permitting turns multiple back-and-forth processes into a “one- to two-page digital form,” Birch said. Code standards groups like Underwriters Laboratories and the International Code Council have signed off on SolarAPP+, and similar automated platforms from startups and from city permitting departments are now providing similar same-day options.
The advantages of instant permitting are so great, Cinnamon said, that he’s stopped doing projects in cities and counties that don’t offer some form of it. With less than six months to finish projects that can secure tax credits, “we don’t have the time” to spend elsewhere, he said.
The next step is to expand instant permitting from hundreds to thousands of cities and counties by taking on statewide permitting reforms, said Nick Josefowitz, CEO of Permit Power, a nonprofit advocacy group.
Over the past several years, states including Democratic strongholds like California and Maryland as well as Republican redoubts like Florida and Texas have adopted solar permitting reform laws, he said. New Jersey lawmakers passed a bill this summer that now awaits Gov. Phil Murphy’s signature.
Reform looks different in every state. California set mandates for cities and counties to use instant permitting, while Texas and Florida required cities and counties to allow licensed and credentialed third parties to issue permits and conduct inspections on homeowners’ behalf. Colorado’s law backed off on mandates but offered incentives for local authorities to deploy instant permitting, while New Jersey’s law would empower a state agency to set up instant permitting for cities and counties to use.
Lowering permitting costs can allow solar installers to cut their prices, which increases their business, spurs more competition, and gives households more options, Josefowitz said. A series of studies this year from Brown University’s Climate Solutions Lab and the Greenhouse Institute found that streamlined and instant permitting in Arizona, Colorado, Illinois, Minnesota, New Jersey, New York, and Texas could result in an additional 2 million home solar installations between now and 2030, saving households a collective $100 billion.
The results are good not just for households and solar installers but for cash-strapped municipalities, said Elowyn Corby, mid-Atlantic regional director for nonprofit group Vote Solar, which advocated for New Jersey’s newly passed reform bill.
“When you put the onus on municipalities to process these permit applications, that’s an enormous drain on their resources as well, especially in lower-income communities where there isn’t as much municipal infrastructure,” she said. “We’re hoping this brings capacity back to local governments.”
Permits aren’t the only solar roadblocks. Utilities also need to approve solar and battery systems at homes connected to their grids before they’re allowed to be turned on. Solar installers have long complained that slow or costly interconnection processes are a significant drag on their bottom lines.
“I’ve heard from some of our installers — and some of the bigger ones — that the interconnection approval process is more of a challenge and a bigger cost than the permitting side,” said Ravi Mikkelsen, CEO of Atmos Financial, a financial technology company that connects lenders with solar installers and customers. “Some utilities are better than others, but across the board, this is a major issue.”
Interconnection rules are complicated, and utilities apply them differently. But reports from solar installers over the years have highlighted problems ranging from lengthy waiting times and restrictions on new solar hookups to exorbitant costs assessed on homes wanting to interconnect.
A lack of state regulator oversight for interconnection policies complicates efforts at reform, Josefowitz said.
Regulators in some states like California set rules for all regulated utilities, but other state regulators don’t. Even those that have set statewide guidelines for utilities have been slow to adopt rules that require them to put in place more streamlined processes or take the latest technology advances into account. A 2023 ranking from Vote Solar and the nonprofit Interstate Renewable Energy Council assessed state adoption of interconnection “best practices.” The groups gave only New Mexico an A grade and six other states B grades, while marking 13 with an F for lacking any statewide standards.
“We need [regulator] rules about when projects can be fast-tracked, what types of systems when and where can be automated and approved by software,” Josefowitz said.
Extreme amounts of rooftop solar can cause problems on power grids designed to carry electrons from big substations to customers.
“But batteries totally change the game on this,” he said, enabling homes to store solar power when utility grids don’t need it and release it when they’re in short supply.
That’s why solar companies ranging from nationwide players like Sunrun to regional and local installers are recasting their business approach to include becoming “virtual power plant” providers — active providers of energy and grid resources that help augment the resources that utilities can bring to bear.
Opportunities to earn money for these services are relatively scarce today. But with Republicans in Congress and the Trump administration making it much more expensive and difficult to build more renewable energy to meet the growing demand for electricity, utilities may be well advised to reduce the barriers to installing solar and batteries that can provide it, Mikkelsen pointed out.
“At $2 a watt, you can bring down the cost of your power, and you can save money on electrification,” he said. But also, “your battery can be used economically much more frequently and becomes super-valuable to the grid. You want to unlock the power of batteries? You fill them with cheaper electrons.”
Southern California can keep a landmark rule that’s meant to spur the electrification of certain boilers and water heaters across the smog-choked region.
Late last week, a federal court upheld the first-in-the-nation regulation, which will gradually eliminate emissions of nitrogen oxides (NOx) from more than 1 million fossil-gas appliances in the South Coast Air Quality Management District that covers greater Los Angeles. It applies to light-industrial and commercial boilers, steam generators, and process heaters, as well as residential pool heaters and tankless water heaters.
Opponents of the rule, led by gas-appliance makers and building trade groups, had sued in December to invalidate the standards.
“This decision recognizes our air regulators’ long-established authority to adopt life-saving protections — and sends an undeniable signal to manufacturers and businesses that the future of California’s industrial sector is electric,” Candice Youngblood, an attorney for Earthjustice, which intervened to defend the rule in court, said in a July 21 statement.
The measure is ultimately expected to reduce pollution by 5.6 tons of NOx per day — the same as halving smog-forming emissions from cars in the region.
Advocates say the ruling could help to reenergize efforts around the country to replace fossil-fuel-burning equipment with electric heat pumps and other clean technologies in homes and commercial operations.
Such initiatives have stalled since April 2023, when a different federal court struck down Berkeley, California’s pioneering ban on gas hookups in new buildings. The court said the city’s gas ban was preempted by the federal Energy Policy and Conservation Act and thus wasn’t valid. The groups suing to stop Southern California’s zero-emission boiler rules pointed to Berkeley to claim that the measure also conflicted with the federal energy-efficiency law.
On July 18, the U.S. District Court for the Central District of California found otherwise. The court clarified that the Berkeley ruling is “very narrow” in scope and applies to building codes that concern energy use. The measure in Southern California regulates only appliances’ emissions. Put another way, “It’s about what comes out of the appliance — not what goes in,” explained Nihal Shrinath, a staff attorney for the Sierra Club, which also intervened in the case.
Last week’s court ruling “is a really big deal,” both because it enables significant emissions reductions and it affirms that air-quality measures can withstand such legal challenges, he told Canary Media.
“We think there’s probably been less activity by air districts and local municipalities, in terms of advancing [zero-emission rules], because of the fear of litigation,” he said. The South Coast Air Quality Management District itself recently rejected a plan to curtail pollution from certain residential space and water heaters following an opposition campaign led by utility giant SoCalGas.
The California air district spans large portions of Los Angeles, Orange, Riverside, and San Bernardino counties. More than 17 million people live in the region, where high levels of NOx contribute to some of the worst health-harming smog pollution in the country.
In June 2024, regulators adopted the zero-emission rule for small boilers and large water heaters in homes and businesses as part of its decadeslong mission to meet federal air-quality standards.
Gas-burning appliances covered by the rule account for about 9% of all NOx emissions from stationary sources in the area. They include an estimated 710,000 residential pool heaters and 300,000 tankless water heaters, as well as 60,000 light-industrial and commercial boilers and water heaters at places such as dry cleaners, restaurants, warehouses, and hospitals.
While the measure doesn’t explicitly ban or require any specific technology, the most realistic way for anyone to comply is by replacing their gas-fired appliances with alternatives like ultra-efficient heat pumps or modern electric-resistance boilers.
The limits on NOx emissions are designed to ramp up over time, starting in 2026 for new small units installed in new buildings and extending to new high-temperature units installed in existing facilities in 2033. The drawn-out timeline is meant to allow small businesses and homeowners some flexibility as they phase out their current equipment. It also gives manufacturers of zero-emission technologies enough time to develop and scale up production to meet the new demand.
Critics of the measure, including dry cleaner associations and building contractors, have argued that switching out gas-burning equipment and upgrading buildings’ electrical systems would impose a “significant financial burden.” The air district has estimated that the transitioning to zero-emission equipment will cost companies and households about $49 million to $97 million per year — though the air district will provide rebates to help defray some of those expenses. Industrial heat pumps can also deliver lower operating costs than gas boilers because the electric tech is much more energy-efficient.
Regulators and environmental groups maintain that such rules are necessary both to improve public health within the district and to accelerate the market nationwide for emissions-free industrial equipment. Last week’s court ruling ensures such efforts can continue.
The Trump administration just dealt a blow to the biggest transmission line project currently underway in the United States.
The U.S. Department of Energy has canceled a $4.9 billion federal loan guarantee for the Grain Belt Express, a massive transmission line project seeking to carry wind and solar energy from the Great Plains to states farther east. It’s the latest in a series of Trump administration actions aimed at undermining the U.S. clean energy sector in the name of protecting taxpayer dollars.
In its Wednesday cancellation announcement, the DOE claimed that “the conditions necessary to issue the guarantee are unlikely to be met and it is not critical for the federal government to have a role in supporting this project.”
Energy Secretary Chris Wright is also scrutinizing several other loans made under the Biden administration by the DOE’s Loan Programs Office, which issued its conditional guarantee to the Grain Belt Express in November. He has pledged to closely review and potentially cancel tens of billions of dollars more in financing from the office, citing a need to more responsibly steward federal dollars. However, in its 20-year history, the office has turned a profit for taxpayers by collecting interest and principal payments from the companies that receive loans.
The Grain Belt Express has been in the works for more than a decade. It’s one of only a handful of major transmission projects underway in the U.S., and once built it will be able to support the development of gigawatts of new wind and solar projects and deliver $52 billion in energy cost savings over 15 years, according to Invenergy, the Chicago-based developer that’s building it. Around the country, more projects like the Grain Belt Express are needed to expand the grid fast enough to meet surging demand and to bolster electricity reliability.
The cancellation comes a week after Sen. Josh Hawley, a Missouri Republican, told The New York Times that he had made a personal appeal to President Donald Trump to take action to halt the project, and that Trump had promised to instruct the DOE to do so.
“He said, ‘Well, let’s just resolve this now,’” Hawley told The New York Times. “So he got Chris Wright on the line right there.”
Invenergy did not immediately respond to requests for comment Wednesday morning. The developer had sought the loan guarantee to reduce the expense of borrowing for the project, which will cost $11 billion in total and has already secured agreements with utilities in Missouri as part of its efforts to find buyers for the power it will make available across the regions it will connect.
It’s unclear to what extent the loss of federal loan guarantees will derail or slow down the project’s timeline. In May, Invenergy signed a nearly $1.7 billion contract with contractors Kiewit Energy Group and Quanta Services, and construction is slated to begin next year.
In a statement earlier this month responding to a social media post from Hawley criticizing the project, Invenergy accused the senator of “trying to deprive Americans billions of dollars in energy cost savings, thousands of jobs, grid reliability and national security, all in an era of exponentially growing demand.”
The U.S. faces a looming crisis as new data centers, factories, and broader economic growth cause electricity demand to rise faster than supply is forecast to grow.
Solar, wind, and batteries have made up more than 90% of new energy built in recent years, and are the only resources that can be constructed rapidly enough to meet surging demand in the near term. Other energy resources have far slower development times, including fossil-gas power plants, which currently face manufacturing bottlenecks that will take years to resolve.
In addition to headwinds from Trump and the GOP-led Congress, which just eliminated federal tax credits for solar and wind, the main factor that threatens to hold back clean-energy development is a lack of space on the grid.
The U.S. lags in building the new high-voltage transmission lines that grid experts say are necessary to bring even more new solar, wind, and batteries online. These lines carry clean power from where it’s cheap to produce to where the most energy is consumed, like cities, and building more of them can reduce grid congestion, improve power system reliability, and lower electricity rates.
The Grain Belt Express has won approval from utility regulators in Kansas, Missouri, Illinois, and Indiana, and has received support from lawmakers and organizations representing farmers and large electricity consumers. But the project has also faced multiple challenges from landowners and farmers. Invenergy is currently contesting an Illinois court’s 2024 decision to overturn state regulatory approval for the project, made in response to a challenge from the Illinois Farm Bureau and landowner groups.
Missouri’s attorney general, a Republican, launched an investigation into the project earlier this month, accusing Invenergy of inflating economic benefits and overstating cost savings it would deliver. Invenergy contested the validity of that challenge in a letter to Energy Secretary Wright, saying that all relevant issues have already been decided by state courts and regulators.
It’s common for large-scale transmission projects, which traverse hundreds of miles across many different municipalities, counties, and states, to get bogged down in court battles. It’s a big reason why it takes so long to build new power lines in the U.S. But the Trump administration’s decision to cancel financing for the project is uncharted territory, and the impact is still unclear.
Should the project be delayed, it’d be a major setback for the U.S.’s already-sluggish transmission buildout.
The U.S. needs far more transmission to be built to lower energy costs and reduce the increasing threat of blackouts caused by extreme weather, according to reports from groups ranging from the Department of Energy and the North American Electric Reliability Corp. to the Massachusetts Institute of Technology and Princeton University.
Over the past decade, the number of miles of long-range, high-voltage transmission built across the country has fallen, even as utility transmission spending has risen. A report released this week by advocacy group Americans for a Clean Energy Grid and consultancy Grid Strategies found that only 322 miles of high-voltage transmission lines were completed last year, the third-lowest buildout of the past 15 years, and well below the nearly 4,000 miles built in 2013.
“The Grain Belt Express represents a critical opportunity to modernize the grid, lower electricity costs, and deliver reliable energy across multiple states,” Christina Hayes, executive director of Americans for a Clean Energy Grid, told Canary Media in a Wednesday email. “We encourage the administration to take a fresh look at the value this project brings to achieving its own goals for economic growth and energy dominance.”
New York Governor Kathy Hochul has made energy affordability a centerpiece of her political platform this year, blasting proposed utility rate hikes and even promising to slow down implementation of the state’s climate law over the concern that the clean energy transition is costing New Yorkers too much.
But Hochul’s administration is slashing an energy affordability program that was once a priority for the governor, New York Focus has learned.
The EmPower+ program was designed specifically to help low- and moderate-income households “save energy and money” through energy efficiency upgrades. Since 2023 — at Hochul’s initiative — it has been New York’s one-stop shop to help residents take advantage of green building upgrades they might not otherwise be able to afford, like better insulation and replacing old boilers.
“I don’t know of any other program that makes such a big difference to the energy bill and the quality of life for a household that goes through [it],” said Jessica Azulay, executive director of the advocacy group Alliance for a Green Economy.
The program is now facing drastic budget cuts. In a July 11 meeting, the New York State Energy Research and Development Authority (NYSERDA) warned local contractors who install the upgrades that it would be cutting the EmPower+ budget from roughly $220 million this year to $80 million in 2027.
Michael Hernandez, New York policy director at the pro-electrification group Rewiring America, said he was “shocked” to learn of the impending cuts and has been sounding the alarm among advocates and lawmakers.
Azulay called the projected cuts “devastating.”
“As families are facing rising energy bills, the state is cutting back on a key tool that it has to help people get their energy bills under control, and to have homes that are more comfortable and safer and healthier,” she said.
In recent years, EmPower+ has served tens of thousands of New Yorkers, helping them identify ways that their homes might be wasting energy and fix them through installing better insulation and air sealing and switching to efficient new appliances like heat pumps. The program targets one- to four-family homes, allowing both homeowners and renters to participate.
The program covers up to $24,000 worth of upgrades per household, using a mix of state and federal funding. It aims to cover the full cost of upgrades for low-income households and, in some cases, guarantee that participants never pay more than 6% of their income on energy, by providing ongoing subsidies where needed.
Even New Yorkers who have gotten relatively minor upgrades through the program say it can make a big difference.
Isaac Silberman-Gorn, a first-time homeowner in Troy, outside Albany, said the program recently allowed him to replace a “dinosaur” of a dryer with a brand-new heat pump model. Thanks to the upgrade, his energy usage no longer spikes every time he does a load of laundry.
“It’s the first new appliance I’ve ever had,” he said. “Our energy bills are lower. I’m not worried about the thing starting a fire, which is nice.”
Silberman-Gorn, who works part-time as a bicycle mechanic and at an environmental nonprofit, said he wouldn’t have been able to afford the state-of-the-art new dryer if EmPower+ hadn’t covered the cost. “That was a game changer,” he said.
The program relies heavily on the work of local contractors, who conduct NYSERDA-funded energy audits for homes and then, typically, file the application to NYSERDA for upgrades that might be warranted. They’ve been a key avenue for bringing people into the program, often through customers who refer the companies to friends and neighbors they think might be eligible for similar upgrades.
NYSERDA told contractors in last week’s meeting that they can no longer sign up new customers for EmPower+ themselves. Clean energy advocates and contractors participating in the program see this as another way to tighten the belt.
“That will naturally slow the program down big-time,” said Hal Smith, CEO of Halco Home Solutions and president of the Building Performance Contractors Association of NYS, a trade group.
He said his own company, which works across the Finger Lakes region and has a staff of about 180, should be able to weather the cuts because it does a variety of work and serves customers across the income spectrum. But he worries that some companies working mainly or even exclusively for EmPower+ may have to shut down entirely or lay off much of their staff.
The cuts are particularly hard to stomach after years where NYSERDA was pushing for “more, more, more,” Smith said, building up the program as the state scrambled to meet clean energy targets and encouraging as many contractors as possible to get on board.
“That’s been the march for years, and we’ve all grown, grown, grown,” he said. “Now NYSERDA is saying we have to put on the brakes.”
A NYSERDA spokesperson said that EmPower+ remains a high priority for the agency and that it is only pausing applications from contractors while it reviews how to direct funds to the households most in need. (The spokesperson did not comment on the agency’s funding cuts to the program.)
Smith said he doesn’t blame any one actor for the cuts. The EmPower+ program — which was the result of a 2023 merger between two others — draws its funding from a dizzying array of sources. There’s money from New Yorkers’ utility bills, through a program approved by the state’s Public Service Commission; from the East Coast cap-and-trade program known as RGGI; from the state budget; from a federal home energy rebate program created under former President Joe Biden; and from the longer-standing federal heating assistance program LIHEAP.
Scott Oliver, an EmPower+ program administrator at NYSERDA, told contractors last week that federal and state budget cuts were forcing the agency to scale back the program. Hochul and state lawmakers gave EmPower+ a $200 million funding surge in 2023 but earmarked only $50 million for the program this year. President Donald Trump’s administration is seeking to eliminate LIHEAP entirely and cut back other weatherization funds.
Hochul could direct NYSERDA to tap other funding sources for the program, advocates say.
The cap-and-trade program RGGI has earned New York anywhere from $100 million to $400 million a year over the last decade and accumulated a surplus of more than $850 million, according to NYSERDA’s latest financial statement. The state’s new $1 billion climate fund included only $50 million specifically for EmPower+, but has another $110 million for unspecified green buildings projects, which the governor could use for the program. (The New York State Assembly had sought in negotiations to allocate more than $300 million just to EmPower+.)
And the Public Service Commission, New York’s utility regulator, recently increased the funding going from energy customers’ bills to programs like EmPower+, if not by as much as some advocates had hoped.
Advocates say it’s not yet clear whether Hochul’s administration intentionally cut EmPower+ or whether the program, with its complicated mix of funding, has simply slipped through the cracks.
Still, Hernandez, of Rewiring America, said it was bewildering that Hochul’s administration could allow such cuts to proceed while the governor emphasizes energy affordability as much as she has: “How can she be saying, doing both of those things at the same time?”
In a statement, the governor’s office highlighted the $50 million for EmPower+ in this year’s state budget.
“Governor Hochul has made affordability for New Yorkers a top priority,” said Hochul’s energy and environment spokesperson Ken Lovett. “The Governor continues to push back against devastating cuts in Washington, and calls on our state’s Congressional Republican delegation to join the fight to protect our state’s most vulnerable citizens.”
The EmPower+ cuts further slow New York’s progress toward meeting legally binding climate targets, in particular a requirement to slash energy use in buildings by 2025. That deadline is now just months away, and the state is far from meeting it.
Some climate hawks in the state legislature are beginning to cry foul over the EmPower+ cuts.
“I’m sure that right now the governor is doing her best to look at where we can cut corners,” said Assemblymember Dana Levenberg, of Westchester and the Hudson Valley, referring to the massive funding cuts coming down from Washington. “This is not where we should be doing that.”
In their presentation last week, NYSERDA officials said they were still looking for alternate sources of funding to keep EmPower+ whole.
“This is a problem that is absolutely fixable, and we need the governor to step in here and make the call,” said Azulay, of Alliance for a Green Economy.
Hochul has promised that she’s attuned to such concerns. “Utility costs are a huge burden on families,” she told reporters earlier this month, “and I’ll do whatever I can to really alleviate that.”
An Ohio bill that would establish rules for underground carbon dioxide storage is being shaped behind the scenes by oil and gas companies that stand to benefit from the legislation.
House Bill 170 would pave the way for companies to pump waste carbon dioxide from industrial plants and hydrogen production deep underground as a way to lower their emissions. Companies would lease subsurface property rights long-term and eventually transfer liability for the stored waste to the state.
Oil and gas industry groups have been busy for months vetting bill sponsors, drafting legislation, writing talking points for lawmakers, meeting with regulators, and coordinating with other industry stakeholders.
Industry lobbyists often play an active role in pushing for legislation that will favor them. But public records shared with Canary Media by Fieldnotes, a watchdog group that investigates the oil and gas industry, show that the American Petroleum Institute and the Ohio Oil and Gas Association have played an outsize role in shaping the bill.
Supporters say carbon capture and sequestration, or CCS, is necessary to lower greenhouse gas emissions that drive human-caused climate change, especially for hard-to-electrify industries. As lawmakers and regulators craft rules for the technology, the stakes are high, with potentially large risks and rewards for industry and the public.
Carbon capture is “the new Wild West…where there is a lot of money to be made,” said Jennifer Stewart, the American Petroleum Institute’s director of climate and environmental, social, and governance policy, at a hearing on last year’s carbon capture bill in the Ohio Senate. She suggested that tax credits could offset the costs of reducing greenhouse gas pollution and that companies could also sell carbon offset credits to other businesses.
Left unsaid was that the petroleum industry was then facing Biden-era emissions rules for natural gas plants, which an aide for bill sponsor Sen. Tim Schaffer (R-Lancaster) flagged in an internal memo as “the reason for the push for carbon capture.” The aide’s memo cited an American Petroleum Institute summary of what carbon capture “is and why it is good for the oil and gas industry.”
Although the Trump administration now proposes to repeal those rules, the oil and gas industry still faces increased competition from renewables as the energy transition continues. Carbon capture and storage could serve as a way to continue promoting their products.
Ohio is not alone in the push for carbon capture laws. More than 20 state legislatures have passed or have been considering such bills, according to a spring 2024 presentation by the American Petroleum Institute.
The laws are necessary if states want a lead role on permitting and regulating wells to pump waste carbon dioxide deep underground. As of May 30, four states already had federal approval for that role, called primacy. Nine others had applied.
The public records shared by Fieldnotes show that during the last legislative session, spanning 2023 and 2024, people at the American Petroleum Institute and the Ohio Oil and Gas Association vetted Rep. Monica Robb Blasdel (R-Columbiana) as a potential bill sponsor. Industry representatives offered to arrange media opportunities for Sen. Al Landis (R-Dover). They also provided talking points and supplied wording for initial one-page “placeholder” bills. Robb Blasdel, Schaffer, and Landis introduced identical one-page bills in December 2023.
In February 2024, the industry groups sent a draft substitute bill, with details for the carbon capture program. Ohio’s Legislative Service Commission, which reviews bills for form, clarity, and fiscal impacts, raised questions about the bill with Schaffer’s office. His office had the Ohio Oil and Gas Association provide answers.
Also that winter, the petroleum association sent Robb Blasdel’s office the Ohio Department of Natural Resources’ alternative bill language “in response to the industry draft bill.” The group subsequently supplied her office with an analysis of differences in the industry’s and agency’s language. The agency generally wanted industry to pay higher initial fees, provide financial bonding, and wait decades longer before the state assumed liability for closed wells, along with other stricter provisions.
Although representatives from the industry groups met with staff from the Ohio Department of Natural Resources to discuss terms in May 2024, staff members apparently didn’t talk with Robb Blasdel about the bill until months later. “This will be our first convo with Rep. Blasdel about the subject,” wrote Benjamin Bruns, the agency’s legislative affairs director, on September 12.
A detailed bill was finally swapped out for the earlier placeholder version in the House Natural Resources Committee last December. Along with Robb Blasdel, representatives of both the Ohio Oil and Gas Association and the American Petroleum Institute spoke in its favor.
Despite HB 170 and Senate Bill 136 having terms nearly identical to those of the 2024 substitute bill, Schaffer’s aide gave both petroleum groups a chance for advance review before the bills were introduced this year. House Rep. Bob Peterson (R-Sabina) is now a cosponsor with Robb Blasdel. Replacing Landis as a cosponsor of SB 136 is freshman Sen. Brian Chavez (R-Marietta), who has worked and owned companies in the oil and gas industry. He has not answered Canary Media’s questions about whether the bill might benefit any of his businesses.
After hearings in the Ohio House this spring, Robb Blasdel’s office asked for revised bill language, which the American Petroleum Institute’s representative supplied on June 2. Less than 90 minutes later, her office invited petroleum industry people and others to an “interested party” meeting on June 5. Among them were staff and lobbyists for carbon capture companies and other bill supporters, along with representatives for the Ohio Farm Bureau Federation and the Nature Conservancy, which had identified themselves as interested parties (versus saying they were for or against the bill).
No opponents were invited, despite numerous concerns raised by the Buckeye Environmental Network, the Freshwater Accountability Project, and others, including whether provisions in the bill would infringe on property rights, lower home values, and cause health and safety problems, among other issues.
A new substitute bill was introduced during the June 18 meeting of the House Natural Resources Committee, which Robb Blasdel chairs. More hearings are planned for the fall.
Besides documenting industry’s push for Ohio to pass a carbon capture and storage law, the public records raise questions about whose interests lawmakers are serving.
As Fieldnotes researcher Julia Kane sees it, industry groups that stand to profit have “been in the driver’s seat of this process…I’d think in a democracy you’d want the lawmakers looking out for the interests of the public and talking to all the stakeholders,” she said.
Neither Chavez nor Schaffer responded to Canary Media’s requests for comment. Peterson’s aide, Kylie Fauber, said the representative would defer any comments to Robb Blasdel. She has not answered Canary Media’s questions for this story.
The American Petroleum Institute “regularly engages with policy makers on both sides of the aisle to educate on the critical role of American energy and to share our industry’s priorities,” said Christina Polesovsky, the organization’s associate director for Ohio, in response to Canary Media’s questions about critics who see the group as having outsize influence. She added that the group has provided on-the-record testimony through the committee process.
The Ohio Oil and Gas Association did not answer Canary Media’s request for comment for this story.
Opposing parties have also testified, and Robb Blasdel met with two representatives of the Buckeye Environmental Network on June 4. But they and other opponents were left out of the “interested party” meeting on June 5, before the most recent substitute bill was introduced.
“The cake is most of the way baked, and the oil and gas industry kind of set the foundation for the entire conversation,” Kane said.
While the extent of industry’s involvement in the carbon capture bills wasn’t clear before the most recent batches of the public records were released to Fieldnotes this spring, it’s not necessarily surprising.
“This is the system that we’re in,” said Stephanie Howse-Jones, a Cleveland City Council member who served for seven years as a Democratic representative in the Ohio House. Lobbyists often provide draft bills and talking points. Lawmakers often use those talking points when speaking about legislation, but they don’t always read the full text of their bills, she noted.
Howse-Jones said Ohioans need to understand specifically how bills will impact them and their communities. Getting that information may be more challenging after Ohio’s latest budget bill changed the state’s public records law to shield lawmakers’ notes and some internal communications from disclosure until the next legislative session. But more transparency isn’t enough, she said.
“Ohioans must demand more of their state legislature,” Howse-Jones said. Until campaign finance reform takes place, “most of us won’t be able to compete with the dollars. But we do have organizing-people power.” That goes beyond voting and includes taking an active role in organizing and communicating constituent concerns, she said.
Tristan Rader (D-Lakewood) said he hasn’t made up his mind about the carbon capture bills but has questions, especially whether the waste will escape from the underground spaces in which it will be stored. Yet he sees an imbalance in power at the legislature, where industry often holds more sway.
“The real problem is that the communities that are impacted by the activity of these organizations’ wells have a very minimal presence and limited input. And it’s not for lack of trying,” Rader said.
How do you reduce greenhouse gas emissions from one of the largest sources — buildings — without breaking the bank or the grid? To answer that question, the utility Puget Sound Energy (PSE) turned to DNV, a global risk management and assurance consultancy, to examine the benefits of heat pumps.
While heating, ventilation, and air conditioning technologies have vastly improved in efficiency over time, the intervals at which people replace these systems aren’t that frequent, so it may take decades to upgrade a carbon-intensive but otherwise properly functioning HVAC system. Utility programs to incentivize the replacement of older systems with more efficient ones can speed up the process, but in colder regions, that typically means simply replacing a system fueled by oil or natural gas with a more efficient but still fossil-fueled system. Electric heat was simply too inefficient and expensive for colder climates — until recently. Fortunately, the heat pumps on the market today have matured to the point where they are effective in places with colder climates, like Washington state. But they still need a little push for widespread adoption.
When data met heat pumps
PSE supports approximately 1.1 million electric customers and more than 900,000 natural gas customers and is at the forefront of heat pump deployment across the Evergreen State. The utility, which has worked with DNV on energy projects since 2010, wanted more data on potential customer and system impacts of dual-fuel heat pumps. “I was already in conversation with the customer on a potential project related to load forecasting when a question came up around dual-fuel heat pumps,” said DNV Principal Consultant Kevin Cracknell. “My response was that DNV has the data and expertise to help.”
So DNV and PSE devised a pilot program that provided incentives for two types of heating and cooling systems: dual-fuel heat pump systems and cold-climate heat pump systems. The pilot targeted customers who were either interested in adding a hybrid heat pump system to their natural gas furnace or replacing their electric forced hot-air furnace with a cold-climate heat pump.
What are dual-fuel heat pumps?
Dual-fuel systems have a standard heat pump, which can provide heating down to about 35 degrees Fahrenheit, paired with a natural gas furnace, which turns on when temperatures drop below 35°F. The cold-climate systems are rated to provide 100 percent heating until temperatures drop to about 5°F.
With average winter temperatures between 30 and 40 degrees Fahrenheit, PSE’s territory is an ideal place to deploy heat pumps. But electrification comes with challenges. If the majority of PSE’s 900,000-plus gas customers made the switch to electric heat pumps, the impact on the grid could be significant. Because the impacts on energy savings and peak load from heat pumps hadn’t been closely studied, PSE needed to fully understand the implications before it considered expanding the program. “When it comes to energy efficiency programs, utilities need information backed up by sound science. The DNV team provided critical information on heat pumps to PSE so they can move the energy transformation forward,” said Geoff Barker, a principal consultant at DNV and the sponsor of this project.
To get a clear picture of typical consumption patterns, DNV completed a preliminary analysis using unique localized data, including residential saturation surveys, daily gas data, and interval advanced metering infrastructure (AMI) data. The data was available through DNV’s existing end-use data development work as well as load research completed to support PSE’s gas and electric utility rate cases. Using this data, DNV examined consumption patterns on the basis of outside temperature, home size, and heating technology. DNV’s preliminary analysis enabled PSE to confidently validate assumptions on energy use and changes in load, which got the utility team excited for a more detailed study.
Then PSE engaged DNV to evaluate how much money energy program participants saved and how the new equipment changed peak demand during the heating season. Both these statistics are important — participants need to see at least a small dent in their energy bills to make their investment worthwhile, and the utility needs to make sure the grid can handle the increased demand. Measuring energy savings was relatively simple. DNV analyzed billing data to estimate annual heating savings and hourly peak demand, modeled consumption data, and then estimated annual savings using weather-normalized daily consumption and peak-demand impacts.
A sample of dual-fuel heat pumps were also submetered to determine when the heat pumps or gas furnaces were being used and at what outdoor temperatures. To measure the difference between the modeled and actual consumption, the submeter data was also compared with the consumption data in the AMI billing analysis.
From an energy savings perspective, results were positive: The pilot program showed that all the program participants reduced the total amount of energy used to heat their homes. For participants who switched from an electric furnace to a heat pump, all the energy savings were due to the greater efficiency of the cold-climate heat pump. Results were mixed for participants who switched from a gas furnace to a heat pump and for those who installed a hybrid system. While their electricity use increased, that was countered by a reduction in gas consumption, and thus a reduction in their overall home energy use.
Just as important to PSE was the program’s effectiveness. DNV explored the experiences of the customers who switched to hybrid systems, the contractors who installed the equipment, and PSE staff to understand all aspects of the program. Unlike the energy savings evaluation, this analysis depended on interviews and surveys, and provided PSE with insights on how to improve the program moving forward.
The good news is that all participants were very satisfied with the new equipment. Customers rated their experience with the program very highly, and a majority of them would recommend a similar heat pump system to their friends and family. For energy savings, the average satisfaction rating for customers with a cold-climate heat pump was 4 out of 5. For owners of a hybrid system, it was slightly lower, 3.9 out of 5, likely because the overall savings were a bit less than expected.
What’s next for heat pumps in Washington state? DNV identified several areas where the program could be improved, including the need for more clarity on how to optimally run the hybrid heat pump systems (some participants had their gas heating kick in at temperatures as high as 50°F, and others let it run at any temperature). PSE plans to provide incentives for hybrid heat pump systems for the next 5 years and will continue to evaluate the energy savings, peak demand, and carbon emissions impacts over the next few years.
Additionally, future participants and their systems will provide more data, which will help increase understanding of how hybrid heat pump systems impact energy consumption — giving the industry a greater understanding of this emerging opportunity. PSE plans to provide incentives for hybrid heat pump systems for the next 5 years and will continue to evaluate the energy savings, peak demand, and carbon emissions impacts of the systems over the next few years.
“The collaboration with DNV has allowed us to gather valuable data that will help shape the future of home heating in our region.”
Jesse Durst, senior market analyst at PSE
PSE’s pilot heat pump program is laying the foundation for significant decarbonization in Washington state, ensuring that its customers are saving energy, reducing greenhouse gas emissions, and keeping warm all winter long. But the impact of this pilot program goes beyond the state’s borders. The data and insights DNV has amassed are a solid foundation for utilities, contractors, and customers to understand the value of heat pumps as an effective tool for decarbonization.
The Trump administration just dealt another blow to U.S. environmental regulations — one that could allow more contamination of drinking water from toxic coal ash contamination.
The Environmental Protection Agency proposed on July 17 to extend deadlines for required reporting and groundwater monitoring at coal ash landfills and dumps.
Any delay of these rules would be harmful in its own right, experts say, and they fear the announcement is just the beginning of further efforts to undercut coal ash regulations. During his first term, President Donald Trump largely ignored federal coal ash rules that took effect in 2015. This time around, his administration is widely expected to roll them back.
Advocates suspect that updates made last year to include so-called legacy coal ash, which wasn’t covered by the original rules, and coal ash landfills are especially vulnerable. That’s why alarm bells have been ringing for advocates following the EPA’s latest move to delay enforcement of one key aspect of the updated rules: the regulation of dry coal ash dumps and landfills, known as coal combustion residual management units, or CCRMUs.
The EPA’s July 17 announcement included a direct final rule and a companion proposal that would extend deadlines for these CCRMUs.
The EPA said it wants to extend the deadline by one to two years for the “facility evaluation reports,” which companies have to file if they own coal ash that meets the definition of a CCRMU, and therefore makes the sites newly subject to regulation. The EPA also proposes extending the deadline to start groundwater monitoring at these sites for an additional 15 months, from May 2028 to August 2029. The direct final rule issued by EPA would extend the deadline for the facility report to February 2027.
As it stands, utilities and other owners of coal ash sites are required to report by February 2026 whether they have any coal ash in landfills, berms, dumps, or other dry repositories that would be considered CCRMUs newly subject to regulation under the updated rules.
“We assume what EPA did was give themselves time to make significant changes to the legacy coal ash rule,” said Lisa Evans, senior counsel at Earthjustice. “The amount of time given to utilities to comply with the CCRMU portion of the rules [was] extremely generous. The utilities were given years, and now they’re coming back for more, thinking this EPA will grant them more time.”
The initial coal ash rules took effect in 2015 and were heralded as a major step toward cleaning up the toxic coal ash located at more than 700 sites at over 300 power plants nationwide. But those rules did not cover coal ash that was used to fill in earth or build up berms, or was simply scattered about; nor did they cover ash at coal plants closed before the rules took effect.
The environmental law organization Earthjustice filed a lawsuit on behalf of environmental groups seeking to expand the 2015 rule’s coverage, and after a federal court decision in 2018, the updated rules were eventually adopted in May 2024. These updated rules cover CCRMUs as well as “legacy ponds” — coal ash stored in water at coal plants closed before 2015.
Under federal administrative procedures, the EPA’s new direct final rule will take effect six months after being published in the Federal Register if no “adverse comments” are filed by the public. Groups including Earthjustice are almost certain to lodge adverse comments, in which case the rule would not take effect, and instead the companion proposal — to extend the facilities report deadline to February 2028 — would undergo a public comment process.
This poses a bit of a conundrum for environmental groups: If they challenge the rule, they may end up with an even longer delay.
“If you get a year or two years, you get another two years to put in groundwater monitoring. Then that delays the determination of contamination, which then delays development of a cleanup plan and final remedy,” said Evans. “You’re pushing everything into the future.”
An EPA press release says, “These actions advance [EPA] Administrator [Lee] Zeldin’s Powering the Great American Comeback Initiative,” which includes energy dominance, among other pillars.
Evans said the EPA’s announcement came immediately after a July 17 meeting that she and other advocates had with EPA officials, along with residents who live near some of the country’s hundreds of legacy coal ash impoundments. She said the officials listened to their concerns but made no mention of the delays that were about to be unveiled.
“We were all stunned,” she said. “Years do make a difference when you’re thinking about the movement of contaminated groundwater. This will allow more contaminants to get into groundwater, it will make it hard, possibly impossible, to remediate. We know these sites; we know how contaminated these sites are; we know contamination is moving in the groundwater.”
Almost a century ago, on the shores of Lake Michigan in northwest Indiana, the utility NIPSCO mixed coal ash from its Michigan City coal plant with sand and sod to help fill in the space behind steel retaining walls. On the other side of those now-corroding steel walls is the lake, which provides drinking water for the region and is a hub of both human recreation and aquatic life.
Environmental leaders have serious concerns that waves will pound away at the decaying wall, further weakening it, to the point that tons of toxic coal ash will spew into the lake. Coal ash contains heavy metals and other contaminants known to cause cancer and other serious health problems, as the EPA notes.
The Michigan City coal plant is among more than 300 sites covered by the updated rules, according to Earthjustice’s analysis, meaning NIPSCO should be required to file a CCRMU facilities report by February 2026 and then groundwater monitoring results and cleanup plans. Any delay in the reporting deadlines means a delay in the site being remediated — and extends the risk of coal ash contaminating the lake and possibly the groundwater too, environmental leaders say.
“Having the delay in some of those requirements is pretty devastating to hear,” said Ben Inskeep, program director of the Citizens Action Coalition, an Indiana consumer protection group. “These are coal ash waste dumps that have been there for decades. For all this time, they are just leaching really nasty things into our water supplies, putting us in grave danger of a catastrophic failure of the coal ash, all that coal ash getting into our waterways or drinking water supplies.”
NIPSCO is in the process of repairing one of the steel seawalls adjacent to a creek that empties into Lake Michigan by the Michigan City plant, but local leaders say that is less a solution and more a sign of the risks.
“The utilities have had a long time to figure out what kind of coal ash they have on their properties, what damage has been done, what remedies are possible,” Inskeep said. “Further delay is certainly harmful to communities who have been forced to endure living next to these toxic sites for so long.”
Owners of legacy coal ash ponds were required in November 2024 to file inspection documents for their sites. Those documents show serious groundwater, lake, and river contamination concerns from sites in Alabama, Georgia, Illinois, Indiana, and West Virginia, among other states, according to Earthjustice’s analysis.
The Widows Creek plant on the Tennessee River in Alabama may be the “dirtiest” site subject to the updated rules, according to Earthjustice. The plant was retired shortly before the 2015 rules took effect, meaning that it was not regulated until the update last year. Also unregulated until the 2024 update was the Morrow Lake plant in Michigan, whose location puts coal ash in direct contact with a recreational lake, according to its recently filed inspection reports.
Also troubling, advocates say, is that multiple companies known to have legacy ponds on-site did not file any reports by the November deadline or within an allowed six-month extension period. An EPA website compiling reports includes 46 sites filed under the legacy rule, out of at least 84 sites known to have legacy ash, according to Earthjustice’s analysis.
“It’s unfortunately not surprising, considering the industry’s general noncompliance,” said Mychal Ozaeta, Earthjustice’s clean energy program senior attorney. “It’s nothing new. We’re going to continue to monitor it, utilize our internal resources, work closely with our partners to track it just so the public is aware of various sites across the country failing to make publicly available this critical information and comply with requirements.”
The EPA press release about the deadline extensions also refers back to “March 12, 2025, the greatest and most consequential day of deregulation in the history of the U.S., [when] EPA committed to taking swift action on coal ash, including state permit program reviews and updates to the coal ash regulations.”
It’s a reference to another move the EPA is making to further undercut federal coal ash rules: Giving states, including those with lax records on the environment, the power to enforce their own coal ash rules.
On July 10, the EPA had issued another announcement that could weaken the legacy coal ash rules. It essentially said an earlier memo from the EPA — aimed at defining “free liquids” causing contamination concerns in coal ash repositories — should be ignored.
“It’s pretty nefarious,” said Evans. “This is all just the start of the Trump administration’s attempted unraveling of coal ash protections.”
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