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Massachusetts lawmakers may double the number of cities and towns allowed to ban fossil fuels in new construction. A bill under consideration would add up to 10 communities to an ongoing pilot program that proponents say is already reducing emissions, making homes healthier, and lowering energy bills — all without stifling the development of new housing.
Cities including Salem and Somerville are lining up to participate in an expanded program, and some local leaders in Worcester are eager to take part, too. Boston, the state’s largest city, has previously expressed interest in joining.
“We’re a coastal community that’s going to bear the brunt of climate change,” said state Rep. Manny Cruz, a Democrat representing Salem. “We want to make sure we’re doing our part to mitigate the damage.”
As Massachusetts strives to reach net-zero carbon emissions by 2050, it has prioritized policies that encourage the transition away from fossil fuels, particularly natural gas. In 2022, as part of a wide-ranging climate law, the state created a pilot authorizing 10 municipalities to prohibit fossil-fuel hookups in new construction and major renovations. In 2023, it introduced an optional building code aimed at reducing energy consumption and preparing for an all-electric future, and later that same year, regulators issued guidelines for natural-gas utilities to evolve toward clean energy.
Massachusetts joins other states and cities pursuing such policies. New York this summer became the first state to commit to an all-electric building standard, though Gov. Kathy Hochul, a Democrat, is now under pressure to delay the implementation of these rules. Dozens of local governments nationwide have measures on the books barring gas use in new buildings and renovations, and some have policies to ratchet down fossil-fuel appliances in existing structures over time, too.
Advocates hope Massachusetts’ pilot paves the way for the legislature to allow all 351 of the state’s cities and towns to choose their own path on fossil-fuel restrictions.
The bill still faces committee votes in both the House and Senate. Single-issue bills like this one are rarely approved by the full legislature, but are instead wrapped into a larger package, said state Sen. Michael Barrett, a Democrat and chair of the legislature’s telecommunications, utilities, and energy committee, which heard testimony on the bill late last month.
Massachusetts’ all-electric pilot has roots stretching back to 2019, when the town of Brookline passed a bylaw prohibiting new fossil-fuel infrastructure. Supporters argued that the momentum behind the energy transition and forecasts of rising natural gas prices made the policy a responsible step.
There’s no point in installing new systems now that will only get more expensive to run and will end up needing to be replaced with electric equipment before too long, said Lisa Cunningham, cofounder of nonprofit ZeroCarbonMA and one of the forces behind the Brookline bylaw.
“It’s basically locking people into these huge energy burdens,” she said.
But Brookline’s policy was struck down in 2020 by the Democratic attorney general Maura Healey, who was later elected governor of the state in 2022. Healey argued that municipalities do not have the authority to supersede state building and gas codes, though she said she supported emissions reductions and felt she had no choice but to reject the bylaw.
So Brookline and several other towns petitioned the state legislature for special permission to implement their own rules. Lawmakers responded by including the 10-town demonstration program in a sweeping climate bill that then-Gov. Charlie Baker, a Republican, signed in 2022 despite expressing serious reservations about the impact the pilot might have on housing.
Indeed, detractors have long maintained that all-electric building mandates will drive residential construction costs up at a time when Massachusetts is facing an acute housing shortage.
However, none of the 10 municipalities in the current program have reported such a slowdown. Lexington, for example — which has adopted both the fossil-fuel ban and the more stringent building code — has permitted some 1,100 new housing units in the past two years, including 160 affordable homes.
Research also indicates that building and running an all-electric house does not come with a price premium. A 2022 report by clean-energy think tank RMI finds that the up-front cost and annual operating expenses for a fossil-fuel-free home in Boston are slightly lower than for a mixed-fuel building. Since then, Massachusetts has adopted discounted wintertime electricity rates for homes with heat pumps, making electrification even more affordable.
“The lowest-hanging fruit is to build all-electric,” Cunningham said. “Doing all these as retrofits is going to be a lot more difficult.”
In 2023, advocates and supportive lawmakers proposed a bill that would allow any municipality to implement its own gas ban, but the measure did not make it into the climate package passed later that session.
Proponents of expanding the pilot say it is important to offer the opportunity to a wider variety of communities across the state. Of the initial 10 participants, all but two are Boston suburbs, and only two have median household incomes below $125,000. Seven have populations below 50,000, with one, the Martha’s Vineyard town of Aquinnah, home to only about 600 people.
“It restricted it to these much wealthier, much smaller, less diverse communities. That’s just not equitable,” Cunningham said.
Broadening the program will also help the state collect more data about how these prohibitions impact emissions, public health, and housing costs and availability, said Barrett, who supports the bill.
“The more data we can get in about the cost of going all-electric, the better off we’ll be,” he said.
Somerville has been eager to join the pilot since the beginning. When the program launched, it was intended to include the 10 communities that had already asked the legislature for permission to implement fossil-fuel restrictions. The creation of the program, however, spurred more local governments to vote for such bans in hopes of joining the pilot if any spots should open up. Somerville was the first to do so, just weeks after the law was enacted, with its City Council passing the measure unanimously.
Having the authority to limit fossil-fuel growth would not only move Somerville toward its goal of being carbon-negative by 2050, but also lower heating costs for some residents and create housing with better air quality, said Christine Blais, the city’s director of sustainability and environment.
“We want to give Somerville residents the best chance to have a good quality of life,” she said.
In Salem, which has also passed a measure asking to join the pilot, City Councilor Jeff Cohen would like to see the bill passed, but he also thinks it doesn’t go nearly far enough. Allowing 20 of Massachusetts’ 351 municipalities to ban natural gas just won’t make a meaningful dent in the state’s emissions, he said.
“It’s time to do something,” Cohen said. “Ten at a time doesn’t seem good enough for me.”
The ocean has beckoned to legions of energy entrepreneurs before dashing their hopes against the rocks. Now a new company is heeding the siren call — but with a twist.
Italy’s Sizable Energy launched in 2022 to build pumped hydro energy storage under the ocean. Cofounder and CEO Manuele Aufiero pursues that outlandish vision with the methodical diligence he picked up as a seasoned nuclear engineer. Now, the firm has deep-water wave testing under its belt, and in October it closed $8 million in seed funding to build its first offshore demonstration project.
This venture takes aim at two longstanding, elusive cleantech dreams: reinventing pumped hydro and harnessing the sea for clean energy. It’s an ambitious project that must navigate choppy seas, literally and figuratively, to succeed. But if Sizable can pull it off, it would unlock low-cost, long-duration storage that could accelerate the broader shift to clean energy.
Even as lithium-ion batteries surge in popularity, legacy pumped-hydro projects still store more gigawatt-hours than any other technology. The latter harnesses gravity, using excess electricity to pump water uphill and releasing it to turn turbines when more energy is needed. This simple, century-old technology rarely gets built anymore, however; besides the environmental implications of forming enormous reservoirs, today’s fast-moving energy markets aren’t particularly encouraging for power plants that take many years to build and cost billions of dollars up front.
That’s not to say pumped hydro never gets built, Aufiero told me — Switzerland recently completed a facility in a high mountain valley, but it took 14 years. Part of the problem there is that every mountain is different, he explained: the height, flow rate, and energy equipment must be customized for each location.
But the ocean, he said, offers the chance to standardize this otherwise bespoke tech — making it far easier and quicker to deploy.
“We are unfolding the possibility of building the system even before knowing exactly where you are going to deploy,” he said. “We do that by deploying offshore. Water is the same everywhere.”
Specifically, Sizable has designed a gravity-based storage system that shuttles a briny liquid up and down a vertical pipe affixed to the seafloor. Inflatable membranes form reservoirs at the bottom and on the surface; from above, it looks like a giant floating donut. The system connects to the land-based grid, and uses power to pump the brine up through the plastic pipe. Reversing that regenerates power.
Startups have tried reinventing pumped hydro by running train cars filled with rocks uphill, loading up ski-lift-style cable systems with weights, and stacking enormous blocks with robotic cranes. Each of those began with the same claims about mechanical simplicity and ended up in the junkyard of cleantech ideas. But where those ventures started on the ground and had to build up, Sizable Energy starts on the ocean surface and goes down.
“There’s a lot of ocean depth in the world — it’s not oversubscribed,” said Bruce Leak, general partner at Playground Global, which led the seed round.
The relatively low costs of Sizable’s design could make it competitive for long-duration storage, something experts think the grid needs but nobody has really delivered yet.
Lithium-ion batteries are increasingly competitive for shorter durations, like four hours. But they get prohibitively expensive for much longer than that. To deliver the same megawatt capacity over 12 or 24 hours (through the night or a whole day of cloudy weather) requires stacking a bunch more batteries, and that stacks the cost.
Any company that wants to compete in long-duration storage has to find materials and designs that make it dirt cheap to add hours of capacity. Traditional pumped hydro does this by filling a large reservoir with water. Sizable chose a double-walled membrane to fill with brine, which fits the cheap and scalable bill. Adding more vertical feet of plastic pipe is pretty inexpensive, too.
The power equipment costs less than 700 euros ($810) per kilowatt in the long term, competitive with pumped hydro, Aufiero said. Where the technology really shines is in the marginal cost of adding more storage duration: less than 20 euros ($23) per kilowatt-hour, at scale. That’s right on par with what Form Energy is targeting with its iron-air battery, an attempt at a mass-produced electrochemical battery for 100 hours of duration.
Sizable is shooting for eight hours to 24 and beyond. The economics improve at a larger scale: If you’ve got to install a mooring system and connect a marine cable to the grid, you might as well ship more power through it rather than less.
That’ll take some time to work up to. Sizable already built a kilowatt-scale proof of concept, which it floated at the Natural Ocean Engineering Laboratory in Reggio Calabria, Italy. In September, the company subjected its design to a bombardment of artificial waves in the gigantic pool at the Maritime Research Institute Netherlands, which vets the durability of marine engineering. The successful performance in those tests set the stage for the recent fundraising round.
With the cash infusion, the team is building a 1-megawatt device, which will sport a 50-meter (164-foot) radius and occupy up to 500 meters (1,640 feet) of ocean column off the coast of Reggio Calabria.
Sizable is funding this project itself, since it can’t yet show financiers the real-world performance data they need to underwrite investment. It will be fully functional, using scaled-down components because of its diminutive size, but it won’t connect to the grid. Sizable has already secured a 10-megawatt grid connection in southern Italy for its first truly commercial development.
The unenviable challenge facing Aufiero is to fortify his invention against the torments of the sea, without spending so much money armoring it that it loses its low cost.
“Doing something in the ocean, it is a challenge, but it’s also an opportunity for massive scalability,” Aufiero said. He set out to design a “simple system that can be scaled without too many surprises.”
Wave action has literally sunk many hopeful ocean-energy pilot projects. But such devices in the past sought to harness the renewable power of the waves through direct contact. Sizable Energy only needs the ocean as a uniform space to operate in, so its technology tries to minimize wave contact as much as possible.
Two outer rings of plastic pipe were engineered to disrupt waves before they hit the floating reservoir. In the event that strong surf or heavy rain threatens to weigh down the reservoir, bilge pumps activate to clear out the liquid.
In Europe, people have been leasing seabed for energy projects at grand scale for decades. Sizable will apply to the same regulatory bodies that oversee offshore wind, but needs a much smaller footprint per megawatt.
In fact, offshore wind farms are an attractive potential site for the startup’s contraption, Aufiero said. By colocating, Sizable could share the export cables, and firm up the booms and busts of wind generation by storing it locally and distributing it to the grid as needed. Leak, the investor, likened this pairing to transforming an offshore wind plant into a nuclear power plant by converting variable generation into predictable, baseload clean energy.
For their part, the lead investors at Playground Global find the challenge of surviving Neptune’s wrath exhilarating.
“As engineers, we love things that are hard,” Leak told me. “If it’s a good idea that anybody can do, what’s your difference?”
America’s data centers used a whopping 176 terawatt-hours of electricity in 2023, representing 4.4% of the nation’s total power consumption. Those numbers are only going up as AI tools gain popularity, pushing computing loads higher. By 2028, data centers could gobble as much as 580 TWh of power, or 12% of the U.S.’s total electricity consumption that year, Lawrence Berkeley National Laboratory has projected.
The surge seriously complicates goals set by hyperscalers to slash planet-warming pollution — tensions that Canary Media discussed with Google and Microsoft during last week’s SOSV Climate Tech Summit.
Utilities from Virginia to Nevada are planning to build large numbers of gas-fired power plants and to extend the life of aging coal plants to satiate the tech industry’s rising demand — moves that could spike both utility customers’ bills and carbon emissions. Data centers themselves typically rely on diesel-burning backup generators to ensure our increasingly digitized world runs without interruption.
On the panel, I spoke with Lucia Tian, Google’s head of advanced energy technologies, and Sean James, Microsoft’s senior director of energy and data-center research.
Tian helps lead Google’s efforts to commercialize cutting-edge “clean, firm” technologies that could supply around-the-clock power to data centers. Google was among the earliest backers of Fervo Energy, a startup that’s operating and building next-generation geothermal plants in Nevada and Utah. The search giant has also signed a unique deal with Kairos Power to potentially develop a fleet of small modular nuclear reactors.
Microsoft, meanwhile, has inked a long-term power purchase agreement with Constellation Energy to support the company’s $1.6 billion plan to reopen its shuttered Three Mile Island Unit 1 nuclear reactor in Pennsylvania. James said that, inside its own fenceline, Microsoft is developing cleaner alternatives to diesel generators, such as hydrogen fuel cells and advanced batteries. The tech giant is also improving the design of server racks and other hardware to improve energy efficiency and reduce the need for new power capacity.
Tian and James emphasized the potential for data centers to operate more flexibly — limiting the strain on the broader grid and curbing utility costs. Google, for example, partnered with Omaha Public Power District in Nebraska last year to reduce its machine-learning load during severe weather events. More recently, the tech company signed demand-response agreements with the utilities Tennessee Valley Authority and Indiana Michigan Power.
The two panelists also shared their hopes that long-duration energy storage will eventually be able to commercialize and scale, bottling up enough power from wind and solar farms to provide days’ worth of backup for data centers. Today’s lithium-ion batteries typically only last a few hours, though startups are making progress on medium-term systems that can provide eight to 24 hours’ worth of power.
Companies like Form Energy are trying to push the envelope even further. Canary Media’s Julian Spector spoke with Form’s CEO Mateo Jaramillo about the firm’s 100-hour, iron-air battery technology at last week’s SOSV Climate Tech Summit. You can watch the conversation here.
A correction was made on Nov. 10, 2025: This story originally incorrectly identified an image of the Blue Mountain power plant as an image of Fervo Energy’s enhanced geothermal pilot in Nevada. Fervo’s project sends power to Blue Mountain.
China is, without a doubt, leading global efforts to slash emissions from dirty industries, with more than 200 projects in the pipeline for producing lower-carbon chemicals, fuels, and building materials.
But the United States and dozens of other countries are still making progress on that front. Over 1,000 commercial-scale clean industrial plants — totaling roughly $2 trillion in investment — are in development or are operating globally, according to a new report from the Industrial Transition Accelerator and Mission Possible Partnership.
“There’s an opportunity for everyone in this clean industrial revolution in the making,” said Faustine Delasalle, who is both CEO of MPP and executive director of ITA.
MPP is an alliance of global climate and business groups. In 2023, the organization and its partners launched ITA at the COP28 climate conference in Dubai to advocate for increased investment in decarbonizing six key sectors: aluminum, aviation, cement, chemicals, shipping, and steel. Together, they represent roughly 30% of global greenhouse gas emissions.
This week, ahead of the COP30 summit in Brazil, the groups released the latest data, which includes about 300 more facilities than 2024’s report.
To date, only about 8% of the total projects are operational. Another 6% have reached a final investment decision — meaning they’ve secured all the necessary financing and approvals to start construction — while 7% appear “poised” to do so soon. The remaining 787 projects, or nearly 80%, have been announced but need to clear certain financial, technical, or regulatory hurdles before developers can break ground.
Delasalle said the pace at which these low-carbon facilities are coming online is still far too slow to meet global timelines for reining in planet-warming pollution. The on-again, off-again nature of national climate policy — see: the United States — and uncertain demand for cleaner fuels and metals make it challenging for developers to finance and build large, capital-intensive facilities.
Still, Delasalle said she expects the project pipeline to accelerate in the near term, particularly as other countries see China pull ahead in the race to clean up heavy industries. The country’s massive renewable-energy build-out and proactive industrial policies — including for green hydrogen — are fueling China’s early-mover advantage. Public disclosures of China’s projects are often hard to find, meaning the project-tracker report likely underestimates actual progress, according to its authors.
“There’s a growing realization that this is the direction of travel for industry, and that companies and the countries that do move will build their competitive edge,” Delasalle said. “And they are starting to do so.”
A clarification was made on Nov. 7, 2025: This story has been updated to clarify the breakdown of clean industrial projects that have reached a final investment decision versus those that are poised to reach that stage.
Former U.S. Rep. Abigail Spanberger will become Virginia’s new governor after a decisive win this week — and after a campaign that centered around rising power prices in the data-center capital of the world.
With Spanberger’s win, Democrats now control all branches of the state government. Virginia Democrats added more than a dozen seats to their majority in the House of Delegates on Tuesday; the Democrat-controlled Senate didn’t face an election.
That outcome may be a game-changer when it comes to preserving and enforcing the Virginia Clean Economy Act. Passed in 2020, the law requires top utilities Dominion Energy and Appalachian Power to achieve 100% renewable power production in the coming decades. Virginia’s Republican delegates and current Gov. Glenn Youngkin have blamed the legislation for rising power prices and pushed to repeal it, while state regulators have approved Dominion’s plans to build a raft of new gas plants in spite of the law.
The Clean Economy Act remains divisive even among Virginia Democrats. Spanberger has said that she’s committed to its long-term goals and to scaling up clean energy generation. But Democratic House Speaker Don Scott was reluctant to get into details about its future in a press conference this week, and didn’t deny the possibility of weakening its fossil-fuel restrictions, Inside Climate News reports.
The trifecta could also pave the way for Virginia to rejoin the Regional Greenhouse Gas Initiative, a collaborative of East Coast states that requires power generators to meet a set cap on carbon emissions or buy allowances to exceed it. States reinvest those proceeds into emissions-reducing projects and clean energy. Youngkin pulled Virginia out of the partnership two years ago, but Spanberger has promised to rejoin.
But there’s one piece of the clean-energy landscape where Spanberger’s win could be more problem than solution. Dominion is currently building what will be the country’s largest offshore wind farm, with support from Youngkin. That Republican backing could be why the Trump administration hasn’t targeted the Dominion array, while at the same time dealing blow after blow to offshore wind projects in blue states.
Climate action wins in elections big and small
It wasn’t just Virginia: Democrats swept statewide races across the country this week. In New Jersey, U.S. Rep. Mikie Sherrill campaigned on a promise to rein in rising power prices, and, in contrast to her Republican opponent, showed support for offshore wind. Still, the state has no operational or under-construction offshore wind projects, and Sherrill will have limited power to counteract the Trump administration’s anti-wind policies, Canary Media’s Clare Fieseler reports.
In Georgia, Democrats beat Republican incumbents in two elections widely seen as referendums on rising utility bills. Peter Hubbard and Alicia Johnson will now take seats on the Georgia Public Service Commission, which oversees for-profit utilities and their requests to raise rates. And in New York City, Democratic candidate Zohran Mamdani — who tied climate action into his affordability-focused campaign — won the mayoral race.
Several other smaller races also have energy implications. Here are the results of a few:
Clean energy carries on
As the world prepares to meet in Brazil next week for the COP30 climate conference (sans the Trump administration), new reports show that clean-energy progress is still happening in defiance of White House opposition.
BloombergNEF took a look at the impacts of the One Big Beautiful Bill Act, which rolled back federal incentives for clean energy. The legislation will slow solar, wind, and storage deployment over the next few years, BloombergNEF predicts, but growing power demand will ultimately lead renewables to rebound after 2028.
And while the world remains far off track to meet the Paris Agreement goal of limiting global warming to 1.5 degrees Celsius above pre-industrial levels, it’s still making progress. A United Nations report projects the impact of many countries’ new, bolstered emissions-reduction commitments, and finds they’ll limit warming to around 2.5°C this century if fully implemented. It’s not ideal, but it’s still a win from previous reports that forecast as much as 5°C of warming through 2100.
The coast is (somewhat) clear: The U.S. Interior Department removes the Atlantic coast and a portion of the Gulf Coast around Florida from Trump’s plan to expand offshore oil and gas drilling, after opposition from local Republicans. (Politico)
Take another look: A federal court ruling is forcing FEMA to fully study whether installing distributed solar and batteries makes more sense than hardening Puerto Rico’s existing grid and repairing fossil-fuel plants in the wake of recent hurricanes. (Canary Media)
Fixer-uppers: The Trump administration announces a $100 million program for operators to refurbish aging coal plants and retrofit facilities to run on natural gas. (E&E News)
Diving deep for clean heat: A 75-year-old gas-powered steam-heating network in Boston and Cambridge is transitioning to electric boilers and heat pumps that draw thermal energy from the Charles River, even in winter. (Canary Media)
Lingering shutdown impacts: The U.S. Senate will vote today on a framework to reopen the government, but funds that help low-income families pay for heating will likely still be delayed for several weeks even if the shutdown ends. (E&E News, E&E News)
Energy Star saved? EPA Administrator Lee Zeldin is quietly reconsidering plans to end the Energy Star program, and the agency has renewed contracts with the firm that administers it. (New York Times)
Coal-country dilemma: Navajo Nation citizens and officials debate the future of the coal industry in the Southwest, weighing the economic benefits against the environmental and human health impacts. (New York Times)
Xcel Energy’s sprawling Sherco Energy Hub will be among the United States’ biggest solar farms when the last of its three approved phases powers up next year. Soon after, the central Minnesota site could also host one of the Midwest’s biggest battery clusters.
In a Halloween filing, Xcel asked the Minnesota Public Utilities Commission for permission to double its planned battery capacity at Sherco while adding a 200-megawatt fourth phase of solar there and deploying about 136 MW of batteries at a separate site southwest of Minneapolis.
The push to build even more clean energy was spurred by rising electricity demand and the looming phaseout of federal clean-energy tax credits under the Trump administration, which has worked to hamstring renewables while attempting to boost coal and gas generation.
If the commission approves Xcel’s proposal, Sherco would host 910 MW of solar and 600 MW of battery capacity by the end of the decade. At peak production, that would go a long way toward offsetting the output of what Xcel representatives have called the “backbone” of the company’s Upper Midwest generation fleet: the roughly 2,300-MW Sherco coal plant, which shut down its first unit in late 2023 and is set to fully retire in 2030.
George Damian, director of government affairs for Clean Energy Economy MN, said the proposal underscores the growing importance of batteries as the grid shifts away from fossil fuels.
“As demand continues to rise, technologies like battery storage are becoming essential to maintaining reliability while integrating more carbon-free generation,” Damian said.
Xcel regional president Bria Shea agreed, saying in a statement that “[w]e’re making a significant investment in battery storage because we see it as a critical part of Minnesota’s energy future.”
The separate 136-MW Blue Lake project would replace retired fossil-fuel capacity, too, boosting output at what’s now a 332-MW gas peaker plant. Xcel retired Blue Lake’s aging oil-fired units earlier this year, leaving two newer gas units operating and freeing up more than 200 MW of grid interconnection capacity.
Minnesota requires its utilities to procure 100% clean power by 2040 and aims to decarbonize its entire economy by 2050, with ambitious targets for building and transport electrification. Meanwhile, developers have proposed at least a dozen large-scale data center projects around the state, including several in Xcel territory. In December, Xcel executive Ryan Long — then serving in Shea’s role — said the company could absorb 1.3 GW of data center capacity by 2032 without derailing its carbon-free power plan, though he added it may need to extend the life of some gas plants to accommodate the load increase.
In the filing, Xcel said it wants to move quickly to expand its generation capacity while there’s still time to qualify for federal clean-energy tax incentives of 30% or more.
President Donald Trump’s One Big Beautiful Bill Act will sunset those incentives several years early, forcing most wind and solar projects to begin construction before July 4, 2026, to qualify for the full value. Energy storage projects qualify for the full credit value through 2033, but Xcel said uncertainty around new foreign-sourcing restrictions taking effect next year increases the urgency to deploy storage soon too.
Xcel says it expects to break ground on the Sherco and Blue Lake battery installations next year and power them up in 2027. It aims to commission the Sherco solar project by 2029.
Rather than contract with independent solar and battery installations in its territory, Xcel wants to build and own all three projects itself. In the filing, it said rules set by Minnesota’s grid operator require company ownership of new energy facilities reusing interconnection rights at retiring power plants. The same filing asks the commission to approve agreements to purchase power from several third-party solar and battery projects that will connect to the grid elsewhere.
John Farrell, the Minneapolis-based codirector of the Institute for Local Self-Reliance and a frequent critic of the monopoly-utility model, said the looming tax-credit cliff creates an unusual circumstance where the need to quickly develop more clean energy cuts against his preference for an open and competitive bidding process that could result in a better deal for electricity customers.
“I am more sympathetic than I would be normally because we are stuck in the regime we’ve got and there’s a lot of money on the table,” he said, referring to the tax credits whose rollback is expected to raise Minnesotans’ electricity bills in the coming years.
To incentivize faster clean-energy deployment ahead of the cliff created by Trump’s megalaw, the Minnesota Public Utilities Commission in August said it would allow projects that meet the deadline for federal tax incentives to also access extended eligibility for state renewable energy credits.
Xcel spokesperson Theo Keith said the utility has “already taken steps to ensure this portfolio of projects will qualify for federal tax credits before they expire.”
But with the North American Electric Reliability Corp. forecasting a “high risk” of capacity shortfalls on the Upper Midwest grid by 2028, there’s a chance that the U.S. Department of Energy issues an emergency order requiring one of the Sherco plant’s two remaining coal units to run past its planned retirement next year, said Allen Gleckner, chief policy officer for Minnesota-based Fresh Energy.
The DOE has already done so for one retiring coal station in the Midwest, Michigan’s 1,420-MW J.H. Campbell plant. Its operator, Consumers Energy, says that order, which runs at least through Nov. 19 and which the DOE says it could extend for much longer, has already cost consumers at least $80 million. It’s unclear whether a similar order at Sherco would affect Xcel’s battery plans, but it would be disruptive to the utility either way, Gleckner said.
“The uncertainty that scenario contemplates is another reason why it would be a terrible idea,” Gleckner said.
Asked if Xcel had reason to expect a DOE emergency order at Sherco and whether that could interfere with its proposed clean-energy deployments there, Keith said only that Xcel is moving ahead with its plans to retire the coal units by 2030.
“We are in regular conversations about Minnesota’s energy future with various stakeholders, including federal, state, and local elected officials,” he said.
Two years ago, the Biden administration announced $7 billion in funding for a nationwide network of hydrogen hubs meant to kickstart production of the alternative fuel.
Now, the Trump administration has cast doubt over the future of the program — including the Appalachian Regional Clean Hydrogen Hub, or ARCH2, which features projects in Ohio.
Despite the turbulence, industry leaders said they see a bright future for hydrogen in Ohio.
“We’re building businesses in this state regardless of that federal funding,” said Bill Whittenberger, executive director of the Ohio Fuel Cell and Hydrogen Coalition, at the group’s 2025 symposium, held Oct. 27 and 28 at the Honda Heritage Center in Marysville, Ohio. In his view, federal funding “makes things go a little faster, [but] there’s a strong business case for all the things we’re doing here.”
Many see hydrogen as necessary for decarbonizing hard-to-electrify operations, such as steel and glassmaking, as well as some transportation sectors.
Today, however, few industries use the fuel at a meaningful scale — and very little low-carbon hydrogen is available.
The Biden administration’s hub initiative meant to change that by bringing down the cost of low-carbon hydrogen, which can be produced with renewable energy, nuclear power, or natural gas with carbon capture and storage.
The initiative sparked detailed planning for dozens of projects throughout the hub regions. In Ohio, proposals took on different shapes: One developer wanted to use solar power to make hydrogen for buses in Stark County, while another planned to derive the fuel from a chemical plant’s waste stream. Still others looked to expand storage and refueling operations in central and northeastern Ohio.
The Biden administration’s Inflation Reduction Act also created a lucrative federal tax credit for clean-hydrogen projects, an incentive that successful lobbying preserved through the end of 2027 in Republicans’ massive budget bill signed into law in July. But even with this federal support in place, the nascent industry has been on shaky ground. Some high-profile green-hydrogen projects were already floundering before this year.
The Trump administration’s October cancellation of federal dollars for two of the hubs that focused on hydrogen from renewable energy raised urgent questions about the viability of many hydrogen ventures nationwide.
The fate of the other five hubs remains uncertain. Last month, their names appeared on a leaked Energy Department list alongside a note to “terminate,” but the DOE has not confirmed their status.
Still, conference attendees emphasized, some hydrogen projects are moving forward in Ohio.
There’s the plan from American Electric Power’s Ohio utility to power data centers with fuel cells, for example. It’s part of a broader AEP partnership with Bloom Energy to acquire up to 1 gigawatt of fuel cells to help the giant computing facilities get online faster.
“Speed to power trumps all other things,” said Amy Koscielak, a senior business development leader for AEP.
At the outset, though, the systems planned in central Ohio for Amazon Data Services and Cologix Johnstown will run on natural gas. Eventually, AEP has said, they could switch to run on hydrogen.
Earlier this year, the Public Utilities Commission of Ohio green-lit plans for AEP’s Ohio utility to provide the systems’ output exclusively to those customers, although appeals are pending.
Hydrogen also features in vehicle offerings from American Honda Motor Co. Although its hybrid cars that can use either hydrogen or battery electric power are built in Marysville, most of them go to California.
In general, battery-powered electric vehicles are probably the best option for “small mobility,” said Gary Robinson, vice president of sustainability and business development for the company. Indeed, hydrogen cars remain niche at best. But “trucks, buses, industrial equipment — all of those things, in our opinion, are perfect candidates for hydrogen,” Robinson said. The company is exploring shipping and aviation as other potential markets for fuel cells.
Ohio also has a few projects looking to harness electrolysis — a process that uses electricity to separate water molecules into hydrogen and oxygen. If the electricity that feeds into electrolysis is clean, the resulting hydrogen is clean too.
Dayton-based Millennium Reign Energy supplied electrolyzer equipment to provide initial fill-ups for the fuel-cell hybrids that Honda has made in Marysville since last year, and it has provided fueling equipment to other locations in the United States and abroad. The company plans to add two fueling stations for its Emerald H2 network in the Dayton area by April, CEO Chris McWhinney told Canary Media.
Plug Power also relies on electrolyzers to produce its hydrogen. The 28-year-old company’s first big order back in 2007 was for fuel cells to power pallet trucks at a Walmart distribution center in Washington Court House, Ohio, said Mike Ahearn, vice president for North American service. He did not talk about projects the company would do as part of ARCH2, if it moves ahead, but he did describe work outside of Ohio.
Plug Power remains on track to start construction next year on a wind-powered hydrogen plant capable of producing around 45 tons per day in Graham, Texas. “We are on a good trajectory,” Ahearn said, adding that the company’s goal is to turn a profit next year — something it hasn’t done yet over its almost three decades in operation.
Independence Hydrogen, another ARCH2 project-development partner, concentrates on local hydrogen production and distribution. While federal funding remains uncertain, the company still hopes it can move ahead with the Ohio project that would be part of the hub.
The company’s method of making the alternative fuel doesn’t fit neatly on the “hydrogen rainbow” that indicates whether production relies on renewable energy or fossil fuels.
Rather, the source would be an industrial waste stream from the INEOS KOH plant in Ashtabula, Ohio. The plant makes potassium hydroxide and other chemicals, and releases a waste stream that is almost all hydrogen. Independence Hydrogen would basically “clean up” the gas by removing water and other impurities and then compress it for transport.
But “I need an offtaker,” said William Lehner, chief strategy officer for the company. “We would love to provide that project.”
Indeed, most companies at last week’s symposium would love more customers, but it’s unclear how quickly interest in the alternative fuel will ramp up if federal funding for ARCH2 and other hydrogen hubs remains in limbo and if tax incentives aren’t extended further.
The DOE’s “hydrogen shot,” launched in 2021, aimed to scale up the production of clean hydrogen and cut its cost to $1 per kilogram — an 80% reduction — by 2031. While developers would still cover at least half the project costs at the hubs, federal grants would have reduced total expenses and let them charge customers less for their hydrogen. The hope was that the lower prices would stoke demand.
The Trump administration’s actions to dismantle decarbonization policy also raise questions about clean hydrogen’s future. Without sticks that punish greenhouse gas emissions or carrots that make zero- and low-carbon fuels cheaper, a lot of projects face a difficult road ahead.
A longstanding federal tax credit for rooftop solar is about to expire, making it more expensive for homeowners to access cheap, clean energy — and sowing uncertainty for the companies that put photovoltaic panels up on roofs.
But a small Durham, North Carolina, company called EnerWealth Solutions sees a path forward — at least for the next two years. Its model is to buy rooftop solar panels with a tax credit still available to commercial entities and rent them to homeowners, passing along the savings.
It’s an approach that firms around the country can adopt as the beleaguered rooftop solar sector tries to weather the Trump administration’s assault on clean energy.
The leasing strategy could be particularly useful in places like North Carolina, where a robust solar industry has taken root but state policy support for home rooftop panels is waning. In early 2023, funding dried up for a popular rooftop solar rebate program run by Duke Energy, the state’s predominant electric utility. Later that year, Duke began lowering bill credits for customers who send their solar power back to the grid.
A sunny state of 11 million people, North Carolina is a leader on utility-scale solar but middling when it comes to residential solar adoption. Just over 55,000 homes are now equipped with rooftop panels, according to the U.S. Energy Information Administration, so the industry has ample room to grow.
“It’s so imperative that we’re opening every avenue to get these technologies into the hands of as many North Carolinians as possible,” said Matt Abele, executive director of the North Carolina Sustainable Energy Association, an advocacy group.
EnerWealth’s first residential leasing customer is one of the industry’s own. A certified public accountant and financial consultant for solar firms, Casey Gilley said installing an array on his Chapel Hill home is something of an unspoken requirement. “You can’t work in the business and not have solar,” he said. “Right?”
While his profession may not be entirely typical, Gilley is an average Tar Heel in other ways. He’s trying to do his part to reduce pollution and save energy. He wants to guard against coming electricity-rate increases. And forking over a down payment on a full-price solar array for his family of five was a no-go.
Plenty of people EnerWealth aims to serve fit that profile, says Brian Liechti, director of solar leasing. That’s why, until the end of 2027, when companies like his can no longer access the tax credit, the goal is simple: “Make hay and electrons while the sun shines,” he said.
Veterans of the solar industry say they’re used to the ebb and flow of policies designed to encourage homeowners to go solar. But there’s no doubt that they’ve had an especially hard year.
Most crushing was the passage of the One Big Beautiful Bill Act by President Donald Trump and the Republican-controlled Congress in July. The law eliminates the 30% tax credit for home solar at the end of this year, nearly a decade sooner than it was previously set to expire. The change is pushing sales to new heights, but a crash is expected once the incentive is gone in 2026.
The White House also clawed back $7 billion in grants intended to help low-income households go solar, including a $156 million initiative projected to benefit 12,000 families across North Carolina. The state’s Attorney General Jeff Jackson is among 23 attorneys general around the country suing the Trump administration for terminating the program, calling the move illegal.
The policy whiplash comes amid a difficult macroeconomic environment for rooftop solar. High interest rates and inflation have lingered for years, dampening interest in the sector among those without the cash to buy a solar array outright.
Despite these woes, North Carolina installers see a few bright spots.
For one, a Duke trial program called PowerPair, in which customers receive a rebate of up to $9,000 for investing in a battery along with a solar array, has seen thousands of enrollees since its launch in the spring of last year. The pilot has reached its limit in the company’s eastern and far western territory but still has room in the central part of the state.
What’s more, a 2017 state law creates a small crack in Duke’s monopoly. While agreements between homeowners and non-utilities for the purchase of electricity are forbidden as ever, the statute allows individuals to rent the use of solar equipment up to a certain cap. This provision has been little-used to date in the residential sector but is a cornerstone of the EnerWealth model.
Then, there’s a final puzzle piece for the company: the pro-solar policy that escaped the purge in the One Big Beautiful Bill Act. While incentives for individuals dry up Dec. 31, commercial entities can receive at least a 30% credit for investing in renewable energy through the end of 2027.
EnerWealth, then, can keep buying rooftop solar panels for another two-plus years, benefit from the credit, and then pass on some of the savings to its lessees. For now, the company doesn’t have to fear hitting the Duke solar leasing cap established in 2017. And customers who can cash in on the PowerPair battery incentive while it still lasts will see even more savings.
These federal and state incentives can come together to produce savings for North Carolinians, even in a tough time for rooftop solar.
Though Gilley might conceivably have borrowed money and installed his panels in time to use the expiring tax credit, he chose the EnerWealth lease model instead.
“I ran the numbers of ownership versus lease, and they were very similar,” he said. But what ultimately tipped the scales toward the latter was that it didn’t require a down payment or any ongoing costs. “I didn’t have to come up with any cash,” he said. “Also, I don’t have to worry about any maintenance or any problems for the next 25 years.”
PowerPair is still available in Gilley’s area, so he used the $9,000 rebate as a down payment on the battery and the solar system. He receives net-metering bill credits and still pays Duke for electricity — but about $210 less per month than before. Even with his $150 monthly payment to EnerWealth, Gilley is saving about $60 a month.
His rental payment for the equipment will step up 1.5% each year. “But electricity prices are going to escalate at a much higher pace than that,” he predicted. “So, my annual savings will only grow.”
When the residential tax credit expires in two months, homeowners who want to go solar will have an even easier choice to make: Finance their equipment over time at roughly 7% interest rates or rent it for about 25% less per year, thanks to passthrough savings from the tax credits.
“A lease is the only way to monetize the tax credit for residential systems,” EnerWealth’s Liechti said.
According to EnerWealth calculations, the lower lease payments on a $35,000 battery and solar array mean customers will save nearly $15,000 in overall electricity costs over 20 years. Even those who can pay for a system outright might choose a rental option, which spreads the costs out over time and produces monthly bill savings right away.
Meanwhile, in terms of customer experience, there’s little difference between renting and owning the panels and battery. Homeowners have a buyout option beginning in year seven. If they move, they can purchase the equipment and include the expense in the home’s sale price, or transfer the lease — and monthly bill savings — to the new owners.
While EnerWealth is breaking ground in the solar leasing market in North Carolina, other companies are sure to follow, said Scott Alexander, chief strategy officer for the company.
“We’re just one tool in the toolbox,” he said.
The EnerWealth model does have its limits. It’s only available in Duke territory, which covers most but not all of the state. It’s also much more attractive with the PowerPair rebate, which is soon to dry up and faces an uncertain future after that.
Most of all, the leasing economics will get a lot less appealing in two years, when the 30% tax credit runs out for commercial entities, too.
After that, Alexander said, “we have to innovate. We have to pivot. No business lasts forever. We’ve got two years.”
A correction was made on Nov. 6, 2025: An earlier version of this story mischaracterized the advantages of leasing rooftop solar and a battery versus purchasing a system at full price up front. The latter offers consumers more savings over the long term, according to EnerWealth’s calculations, while leasing provides the advantage of immediate net savings.
Zohran Mamdani surged to a historic victory in Tuesday night’s election for New York City mayor, riding a campaign that was laser-focused on halting soaring rents, improving mass transit, and rebuking President Donald Trump’s crackdown on immigration in a metropolis where more than one-third of the population is foreign-born.
The city’s skyrocketing electricity prices, however, received scant mention — even as utility rates animated races around the country, including Democrat Mikie Sherrill’s gubernatorial victory in New Jersey. Despite kicking off his career as a state lawmaker in 2020 by fighting to close the city’s fossil-fueled peaker plants, Mamdani, a 34-year-old democratic socialist, made little hay about climate change at all during the campaign.
Yet the next mayor of the nation’s largest city inherits a world-leading experiment in retrofitting buildings to slash emissions, open questions about how to transition to cleaner power sources, and a patchwork of adaptation efforts meant to protect aging infrastructure from mounting deluges.
The most significant climate policy under the mayor’s purview is a statute called Local Law 97. Passed in 2019, the law requires buildings over 25,000 square feet to slash emissions 40% by the end of this decade and to reach net-zero by 2050. To do so, the nearly 50,000 buildings that qualify must swap oil- and gas-fired heating systems for electric heat pumps.
When the first phase of the law came into effect last year, just 8% of the buildings covered needed to make upgrades to comply, estimated the Urban Green Council, a nonprofit focused on building decarbonization. But more than 50% of buildings will need to make changes to hit the 2030 emissions target.
“That’s a lot,” said John Mandyck, the Urban Green Council’s chief executive. “There’s a lot the next mayor is going to have to do.”
Among the law’s biggest opponents were co-op buildings, condos, and landlord associations that said compliance would cost too much. One anti-Mamdani PAC, as New York Focus reported, sought to make the law a defining issue in the race, saying the candidate from Queens would only raise the price of bringing buildings into line.
In a policy proposal, Mamdani said he would lobby Albany to extend a general tax break that helps middle-income co-op and condo owners pay for building renovations, and to reduce the fees to apply. He also vowed to staff up the agencies in charge of helping building owners navigate the rules. He said in a mid-October debate that he’d heard “from so many” that “it’s cheaper to pay the fine than to actually get into compliance.”
The city could also lower costs by finding a way to purchase heat pumps and other appliances in bulk, Mandyck said. Last year, the New York City Housing Authority agreed to buy 10,000 state-of-the-art induction stoves for apartments in the nation’s largest public housing system, and the state kicked off a new contest shortly after for heat pumps. At the debate, Mamdani said he would look to NYCHA as a model.
But Mandyck said, while the NYCHA programs are “off to a great start,” they’re still only pilot projects.
“That can be part of the solution,” he said. “But there needs to be some new entity, whether an authority or something, that would find a way to do bulk purchasing to aggregate to the market. This is a huge market.”
Yet the buildings covered under Local Law 97 represent just about 5% of the city’s total skyline.
“There’s 950,000 other buildings in New York City,” Mandyck said. “We’re going to have to think about how we help the smaller buildings decarbonize, too.”
To electrify the entire city without spiking emissions, New York will need more clean power plants.
Right now, the city depends on fossil fuels for more than 90% of its power. The mayor has limited say over the electrons that flow into the five boroughs, and the dense urban landscape leaves little space for solar and wind installations within the city. Mamdani’s one major clean-energy plan is aimed at adding solar panels to the roofs of schools, but even that would likely require approval from Albany while only meeting a fraction of local demand.
City Hall does, however, play a role in negotiating contracts for the city’s public institutions with the New York Power Authority, the state-owned utility.
Roughly one-fifth of the power NYPA sells statewide goes to public customers in the city. New York Gov. Kathy Hochul, a Democrat, directed NYPA in June to work on building at least 1 gigawatt of new nuclear reactors in the state in the coming years, and the Mamdani administration could play a part in brokering a deal for those electrons. At the final mayoral debate, Mamdani said he considered a new nuclear plant “something worth exploring,” though he’s remained mum on nascent efforts to reconstruct the Indian Point power station that once provided about a quarter of New York City’s power.
Mamdani will also inherit a climate problem with more immediately tangible stakes than decarbonization: the need to update New York’s aging infrastructure to deal with increasingly extreme weather.
Routine rainstorms regularly overwhelm the city’s stormwater systems and cause deadly torrential flooding. Just last week, two men died in basements in Brooklyn and Manhattan amid heavy rains.
Since the devastation of Superstorm Sandy in 2012, the city has begun a series of adaptation projects totaling billions of dollars — but some less glamorous work has been underway for decades.
Take the New Creek stormwater project on the East Shore of Staten Island as an example. The project, championed by outgoing Mayor Eric Adams, a Democrat, is part of the Bluebelt Program that started on Staten Island in 1996 and transformed the city’s least populous borough into a testing ground for water-management infrastructure. The Department of Environmental Protection now plans to apply those solutions in Brooklyn, Queens, and Manhattan. Five of the 19 project sites are fully complete, and the rest are on track to be finished in the next five years, said Robert Brauman, deputy chief of Bluebelt operations at the agency.
On a sunny Wednesday morning, roughly 12 hours after Mamdani delivered a trumpeting victory speech, Brauman stood atop a concrete structure overlooking the large freshwater stream known as New Creek. Just a few years ago, it was a trickle running through a corrugated culvert under a quiet stretch of the Midland Beach neighborhood that would, in bad weather, turn into a torrent. Today, however, the water travels through a carefully regulated S-shaped pipe system, allowing New Creek to keep stormwater from flooding the surrounding neighborhoods. The city’s Department of Environmental Protection combed over 19th-century botanical records to select plants native not just to the five boroughs but to Staten Island specifically to flank the body of water.
“That prevents flooding downstream, and it gives all the plants we installed time to clean the water, so the native wetland vegetation can suck up nitrogen and phosphorus and everything else and clean the water before it goes out,” said Brauman. “That’s perfect adaptation.”
After walking the perimeter of the project, he arrived at the dead end of Mason Avenue and stopped on the sidewalk. Between the curb and the asphalt of the street was a concrete path that looked like a hard version of the polygreen foam popular on children’s playgrounds. When Brauman poured a sip of coffee from a McDonald’s cup, the liquid spread for a moment, then started to disappear. The specially made porous pavement absorbs fluids, reducing how much liquid flows into storm drains during heavy rainfall.
“This is one of the first ones on Staten Island,” Brauman said. “The city is trying to incorporate it into more projects.”
Mamdani has yet to announce whether he’ll keep Rohit Aggarwala as the Department of Environmental Protection’s commissioner. But Brauman said he’s confident projects like this will continue either way, even if Mamdani had little to say about adaptation on the campaign trail.
Mandyck said the Urban Green Council plans to think through potential policy proposals in the coming months for how to better organize and grow the city’s efforts.
“It’s clear we need to take adaptation more seriously,” he said. “There are a lot of good things going on right now in New York, but they’re a little decentralized.”
In the depths of the 75-year-old Kendall Cogeneration Station along the Charles River in Cambridge, Massachusetts, a clean-heating transformation is underway.
For years, the facility has burned natural gas to produce steam for Boston and Cambridge’s century-old underground heating system. Now, it’s aiming to become a clean “district energy” system, capable of delivering warmth during bitter New England winters without baking the planet — a first for a citywide network in America.
Last year, Vicinity Energy, the owner and operator of the steam heating network, finished installing a 42-megawatt electric-powered boiler at the Kendall facility. Earlier this year, the company confirmed plans for its next step: installing a 35-megawatt industrial heat pump from Everllence, a German energy systems manufacturer formerly known as MAN Energy Solutions.
“That project was greenlit this summertime,” Vicinity Energy CEO Kevin Hagerty told Canary Media, and demolition to make way for the new heat pump has already begun.
“We’re anticipating that being completed midway through 2028. We’ll turn the heat pump on and turn the Charles River into a renewable energy resource,” Hagerty said.
The industrial heat pump will draw from the river water’s latent thermal energy to create boiling-point temperatures within the Kendall facility’s steam-generation complex. The technology will function even in the winter because the low-temperature refrigerant it uses is far colder than even the icy-cold Charles, creating a temperature differential that the heat pump can harness to produce steam.
All that steam flows through about 25 miles of piping to heat roughly 70 million square feet of buildings in Boston and Cambridge, including college campuses and biotech facilities. Vicinity has secured commitments to use the lower-carbon steam from its electric-powered heating systems from area customers such as Emerson College and life sciences real estate company IQHQ.
Hagerty said other “very large offtakers are underwriting this,” although he declined to name them. “The pump is not fully subscribed yet, but it’s getting there.”
The system will be among the biggest in the United States, which has roughly 900 district energy systems ranging from those in airports and on college campuses to the citywide steam network in Manhattan, the country’s oldest. District heating is also popular in European cities, where comparatively high fossil-gas prices are driving a more urgent embrace of large-scale clean-heating systems.
For customers in Cambridge and Boston, Vicinity’s “eSteam” plan makes sense for reasons of political economy, Hagerty said. Massachusetts has set mandates to expand its supply of carbon-free electricity and to reduce its use of fossil fuels in buildings. A preexisting, centralized system like the Kendall facility’s can convert to electric heat pumps and boilers far more cost-effectively than individual buildings could on their own, he said.
“It’s about one-half to one-fifth the cost for buildings to use our eSteam and electrify through the district energy system than it is for them to locally electrify and decarbonize,” Hagerty said.
Most of those savings come from the fact that the Kendall facility’s electric grid substation and steam pipe network are already built, he said. That obviates the need to retrofit individual buildings with electric heating — or for utilities to make distribution grid upgrades to accommodate a heat pump at every building.
District energy systems like Vicinity’s also benefit from economies of scale, Hagerty said. Large, centralized networks can mix and match mutually reinforcing technologies like electric boilers and heat pumps. They can recapture waste heat from other parts of the system and use it to make more steam, as is being done with the Kendall facility’s gas-fired electricity-generation turbine, which provides peak power and “black start” services for the local grid.
District energy systems can also store and shift energy, as Vicinity plans to do with the thermal energy storage that makes up the next stage of its eSteam conversion plan. It’s looking at systems that can convert electricity into heat storage, which would “allow us to relieve the stress on the electric grid and be a lot more flexible,” he said.
If anything, the Boston-Cambridge system is only starting to utilize the cost-effective decarbonization strategies that district energy systems enable, Hagerty said. Europe is leading the way on that front, with showcase projects such as the 70-megawatt industrial heat pumps now using the chilly water of the Baltic Sea as a thermal exchange to heat water to keep buildings warm in the city of Esbjerg, Denmark.
“They currently have the largest industrial-scale heat pump for district energy in the world,” said Alejandro Gorosito, U.S. national sales manager for Everllence, which provided the heat pump for the Danish city. It won’t hold that distinction for long, he said — Everllence is building a 150-megawatt heat pump for a similar project in Cologne, Germany.
In Europe, adoption of industrial heat pumps is helped along by the fact that fossil fuels tend to be more expensive than electricity. Because heat pumps are far more efficient than fossil-fueled options, they can be the most cost-effective choice when electricity is cheaper, Gorosito said — a fact that can push companies without climate goals to pursue the clean-heat technology.
In much of the United States, where fossil fuels are abundant and power prices are rising fast, the math doesn’t favor heat pumps, Hagerty conceded. But for Boston and other cities that require building owners to reduce their carbon emissions, and for states like Massachusetts that aim to decarbonize their economies, district energy systems can serve as a “regulatory hedge for our customers,” he said.
“They need to make decisions as to whether or not they’re going to heat their building with natural gas, because we’ve got regulations in place that are going to start enacting fines … Do they want to take the risk of spending millions of dollars on something that they may not be able to use in five to 10 years?”
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