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Last spring, when the Second Harvest Food Bank of Northwest North Carolina installed a giant solar array on its new headquarters in Winston-Salem, leaders of the project hoped it would inspire other nonprofits to follow suit.
Sure enough, it has done just that.
A 400-kilowatt solar array is now being built at the headquarters of Goodwill Industries of Northwest North Carolina, less than two miles from Second Harvest.
“They’re our neighbor,” said Bill Haymore, a longtime Goodwill veteran who has worn many hats and today serves as its chief sustainability officer. “We partner closely with them. So we watched with great envy at the work that they had done, and we followed the model that they set forth.”
The installation will produce enough electricity to power about 40% of the building, Haymore said, and will save the nonprofit over $1 million in energy bills over the coming decades. Those savings will be plowed back into Goodwill’s mission of providing employment, job training, and other opportunities for the community.
What’s more, the clean energy project itself falls squarely within his organization’s sustainability ethos. “The work we are doing in this arena is something that we’ve been doing for 100 years,” Haymore said. “Every time we take a donation, we’re recycling.” But, he added, “we need to be bolder about it and show the community that we’re committed to this work. The solar panels were just one of the things that we have elected to do to reduce our carbon footprint and to be a better steward.”
A behemoth international network, Goodwill is made up of 150 independent organizations, each with its own board of directors and priorities. While the Goodwill serving northwest North Carolina doesn’t have any carbon reduction goals yet, Haymore says the plan is to change that.
“This past year, we purchased carbon-tracking software to help us benchmark where we’re at,” Haymore said. “Once we feel very, very confident with what our carbon footprint is, we’ll be able to measure success.”
As did Second Harvest, Goodwill will reap a 30% tax credit in the form of direct pay — a mechanism established by the Biden-era Inflation Reduction Act that allows nonprofits to access the incentive, which was formerly available only to entities that pay income tax. The organization also hopes to get a 10% bonus credit since it, like the food bank, is located in a low-income census tract.
These levers, designed to help institutions with no tax liabilities and thin operating margins, remain intact at least through the end of next year — despite the axe that congressional Republicans took last summer to a host of clean energy inducements established or enhanced during the Biden years.
But last summer’s law did include new red tape: Beneficiaries of clean energy tax credits now must verify that no components of their new systems were produced by a “foreign entity of concern.” The requirement took effect at the beginning of this year, spurring Goodwill to contract for the project by Dec. 31. The installation is expected to be completed sometime this fall.
Both Goodwill and Second Harvest were recruited to go solar by the Piedmont Environmental Alliance, a local group that formed the Green Business Network to encourage businesses and nonprofits to install solar, electrify their vehicle fleets, and reduce food waste.
If there was a “silver lining” to last summer’s clean energy rollbacks, it was that “Second Harvest and others were feeling the pressure that these tax credits might not exist forever,” said Will Eley, director of the alliance’s green economy program. “They wanted to move as quickly as possible, and Goodwill was certainly responsive to that.”
Eley and his group have been a key force behind an array of initiatives in Winston-Salem and the surrounding region, including the newly launched “Electrify the Triad” campaign and a training program for clean energy jobs hosted at the Goodwill.
That’s why Eley is most excited about the fact that the solar panels will be installed by workers trained at the nonprofit.
“You can actually see the rooftop from the classroom that’s been used for that,” he said. “It’s the full circle of positive feedback loops. It’s been a lot of fun.”
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Mike Fleming was always interested in geothermal energy — how it works, how sustainable it is, and how efficiently it can heat homes and businesses. But Fleming, who has a decade of experience drilling wells in New England, didn’t see it as a career path.
That changed when his boss recommended him for a position at Phoenix Foundation Co. in late 2024. Part of the job involved overseeing drilling for geothermal projects. There were some differences between the roles, but there were plenty of commonalities, too. The technical skills, focus on safety, and need for precision are the same. And ultimately, “You’re making a hole in the ground, you’re putting some plastic pipe down there, and you’re sealing the hole,” said Fleming.
What felt routine at first is part of an emerging frontier in energy. Fleming’s work focuses on what’s called conventional geothermal, which requires drilling some 200 to 500 feet into the ground in search of subsurface earth that hovers between 50 and 60 degrees Fahrenheit — a temperature millions of residential heat pumps nationwide use to warm or cool homes year-round.
Geothermal provided about 0.36 percent of the country’s energy in 2024, by one estimate, but there are extraordinary amounts of it to be accessed at greater depths. Companies boring thousands of feet into the earth, a technique called enhanced geothermal, can reach rock as hot as 750°F — hot enough to power buildings, factories, even communities. That creates tremendous opportunities for oil and gas workers and others with drilling experience. As many as 300,000 people already possess the required skills, according to a 2024 U.S. Department of Energy report.
The Trump administration has looked favorably upon this renewable energy even as it has smothered wind and solar. The One Big Beautiful Bill Act preserved its tax credits through 2033, and the DOE recently announced $171.5 million for next-generation geothermal field tests.
It’s still too early to see a massive workforce transition, experts said, but they’ve seen evidence of growth. Another DOE report released in 2024 showed the domestic geothermal workforce inching up to 8,870 people. Globally, the industry employs around 145,000 workers. Many of those people simply go where the work is, fulfilling, say, a contract for an oil company before landing one with a clean energy outfit, said Cindy Taff, CEO of geothermal startup Sage Geosystems. “Drilling rig companies recognize this growth,” she said.
Taff spent 36 years at Shell. Frustrated that the oil behemoth wasn’t investing in geothermal, she co-founded Sage Geosystems in 2020. She sees a broad range of fossil fuel workers, from drillers to geologists, who will fit right into the renewables sector, arguing that the same industry that evolved from simple land wells to offshore operations in water thousands of feet deep has a vast pool of technical expertise. “What people tend to overlook is that the oil and gas industry over the last 100 years has really done a lot of innovative stuff,” she said.
One promising way to reach exceedingly deep rocks is by hydraulically fracturing them, running water through the path that eventually heats up and can be flashed into steam for power. Jonathan Ajo-Franklin, a geophysicist and professor at Rice University, said that there should be very little need to reinject large volumes of wastewater into the ground as a part of the geothermal fracking process. The oil and gas industry’s wastewater disposal has been linked to earthquakes in Oklahoma and West Texas.
Ajo-Franklin has worked with startups like Fervo Energy to conduct research on enhanced geothermal. He said that major oil companies “haven’t made big investments” in this area while they wait for the technology to be proven out. Nonetheless, he sees a lot of skill overlap between the fields.
Much of the U.S. oil industry focuses on extracting oil from rock that doesn’t naturally let it flow, he said. They’ve spent decades developing the technology and refining the complex techniques needed to maximize production — expertise readily transferable to drilling for heat.
Jamie Beard, executive director of the advocacy group Project InnerSpace, sees that potential and wants the Trump administration to back early-stage pilots. To build support, her organization hosted an event called MAGMA — short for Make American Geothermal More Abundant — last year to bring together industry leaders, policymakers, and Energy Secretary Chris Wright to make the case for next-generation geothermal. Wright expressed support for the industry.
In Beard’s view, there are a plethora of opportunities for geothermal, including powering data centers. “Oil and gas looks at that opportunity and says, ‘Well, hell, if we’re cranking out these projects and they’re natural gas, why can’t we crank out these projects and they could also be geothermal?’” she said.
Brock Yordy, founder of the Geothermal Drillers Association and a third-generation driller who started at 16, compares the transferability of drilling skills to hanging a painting. Walls made of brick, drywall, or wood might require a different bit, but “the base fundamentals are the same,” he said.
He sees this moment as an opportunity to get in on the ground floor of an exciting new line of work. “There’s not many jobs where you’re going to, by 500 feet, be drilling a piece of the subsurface that hasn’t been touched in 25,000 to 100,000-plus years,” he said. “It’s like being Indiana Jones. It’s exciting to think about.”
Lots of Americans are electrifying their cars and homes, enticed by the prospect of lower bills, cleaner air, and less planet-warming pollution. But all that new electric equipment creates a serious challenge: It requires bigger, better infrastructure to manage the increased flow of electrons, from the electrical panels in individual buildings to the transformers and power lines that make up the grid at large.
Pacific Gas & Electric, California’s largest utility, is testing a one-two punch of technologies that could let it and customers sidestep those expensive upgrades. The first are devices from smart-electrical-panel startup Span, which plug into utility meters and control when and how a home uses power, avoiding the need for higher-capacity panels. The second are the latest digital controls from smart-meter vendor Itron, which can ensure that the collective power demands of multiple customers don’t push local grid transformers beyond their limits.
Working in concert, these technologies could help individual customers avoid thousands of dollars of upgrade costs to electrify their homes, said Quinn Nakayama, PG&E’s senior director of grid research innovation and development. And if deployed at scale, they could allow the utility to delay billions of dollars in grid upgrades, which should help reduce rates for all its customers, he said.
To be clear, PG&E isn’t promising those results right away. The pilot with Span will start by installing the company’s meter-connected devices at PG&E employees’ homes in the coming months, with a larger rollout to volunteer customers envisioned for 2027, Nakayama said. And PG&E will upgrade existing smart meters with Itron’s technology at about 1,000 homes this year; if they’re cost-effective, the utility may seek to incorporate the capability in hundreds of thousands of customers’ meters through 2030.
“Our service planners, when they interconnect new loads, always have to imagine the worst-case scenario,” Nakayama said. “This enables us to give them the tools and the assurances that those worst-case scenarios will never occur.”
PG&E isn’t the only utility looking for ways to meet growing electricity demand without blowing out its grid budget. Utility rates are on the rise across the U.S., in large part because of the increasing cost of maintaining and upgrading the poles, wires, and substations that deliver power to customers. But PG&E is under particular scrutiny from lawmakers, given its steep electricity rate hikes over the past decade.
Utilities also want to sell more power across their wires. The more they can expand capacity for EVs, heat pumps, and other power-using devices, the more money they can bring in to cover the cost of new infrastructure. This, in turn, eases upward rate pressure for customers at large.
One way utilities could sell more power over existing wires is by tapping the capacity of virtual power plants — collections of rooftop solar and battery systems, EV chargers, appliances, and thermostats that can be controlled collaboratively to reduce grid strain. In recent years, PG&E has run multiple VPP pilots with EV chargers, and it launched a project with Span, Sunrun, and other vendors in 2025 to test how smart electrical panels and solar-charged batteries that customers have already installed could relieve local grid constraints.
However, utilities are loath to rely on novel technologies to replace tried-and-true grid upgrades. If a VPP doesn’t work, for example, local transformers or neighborhood substations can overheat and break down under increased stress. That’s why PG&E’s latest experiment is covering its bases with devices that can control excess power use both at the home and on the grid.
To moderate home energy use, PG&E is using Span’s latest smart-electrical-panel device, which is designed to plug directly into utility meters. The Span device can actively monitor and control household circuits powering air conditioners, refrigerators, and clothes dryers, as well as EV chargers, heat pumps, and other more advanced energy systems.
Adding a major new power draw to a home, like an EV charger, often requires an electrical panel upgrade, which can cost thousands of dollars and add weeks to months to an installation. It can also trigger an upgrade to the local grid, which can take months to complete and cost anywhere from several thousand dollars for replacing a transformer on an overhead power line to around $50,000 for digging up and replacing underground service transformers and power lines.
“Nobody wants to pay that,” Nakayama said.
But those upgrades are predicated on the assumption that the new EV chargers will be drawing maximum power at the same time that all the other homes in the neighborhood are maxing out their electricity use, stressing their shared grid infrastructure. That’s usually during hot summer afternoons and evenings when air conditioners are running full tilt.
Span’s tech allows PG&E to offer those customers an alternative, Nakayama said: Let the smart device curb grid stress by reducing charging speeds during those peak hours. Most EVs require only several hours to recharge their batteries, giving them time to ease off on charging for a while yet still fill up overnight.
“I think most people are OK if their car charges a little bit slower, as long as it charges by 6 in the morning,” he said. That’s called managed charging, a concept that utilities across the country are exploring as they prepare to handle millions of new EVs coming online over the ensuing decades.
Span’s software also lets customers set other parameters to keep their total household electricity use below those limits, like delaying clothes dryers until later at night or easing off on air conditioning, Nakayama said. These kinds of technological solutions are going to be important for the more than 600,000 of PG&E’s roughly 5.5 million customers that the utility expects to need some kind of electrical service upgrade in the next 10 years to meet state electrification goals.
Span CEO Arch Rao said the company is working with other utilities interested in using its equipment for similar purposes. “A lot of the technical validation work has already been completed,” he said. “It’s now about customer recruitment and enrollment.”
So that takes care of individual homes. But how can PG&E ensure those controls are actually relieving local grid stress? That’s where Itron’s smart meter technology comes in, Nakayama said — or more specifically, Itron’s latest chipsets, which can be plugged into the smart meters that PG&E has already installed.
Like traditional utility meters, smart meters track a home’s electricity usage. But they use onboard computers and wireless networks to upload those readings to utilities, rather than requiring employees to come by to check the readings once a month. U.S. utilities have deployed nearly 120 million of these smart meters over the past two decades.
In utility parlance, smart meters are known as “advanced metering infrastructure,” or AMI. Older “AMI 1.0” technology can do some advanced tasks, like detect power outages and communicate via wireless networks with other meters and the utility. But it lacks the computing power and real-time capabilities to do more complex things, like actively communicate with and control devices in homes and businesses.
Enter Itron’s latest “AMI 2.0” technology. If AMI 1.0 is like a flip phone, AMI 2.0 is more like a modern smartphone, capable of uploading applications that can undertake the novel tasks that PG&E is now exploring.
In other words, “the meter is no longer just a meter — it’s a controller,” said Nick Tumilowicz, head of Itron’s distributed energy management solutions business. The company’s AMI 2.0 technology has already been controlling Level 2 EV chargers at hundreds of PG&E customers’ homes through a pilot project launched in late 2024, he said. Itron has used the same technology to manage school bus charging in New York City and Tesla Powerwall batteries for Colorado utility Xcel Energy.
Smart meters can also do something that in-home devices can’t, Nakayama said: communicate with all the other meters in the neighborhood to check how their shared electrical loads are impacting the transformers they’re connected to.
All those meters are linked in a wireless network and “speak the same language,” he said. Once an AMI 2.0 meter is connected, “it has the ability to say to its surrounding AMI 1.0 meters, ‘We’re all on the same service transformer,’” he said. “And it can do simple math, and figure out what that service transformer limit is,” as well as determine much demand the transformer faces from homes.
The tech then feeds that data back to the EV chargers and electrical panels that are linked to the AMI 2.0 meter, he said. For instance, if other nearby homes are using more power than usual and stressing the local transformer, PG&E could direct those smart panels and EV chargers to throttle power.
Finding ways for neighborhoods to electrify without crushing the grid will require a lot more solutions like these, said Ben Hertz-Shargel, global head of grid edge at research firm Wood Mackenzie.
“There is so much risk — and so much opportunity — on the distribution system. If electrification happens in an unmanaged way, it will be extremely expensive,” he said.
On the other hand, utilities have to make sure the technologies they’re deploying don’t add more costs than the benefits they deliver, Hertz-Shargel said. For example, PG&E’s new pilots are funded through state grants, and the utility will need to prove their cost-effectiveness before asking regulators to let it charge customers at large to deploy them more broadly as part of a rate case.
That evidence is particularly challenging to come up with when trying to avoid upgrades to the low-voltage network that brings power directly to houses, since most utilities don’t have solid details on that part of the grid.
“The problem is that utilities don’t have good data on these assets below the substation,” Hertz-Shargel said. “These devices need to not only solve the thermal overload problem but provide the ground-truth data to prove that they’re solving the problem — such as that the transformer stayed well below its power rating.” If that evidence is lacking, these technologies will be a harder sell to planning teams, he said.
“It’s smart for PG&E to try these different solutions,” Hertz-Shargel said. “I think the ones that survive will be the ones that are most cost-effective.”
Breaker boxes can be a hidden stumbling block for households looking to go electric. Many of these devices are too small to support the electrical needs of a home plus the addition of an EV charger, a heat pump, and other power-hungry appliances. But upgrading them can take lots of time and money.
Smart electrical panels — smartphone-controllable versions of the electromechanical devices found in most homes — could help solve this problem. While more expensive up front than the old-school gear they’re replacing, smart panels don’t require complicated utility upgrades — and they may be able to save homes and businesses money in the long run.
Leading smart-panel startup Span and major electrical-equipment manufacturer Eaton just announced a strategic partnership to try to boost adoption of the devices. Eaton will also make a $75 million investment in the San Francisco–based startup, which has now raised a total of nearly half a billion, including a $176 million Series C last month.
Eaton, which reported $27.4 billion in revenue last year, will tap its extensive distributor and installer networks to promote Span’s devices. These range from sleek, iPhone-shaped electrical panels aimed at high-end homes with complex electrical-management needs to devices designed for smaller homes, multifamily buildings, and small commercial properties.
Eaton also makes its own version of smart controls in the form of digital circuit breakers, which are the individual devices that plug into slots in standard electrical panels to prevent household circuits from overloading. Those AbleEdge devices are used in control systems from home battery vendors including Tesla and Lunar Energy, and are a core building block of Eaton’s “home as a grid” business strategy, Paul Ryan, vice president and general manager of the company’s energy transition business, told Canary Media.
“Homes are becoming more electrified. EV adoption continues to increase. That all puts a stress on the home and on the grid,” he said. “We have to manage our power more effectively.”
Homeowners who want to electrify may need to upgrade their electrical panels or pay for even more expensive utility-grid upgrades. Instead, smart panels and circuit breakers can actively shift and throttle appliances — like EV chargers and clothes dryers — to keep loads within safe limits, saving tens of thousands of dollars per home, Ryan said.
The smart panels can also generate savings if they’re used to manage the flow of power from rooftop solar panels, batteries, and backup generators on household circuits, he said. Currently, that job is performed using complicated combinations of traditional electrical gear.
These potential benefits have driven a wave of companies to invest in the sector. Along with Eaton and fellow electrical-equipment manufacturers Schneider Electric and Leviton, these include startups like Lumin and vendors of solar energy systems, batteries, and backup generators like FranklinWH, Generac, and Savant.
Span’s smart electrical panel was one of the first to hit the market in 2019, and the first to earn certification under the UL 3141 power control systems standard offered by Underwriters Laboratories, the premier standards-setting body for electrical equipment. Before Eaton, the company had also picked up partners including leading U.S. residential solar and battery installer Sunrun, utility smart meter and communications giant Landis+Gyr, and major U.S. homebuilder PulteGroup.
Span CEO Arch Rao told Canary Media that the startup will continue to operate independently while co-branding its smart panels under the Eaton label.
“They’ve come onboard not just as an investor but as a key partner for scaling our products in the market, particularly in the residential ecosystem,” Rao said. “We’re able to support electrification of all types of existing homes with main-panel replacement, subpanels, load controls, EV charging, and heat pump integration.”
Just as important, Ryan said, Eaton has “expansive manufacturing capabilities and a very strong supply chain. We’ll be collaborating together to help drive down the cost of these solutions and make it more affordable.”
That last point addresses the big question mark for smart panels and circuit breakers: cost. Span’s marquee smart panel retails for about $3,500, well above the $1,000 to $2,500 all-in cost of installing a traditional electrical panel.
In general, digitally enabled panels and circuit breakers cost roughly twice as much as old-fashioned electromechanical equipment does. The price differential has been a barrier to more widespread adoption of these kinds of products, which have already seen one major contender exit the market. Schneider Electric, the French electrical-equipment giant that competes with Eaton in global markets, recently discontinued its Schneider Pulse smart panel.
Other technologies could well offer a cheaper route to doing what smart electrical panels do, according to Ben Hertz-Shargel, global head of grid edge at research firm Wood Mackenzie. In a 2024 opinion piece, he highlighted options ranging from next-generation utility smart meters to controls embedded in EV chargers, batteries, and electric appliances themselves.
“Low-cost smart meters with plenty of compute [capacity] are being deployed at scale today,” Hertz-Shargel told Canary Media in an interview this month. “The question is, do we need more dedicated energy hardware in the home? The lowest-cost solution will always rely on software. It seems a smart meter and an EV charger, or a battery, are the only devices you need.”
Rao pushed back on that proposition. While individual devices can throttle their power use, smart panels offer a more holistic way to oversee and control a home’s overall power demands, he said.
And utility smart meters are “not purpose-built for avoiding a service upgrade, or for adding new electrical loads to your home, most of which require not just sensing, but real-time controls,” Rao added.
Span has been working with a number of utilities, including Pacific Gas & Electric in California, that are interested in using its technology in concert with smart meters and grid control platforms for the additional home device-management flexibility it offers, he noted.
Span and Eaton also plan to launch “joint solutions” that combine both companies’ technologies in the second half of this year. “There are obviously a lot of interesting opportunities for technology partnerships,” Rao said, though he declined to provide details.
When rockets blast off Earth, they rely on tiny metal powders to help propel them into space. Now, an emerging group of startups and scientists is hoping to harness these particles for something more terrestrial: producing carbon-free energy for factories.
Powdered iron can be combusted in industrial boilers to supply the hot water and steam needed to produce everything from beer and baby formula to paper and plastic resins — without directly emitting carbon dioxide. The concept is about a decade old, but companies are just starting to make serious inroads to put the technology into practice.
Last week, the Dutch startup Renewable Iron Fuel Technology, or Rift, said it raised almost 114 million euros ($131 million) in private financing and public grants to develop its first commercial project, making it a front-runner in the space. Rift already operates two pilot units in the Netherlands. With the new investment, the firm plans to build a fuel-production plant and deploy its boilers in about 10 industrial facilities in Europe, the first of which is set to fire up in 2029.
“This represents a concrete step toward decarbonizing industrial heat at scale,” said Mark Verhagen, CEO of the Eindhoven-based Rift.
Around the world, most factories burn fossil fuels to get the heat they need for industrial processes, which is why the sector accounts for more than one-third of energy-related CO2 pollution globally. Rift estimates that its current system can reduce emissions by almost 80%, on a life-cycle basis, when compared with those of a fossil-gas-fired boiler.
The startup is seeking to scale at a pressing time in the European Union, where manufacturers are facing tighter restrictions on emissions and new policies aimed at shifting factories toward cleaner heat sources. The region is also grappling with ballooning gas prices caused by Russia’s 2022 invasion of Ukraine — and now the U.S. and Israel’s war on Iran.
Rift’s approach replaces gas with iron, a highly energy-dense and abundant element that is ground down to resemble sand.
The startup begins by putting iron powder in a specialized boiler, then injecting air and making a little spark that yields a big flame. As the iron burns, it produces heat that can be used directly for manufacturing or district-heating networks. To start, Rift is focused on supplying medium-temperature heat, of around 250 degrees Celsius (482 degrees Fahrenheit).
“The only product that remains are the ashes,” Verhagen said.
Rift will initially use a small amount of virgin iron powder, sourced from industrial suppliers. But the goal is to continually recycle the ashes — which are pure iron oxide — to make new fuel. When combined with low-carbon hydrogen, iron oxide splits into water and iron powder, the latter of which will be returned to the boiler.
As a technology, iron fuel has plenty of hurdles to overcome before it can replace gas in factories. Researchers are still improving the iron-combustion process and the techniques for collecting iron oxide. Companies need to build up supply chains for sourcing and recycling iron powder. And using green hydrogen — the kind made with renewable energy — for fuel production remains challenging, given that supplies are limited and costly.
Developers also need to bring down their production costs in order to compete with the incumbent fossil fuels. Rift, for its part, is working to improve its economic performance with the buildout of its first commercial project, Verhagen noted. The company says it can currently deliver iron fuel for a price of 140 euros per metric ton.
The investment round announced on March 3 includes more than 83 million euros in Series B funding, led by the Dutch pension fund PGGM, as well as a grant of nearly 31 million euros from the EU’s Innovation Fund. Rift had previously raised 11 million euros from investors in 2024, which enabled it to conduct durability tests at its two pilot projects.
“We have closely followed Rift’s development and see strong potential for tangible industrial impact,” Tim van den Brule, investment director at PGGM Infrastructure, said in a press release. “Many industrial innovations stall in the transition from demonstration to realization,” he added, which is why the firm is providing Rift with capital “through to execution.”
Rift is not alone in this fledgling field. Other players include the Dutch startup Iron+ and the Canadian firms Altiro Energy, FeX Energy, and GH Power, along with Ferron Energy in Australia and Fenix Energy in France.
The companies can all trace their roots to early research efforts led by Philip de Goey from Eindhoven University of Technology and Jeff Bergthorson from Montreal’s McGill University. The professors were inspired to pursue metal fuels for energy purposes after observing how powders burned at the European Space Research and Technology Centre in the Netherlands. In particular, they saw iron powder as an appealing alternative to gaseous hydrogen fuel — which has been held up as a more direct replacement for fossil gas but is difficult to store and transport.
In 2020, Eindhoven researchers and students, including Verhagen, built their first 100-kilowatt iron fuel boiler at a nearby brewery. That year, Rift spun out of the student team, with support from the Bill Gates–led Breakthrough Energy Fellows program. The startup later launched a 1-megawatt system that provides heating to some 500 homes in the Dutch city of Helmond; it operates another pilot unit at a cleantech park in Arnhem.
In 2025, Rift signed its first customer contract with the Dutch firm Kingspan Unidek, which makes building insulation and plans to install an iron-fueled boiler at one of its plants.
Verhagen said that, as well as with slotting into existing operations like Kingspan’s, the technology could also work alongside other types of clean-heat solutions that are gaining momentum globally, such as thermal batteries, which store electricity to provide on-demand heat, and highly efficient industrial heat pumps.
Iron fuel could serve as the “baseload” source that supplements electrified technologies, or that kicks in when electricity prices are high or otherwise constrained. “We see that there’s a unique fit” for Rift’s system, he said.
After Susan Lindsay got rooftop solar panels installed on her home in Greensboro, North Carolina, she wanted the low-income households she visited as a parent educator to be able to do the same — but without the expense.
“I realized how hard that would be for any of these families I was working with, but also how quickly it reduced my energy burden,” she said. “I started looking around for people trying to get clean energy into the hands of people who don’t make as much money.”
Soon, Lindsay found a coalition of groups working to solarize their communities. The basic concept has been around for nearly two decades: Organizers vet installers, negotiate prices, and recruit as many residents as possible to go solar during a limited sign-up window. The more participants, the lower the cost, thanks to the power of bulk purchasing.
As part of Solarize the Triad — a campaign that covers the north-central region of North Carolina, anchored by the cities of Greensboro, Winston-Salem, and High Point — Lindsay raised money and in-kind donations to help low- and moderate-income families go solar. Plus, she said, “I introduced my neighbors to all the ways they could get solar panels,” and many did. “I feel like I multiplied my contribution.”
Indeed, in a campaign that ran from July 2024 to the following May, Solarize the Triad led to three houses of worship and over 70 households installing solar. Now, Lindsay is among those kicking off a similar effort called Electrify the Triad, which officially launched last Saturday. The latest initiative focuses on electrification: switching out gas heat, stoves, and hot water appliances for electric versions; installing EV chargers; and increasing efficiency — all steps to reduce fossil-fuel combustion, improve indoor quality, and lower household bills.
Lindsay plans to participate in the program, too — not just recruit for it. “I’m doing this because I really want to be more energy-efficient and to help other people be more energy-efficient,” she said. “It’s not enough for me just to make my house work. We need to do this collectively.”
Backed by many of the same nonprofit partners that made Solarize the Triad a success, including the Piedmont Environmental Alliance and the North Carolina League of Conservation Voters Foundation, the electrification initiative includes contractors ready to install electric heat pumps, hook up induction stoves, upgrade electrical boxes, and make other energy-saving home improvements.
Undergirding Electrify the Triad is Bright Spaces, a Georgia-based firm that has supported over 20 Solarize campaigns around the country by bringing organizers, installers, and participants together through its online platform. Electrify the Triad is its third electrification effort; the others are in the Atlanta suburb of Decatur and Buncombe County, home to Asheville, where the company also has an office.
Of course, not all lessons from Solarize the Triad — a discrete project focused on one technology — will translate to the electrification campaign, which has no set end date. The key benefit of Electrify, said Ken Haldin, development partner for Bright Spaces, is that organizers identify contractors and help participants navigate how to cut costs and reduce their carbon footprint when they’re ready.
“With solar, you either have it or you don’t,” Haldin said. The options under the electrification umbrella, by contrast, are myriad, and a homeowner could swap out old, inefficient appliances with electric versions over time, rather than all at once. “It’s less binary than solar is. It’s much more a matter of choice and timing.”
The new campaign comes at a key moment for households looking to ditch their gas appliances. While the Trump White House and congressional Republicans have already eliminated some tax credits for home solar and efficiency and are attempting to dismantle others, the administration of North Carolina Gov. Josh Stein, a first-term Democrat, is pushing in the opposite direction.
Last year, North Carolina was the first in the country to launch a home energy rebate program created with funds from the Biden-era climate law, the Inflation Reduction Act. State officials announced last month that the cash-back program aimed at low- and middle-income households, which was rolled out in phases, is now available in all 100 counties. Each family can access up to $14,000 for electrification and up to $16,000 for home energy-efficiency upgrades.
Participation in Electrify the Triad isn’t limited by income, but the state rebates will help expand it to scores of households that otherwise might not be able to afford the up-front cost of high-efficiency appliances, added insulation, and other energy-saving measures, even though the outlays will pay for themselves over time in the form of lower utility bills.
“Information is power,” Haldin said. “If you can be guided on the proper way to move forward” on electrification, he said, “then you’re already on a money-saving track. And if someone can point you to an incentive that’s applicable, now you’ve redeemed a coupon you didn’t know you had.”
Among the designers and planners of Electrify the Triad is Shaleen Miller, sustainability and intergovernmental relations director for Winston-Salem. While the city’s climate target of carbon neutrality by 2050 is limited to its own vehicles, buildings, and other operations, she said, “what’s good for the city residents is good for the city.”
Now that the program is officially launched, other members of the team are beginning outreach. That includes Dawn Lewis, a retiree who, with her husband, recently moved from Austin, Texas, to Winston-Salem to be closer to her adult children on the East Coast.
In Texas, Lewis, a member of the United Methodist Church, had embraced the “creation care” philosophy. “Creation is this incredible gift, and we’re asked to do a good job of taking care of it, and we’ve kind of done a horrible job,” she explained. “So, it’s important for us to go out there and try to resolve that.”
After starting a creation care group at her church in Austin, she formed a network of groups from other Methodist churches around the city. “I’m working to do that same thing here,” she said, starting with Ardmore United Methodist Church in Winston-Salem and expanding to other houses of worship throughout the Yadkin Valley.
Lewis, who also participated in Solarize the Triad, said many of the same organizing tactics will apply to Electrify: reaching out to neighborhoods, businesses, and communities of faith to have person-to-person and group conversations.
“The hope is to try to get as many people as possible aware, educated, and then engaged,” she said. “Solarize was successful. I think this will be, too.”
See more from Canary Media’s “Chart of the Week” column.
The U.S. is the world’s largest exporter of liquefied natural gas — and the war in the Middle East is about to bring massive profits to its gas producers.
As the war destabilizes oil and gas production in the region, LNG prices have shot up globally. Qatar — a U.S. ally and the world’s second-largest LNG supplier — halted production of the fuel on Monday after Iranian drones targeted its energy facilities in retaliation for ongoing U.S. and Israeli strikes. The country accounts for one-fifth of the global LNG supply, and the vast majority of its output goes to Asia.
Analysts say American suppliers could be in for a windfall as desperate international buyers bid top dollar to secure what fuel is available. U.S. LNG export terminals are already operating at full bore, so there is unlikely to be a surge in the volume of gas sent abroad — just in the profits firms rake in on each shipment.
Already, the effects of the energy shock are rippling across the world.
In India, the government began rationing natural gas on Tuesday. Meanwhile, Taiwan, which gets 40% of its electricity from LNG and imports heavily from Qatar, said it will take immediate measures that include sourcing more gas from the U.S.
In Europe, natural gas prices have risen less sharply than in Asia but still enough to exacerbate energy affordability problems in the region, which was plunged into an energy crisis following Russia’s 2022 invasion of Ukraine. After mostly quitting Russian gas, Europe has come to rely heavily on LNG from the U.S., though in recent months it has sought to diversify through deals with Qatar and other countries as the Trump administration threatened to annex Greenland.
Since returning to power last January, the Trump administration has pushed to further expand the nation’s lead in LNG exports, despite warnings from analysts that doing so will drive up costs at home. Before the war broke out, the U.S. Energy Information Administration forecast that natural gas prices would climb for Americans in 2027 in part due to expanding LNG exports. The country is already on track to double its LNG export capacity by 2029.
Amid this expansion, Trump has been pressuring allies from Japan to the EU to buy even more U.S. natural gas. But the war only strengthens the case against a deeper dependence on LNG. The more a country relies on shipped-in energy, the more vulnerable it is to global shocks like the one unfolding now.
Renewables, in contrast, are a source of refuge. You install them once and for decades they produce electricity that, though tied to the weather, is completely insulated from global energy markets. Just look at Europe: The region doubled down on wind and solar following the Russian gas crisis, not because of concern for the climate but because of a desire to make its energy system as self-sufficient as possible.
Now, yet another war underscores the perils of relying on imported energy in an increasingly volatile world.
This story was originally published by Colorado Public Radio. Sign up for CPR’s weekly climate newsletter.
Last spring, Occidental Petroleum, an oil and gas company better known as Oxy, began drilling a massive hole in the shadow of a natural gas processing plant south of Greeley.
Drilling rigs are a common sight in Weld County, an area known for producing the vast majority of oil and gas extracted in Colorado. In this case, however, Oxy erected the tower for a different purpose: not to mine fossil fuels, but to tap carbon-free heat roughly 20,000 feet beneath the Earth’s surface.
The project, known as the Geothermal Limitless Approach to Drilling Efficiencies (GLADE), was supported by a $9 million grant issued by the U.S. Department of Energy in 2022. Its goal was to test whether new drilling techniques could reduce the cost and time required to drill superdeep geothermal wells, a potential global clean-energy game-changer.
Oxy has yet to detail its progress publicly and has declined multiple interview requests from CPR News. Its reports to state regulators, however, show that the company completed its drilling work nearly a year ago, working far faster than traditional superdeep drilling projects. The company started drilling in April 2025, digging twin boreholes almost four miles below the surface over less than six weeks, according to state permitting documents unsealed last month.
In a written statement, Jennifer Brice, an Oxy spokesperson, said the project set “new drilling milestones” for Colorado, and the company is now working to assess the experimental project with its academic and government partners.
The results could reveal whether similar projects — or the GLADE project itself — could support a new generation of geothermal power plants. Estimates suggest the bottom of the wells might exceed 450 degrees Fahrenheit. In concept, Oxy could link the bottom of the boreholes, either with additional drilling or by fracking open the surrounding rock. The resulting loop could heat water or another fluid to generate electricity at the surface.
For more than a century, geothermal power plants have been confined to areas with hot springs or volcanic activity, like Iceland or California’s Geysers region. With the GLADE project, Oxy may have demonstrated that fossil fuel companies are well positioned to overcome those limitations. By cutting the cost of reaching high temperatures far below the Earth’s surface, far more communities could harness 24/7, climate-friendly energy available almost anywhere.
“It’s very promising to see an oil company actually jump in with a drill bit instead of standing around thinking about it,” said Roland Horne, a professor of earth sciences and the director of the Stanford Geothermal Program at Stanford University.
Geothermal has long been the sleeping giant of renewable energy.
The resource currently meets less than 1% of global electricity demand, but humanity has only scratched the surface of its potential, according to a recent report from the International Energy Agency. Far more places can now consider geothermal energy due to recent breakthroughs in drilling and hydraulic fracturing developed by the oil and gas industry.
By using the same techniques to tap underground heat, the report estimates that geothermal could meet global electricity demand 140 times over. Unlike wind and solar, geothermal power plants could also fit into compact footprints and supply steady electricity, no matter the weather.
The main constraint is a basic fact about the Earth’s crust: The deeper you dig, the hotter it gets. With wells less than two kilometers deep, the analysis found that only a handful of countries could reach high enough temperatures to make electricity. At seven kilometers, geothermal could be possible in almost any area of the world.
Reaching those depths is difficult but not impossible. During the Cold War, Soviet geologists spent almost 20 years digging the Kola Superdeep Borehole more than 12 kilometers, or 7.5 miles, deep to study the Earth’s crust, setting the record for the world’s deepest hole. In Colorado, a 22,000-foot-deep oil and gas well in Moffat County holds the statewide record, according to a spokesperson for the state Energy and Carbon Management Commission.
Pressure and heat at those depths wreak havoc on mechanical equipment. With the GLADE project, Oxy set out to prove it could overcome those challenges by working faster and more cost-effectively than past superdeep drilling efforts.
The company itself hasn’t released any results, but state records show it dug one of its two wells in 18 days. Horne, the Stanford geothermal expert, said that pace would put Oxy in league with Fervo, a leading geothermal startup that drilled a nearly 16,000-foot-deep geothermal well in southwest Utah in 16 days last year. “That’s pretty impressive,” Horne said.
Other experts have characterized the effort as a success. Amanda Kolker, the manager of the geothermal laboratory program at the National Lab of the Rockies in Golden, said the GLADE project proved it’s possible to dig deep into sedimentary basins, large-scale depressions more commonly explored for oil and gas resources. The Denver-Julesburg Basin is one of many sedimentary basins in the western U.S.
“This achievement could unlock new geographies for geothermal technology deployment in the United States,” Kolker said.
One question is whether Oxy has plans beyond research for its geothermal boreholes. By completing the GLADE project, the company may have taken one of the most difficult steps toward building Colorado’s first geothermal power plant.
Multiple studies show that Colorado has ample underground heat to support a power plant, but no commercial enterprise has built one so far. In central Colorado, a pair of entrepreneurs has spent decades trying to build a geothermal power plant near Buena Vista. Their attempts, however, repeatedly ran into pushback from local residents worried about noise and disturbing the area’s famous natural hot springs. In August 2025, the state land board threw cold water on the idea by declining to renew a key land lease for a potential power plant site.
The Weld County site is rural and surrounded by oil and gas sites, far from hot springs or towns opposed to industrial development. Such a facility would also align with goals outlined by Gov. Jared Polis. Since taking office, the governor has created new geothermal subsidies and streamlined the permitting process for future geothermal projects, including power plants.
It’s unclear whether the company has any intention of building a power plant, but federal scientists advising the project have at least considered the possibility. A 20-page analysis published by the National Lab of the Rockies in 2024 estimates the GLADE project could produce 2.2 megawatts of electricity, enough to power a small community or industrial site.
In 2024, before drilling began, the company also sent a notice to residents, explaining it planned to link the bottom of the wells and circulate water to measure thermal energy. Depending on those results, the document notes, the company hoped to “design a small test plant to generate electricity.”
Brice, the Oxy spokesperson, said the document refers to a “test plant rather than a power plant,” but didn’t explain the difference. She also declined to answer whether Oxy has already built an experimental power plant at the site or plans to in the near future. “No decisions have been made,” Brice said.
If Oxy pursues a power plant, it could hint at a new investment opportunity for Colorado’s oil and gas industry, said Michael Rigby, an energy transition facilitator with the Colorado Energy and Carbon Management Commission. He suspects that oil and gas firms are waiting for a signal — evidence that the same supply chains and workers behind fossil fuels could pivot to geothermal projects.
“There are synergies between oil and gas and geothermal,” Rigby said. “As we see more things happen, I think we will see more merging in that space.”
A correction was made on March 5, 2026: This story originally misstated Roland Horne’s first name as Ronald.
Oregon has made heat pumps the default appliance for cooling new homes.
Last month, the state Building Code Division’s Residential and Manufactured Structures Board voted 7–1 to adopt energy-efficiency standards that encourage builders equipping new homes with air conditioning to use dual-purpose heat pumps instead of conventional central ACs.
The rules could ultimately boost statewide adoption of electric heat pumps, a tech that provides not only cooling but emissions-free heating, too. Heat pumps are 200% to 400% as efficient as conventional gas furnaces, and using them to heat homes is often cheaper than using fossil-fueled appliances.
“The code update is an upgrade in both comfort and affordability,” Eleanor Ponomareff, city council president of Talent, Oregon, said in a statement. “The increased energy savings for new construction will benefit every Oregonian who moves into one of these new homes for years to come.”
Oregon has ushered in the new rules as the Trump administration and Republican-controlled U.S. House of Representatives try to undo or undermine efficiency efforts meant to reduce reliance on fossil fuels and lower energy costs for Americans.
In January, the U.S. Department of Justice sued to block two California cities’ bans on gas hookups in new construction. Last week, the House passed a bill that would limit the Department of Energy’s authority to set energy conservation standards for household appliances. The chamber then green-lit another bill to repeal programs created under the Biden administration to spur broader adoption of heat pumps and energy-saving measures.
Meanwhile, momentum for state and local building standards that embrace electrification with heat pumps is growing across the U.S., according to Ted Tiffany, senior technical lead of the nonprofit Building Decarbonization Coalition. “Today, approximately 25% of the country lives in a jurisdiction that either requires or encourages zero-emission buildings,” he said.
In Oregon in particular, local climate laws and commitments helped set the stage for the new rules, according to David Heslam, executive director of the nonprofit Earth Advantage.
Under state law, standards for new residential buildings need to reduce energy use by at least 60% from the 2005 standards by 2030. Heat pumps will help the state get there, per the Oregon Department of Energy in a letter of support for the rules, which will be phased in starting this October.
In Oregon, where utility rates for more than 1.4 million customers have jumped by about 50% since 2020, the latest building code will reduce the energy use of a typical 2,500-square-foot home by 27% compared with the 2023 version of the code. That cut will result in a savings of $171 per year, the Building Code Division estimates.
To be fair, energy-slashing approaches required under the new standards are expected to increase the cost of building a new residence. But, for that typical 2,500-square-foot structure, the bill savings they generate would allow them to pay for themselves in about 15 years.
This estimate assumes that relevant costs stay fixed. If heat pumps continue to get cheaper and more efficient, or if piped gas prices continue to grow faster than electricity prices, the savings could be even greater.
Oregon building code staff pointed out before the board voted at the Feb. 18 meeting that the new rules aren’t a mandate to adopt heat pumps. They don’t require all homes to have air conditioning — and thus to put in the clean-heat tech. Developers can moreover choose to install gas furnaces with ducted AC units, so long as they meet the updated efficiency standards, which are measured by energy-use intensity.
“But it’s going to cost more to build that home [to comply with the code] because heat pumps are so much more efficient,” said Jonny Kocher, building regulations lead at think tank RMI.
Under the updated rules, heat pumps also don’t need to be sized to cover a home’s total heating demand but rather its typically smaller cooling load. A fossil-fuel furnace could still be used as a backup heating source, for instance.
With its latest building standards, Oregon joins California, Colorado, New York, and Washington in encouraging superefficient heat pumps in new homes. (New York has delayed enforcement of its all-electric buildings code while the law mandating it is in litigation.)
Energy-efficiency standards that encourage heat pumps appear to be working, Kocher noted. For example, the Northwest Energy Efficiency Alliance found that when Washington moved from its 2015 code to the stronger 2018 code, permits for electric space heating in single-family homes rose from 20% to a whopping 88%, with heat pumps accounting for 81% of those permits.
The three West Coast states are “building a market for heat pumps,” which could ultimately help drive costs down, Kocher said.
Still, states could push their regulations further, he noted. Most of these efficiency efforts have focused only on new construction, even though major renovations and additions also fall under building codes’ purview.
There’s one notable example that could prove instructive: When California updated its energy-efficiency standards in 2024, it was the first in the nation to include a provision that commercial building owners replace broken ACs with heat pumps. The state stopped short of extending that concept to homes, but at least 13 California cities have since adopted such rules.
Washington state could be the first to encourage ACs to be replaced with heat pumps in existing buildings when it votes on its code update later this year, according to Kocher.
Developers often don’t have an incentive to install efficient equipment in homes; they’re not the ones paying its energy bills, he noted. But building standards help redress the imbalance, reducing health- and planet-harming pollution — and saving residents money in the long run.
Nearly three years ago, Vermont passed a landmark law that aimed to cut greenhouse gas emissions by shifting residents away from using fossil fuels to heat their homes and businesses. Last month, that plan officially died before ever being put into action — and the path toward cleaner heating in the state is murkier than ever.
In May 2023, Vermont legislators passed the Affordable Heat Act, which is widely considered the first law to require the development of a statewide clean heat standard to lower emissions from heating sources. But after years of contentious debate and recent inaction from lawmakers, regulators closed the case in February, possibly for good.
More than one-third of Vermonters rely on furnaces and boilers fueled by oil — one of the dirtiest and most expensive home-heating sources — and about another 20% primarily use propane. Though the clean heat standard did not mandate a switch to electric heat pumps, the policy would likely have spurred greater adoption of the appliances, which are cleaner and cheaper to run.
Some see the clean-heat turnaround as a financial victory for Vermonters, while others see it as a frustrating loss that will only hurt residents and the planet. How, though, did the pioneering plan manage to fizzle out before it even got started? The answer is a mix of complicated politics, an even more complex policy design, and interference from out-of-state conservative groups.
“There ended up being an enormous amount of misinformation floating around about it, which was very frustrating,” said state Sen. Anne Watson, a Democrat/Progressive who voted for the law. “When people are not circulating well-vetted info, that doesn’t serve anybody — that just serves to scare people.”
Vermont has set a legally mandated target of reducing greenhouse gas emissions 80% from 1990 levels by 2050. Almost all the electricity generated in Vermont comes from renewable sources, including hydropower, solar, and biomass, but the state is still heavily dependent on fossil fuels for heating and transportation. That’s where the clean heat standard came in.
A clean heat standard, broadly defined, is a policy mandating that providers of heating fuels steadily lower the emissions associated with their operations. It’s an adaptable approach, said Richard Cowart, a former Vermont utility regulator and a principal at the nonprofit Regulatory Assistance Project, which advises governments on clean energy policy. Each state implementing such a standard will make its own rules about what kinds of clean energy to include, how quickly to transition, and what fuels to target for reduction.
“It leaves choice in the hands of building owners, homeowners, small-business operators,” Cowart said. “It allows some creativity in implementation and flexibility in the way programs can be rolled out.”
This vision has sparked interest in several other states, but is hitting some obstacles. Colorado in 2021 passed a law requiring natural gas distributors to create clean heat plans. Massachusetts’ Department of Environmental Protection has a clean heat standard in the works, but Democratic Gov. Maura Healey recently delayed the implementation until 2028. Another six to nine states have expressed interest in or have begun exploring the concept, but nothing else is on the books, Cowart said.
Vermont’s idea was to create a “market-based system” in which fuel dealers would obtain a certain number of clean heat credits each year. Credits could be generated by installing weatherization upgrades or heat pumps, or by selling fuels with lower emissions; dealers could offer these services themselves or buy credits from other entities doing that work. Either way, the system would have helped pay for a less emissions-intensive heating system across the state.
The standard’s political foundations were never unshakable. The first shot at establishing the policy occurred in 2022. The heavily Democratic legislature passed a bill creating a clean heat standard, but Republican Gov. Phil Scott vetoed the measure. An attempt to override the veto fell one vote short in the state House.
In 2023, a bill was again passed and again vetoed. This time, the veto override succeeded by one vote in the Senate. Part of the deal that helped the legislation pass was a provision that required regulators to design the program and then bring it back to lawmakers for another vote before it could be implemented.
“That was pretty unusual,” Watson said. “Usually, you design a program, then the rules take effect, basically, immediately.”
Lawmakers never had a chance to take that second vote.
Regulators released their program design and cost estimates in 2025. Those intervening years gave opponents time to build their case against the program. Their main argument: The clean heat standard would dramatically raise prices for any Vermont household still using heating oil, as sellers would pass their compliance costs on to customers. Scott’s administration repeatedly claimed the plan could increase heating oil prices by up to $4 per gallon (for comparison, current prices average $3.65 per gallon), though the basis of this number was never clear.
While the numbers weren’t available until 2025, utility regulators ultimately calculated that the program would cost residents a total of about $956 million in its first 10 years of operation and provide societal benefits of $1.5 billion. The average price of heating oil would go up an estimated 8 cents per gallon in the beginning, rising to 58 cents in 2035. But those using heat pumps could expect to save some $500 per heating season on fuel costs compared with burning oil, or to save over $1,000 compared with using propane.
Shortly before the bill passed, Americans for Prosperity, a national conservative policy advocacy group founded by oil-industry billionaires Charles and David Koch, arrived in the state as part of an effort to expand its work into traditionally left-leaning states. In May 2024, it launched a direct-mail campaign attacking the clean heat standard and inaccurately complaining that the policy would put severe restrictions on natural gas, impose a tax on heating oil, and mandate the installation of heat pumps in homes.
“We were not having a full and fair and accurate conversation about the costs and the opportunities the program could deliver,” said Johanna Miller, energy and climate program director for the Vermont Natural Resources Council.
Then came the 2024 election. In historically deep-blue Vermont, Scott was reelected and 22 legislative seats flipped from Democratic to Republican, eliminating the supermajority that had enabled the veto override the previous year.
At the time, there was widespread concern in the state about property tax increases related to education funding. Republicans took advantage of this ongoing financial unease to inflate and mischaracterize the costs of a clean heat standard, said former state Sen. Chris Bray, a Democrat and major force behind the clean heat standard bill, who lost his seat in the election.
“It got weaponized in the campaign season, with a broad misinformation campaign,” Bray said.
The highly detailed work of designing the clean heat standard created its own complications.
In February 2024, state utility regulators issued the first mandated progress report on their efforts and noted that most participants in the process — including the public utilities commissioners themselves — had “serious misgivings” about whether a thoughtful and effective policy could be put together on the timeline dictated by the law.
The complexity of the program came up again and again. Commenters noted that the standard was difficult for average Vermonters to understand, and extensive education and outreach efforts would be needed. Others suggested that cost and confusion would drive small fuel dealers out of business, leaving consumers with fewer choices and potentially higher prices.
“We opposed this not because the idea wasn’t good, but because the execution was fatally flawed,” said Matt Cota, a lobbyist for fuel sellers who was a member of the Clean Heat Standard Technical Advisory Group.
Even the regulators who designed the standard ultimately advised against adopting it. In a January 2025 report, the public utility commissioners concluded that “the Clean Heat Standard is not well suited to Vermont.” A more effective choice, the commission said, would be to expand upon existing programs, such as the fee that generates revenue for electric-efficiency programs.
In the face of a likely gubernatorial veto, and the recommendations from the commissioners, even those lawmakers who still believed in the policy saw no way forward
“It was the chastened legislature that was unable and unwilling to pick it up and go further,” Bray said.
Lawmakers say the clean heat standard, in the form passed in 2023, is unlikely to be introduced again. Some supporters of the standard worry that further action is unlikely as long as Scott is governor. But advocates of the underlying ideas think some program to incentivize greenhouse gas reductions from heating is necessary and inevitable, even if it is not a fast process.
“That’s going to come back, because it’s something that we know has to be achieved,” Cowart said. “Over the course of a generation this work is going to get done.”
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