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A U.S. appeals court upheld the first-in-the-nation measure, which will slash smog-forming emissions from certain gas-fueled boilers and heaters in the region.
Southern California’s landmark rule to slash emissions from industrial heating sources just notched a major victory in court.
The region has some of the worst air quality in the U.S., and the gas-fueled boilers and water heaters that serve its factories and large buildings are a key culprit.
In 2024, air quality regulators passed a first-in-the-nation rule to clean up those dirty sources. Since then, opponents of the measure — including gas-appliance makers and trade groups for pipefitters and building contractors — have tried repeatedly to quash it. But last week, the U.S. Ninth Circuit Court of Appeals upheld the regulation, which is meant to spur a shift toward clean, electrified technologies.
The standard, which took effect in January despite the legal challenge, gradually eliminates emissions of nitrogen oxides (NOx) from more than 1 million gas appliances across Greater Los Angeles.
“It was a big win for folks who breathe air in Southern California,” Candice Youngblood, a senior attorney for Earthjustice, which intervened to defend the rule in court, said by phone. “The court fully understood how important this rule is to saving lives.”
The South Coast Air Quality Management District set limits on NOx emissions for light-industrial and commercial boilers, steam generators, and process heaters, as well as residential pool heaters and tankless water heaters. The rules currently affect small units installed in new buildings, but they’ll broaden in scope until covering new high-temperature units installed in existing buildings in 2033. Existing gas equipment must be replaced with zero-emission units once it reaches a certain age, or at the end of its useful life, depending on the appliance.
A spokesperson for the South Coast air district stressed that the rule does not ban gas appliances but rather regulates emissions. The agency said it “remains committed to developing technology-neutral solutions that protect public health, reduce harmful nitrogen oxide (NOx) emissions, and move the region closer to meeting federal air quality standards.”
The measure is ultimately expected to reduce pollution by 5.6 tons of NOx per day — the same as halving smog-forming emissions from cars in the air district, where more than 17 million people live.
Yet the policy is likely to make an impact well beyond the four-county region. Proponents say a major goal of setting the zero-emission standard is to signal to heat pump manufacturers and other clean technology suppliers to start ramping up production — which could benefit industrial electrification efforts elsewhere by driving down appliance costs.
The Ninth Circuit’s ruling comes as California is pushing to decarbonize all corners of its $4.3 trillion economy. Manufacturing facilities are responsible for more than one-fifth of annual greenhouse gas emissions in the state, making them the largest source after transportation.
Last year, Democratic Gov. Gavin Newsom signed a law, Assembly Bill 1280, that expands incentive programs to help manufacturers install industrial heat pumps, thermal storage systems, and other electrified equipment. Utilities and state lawmakers are also developing new electricity rate structures that would lower the cost of operating electric appliances.
Such efforts are meant to address the financial challenges that can come with switching to electric appliances in industrial settings. Cleaner alternatives, such as heat pumps and electric boilers, are typically more expensive up front. Electricity is often far more expensive as a fuel than natural gas, especially for large industrial users — an issue that’s true in California as well in other parts of the country, including the Upper Midwest and Northeast.
If policies can help overcome those hurdles, industrial firms stand to reap significant economic benefits by reducing their exposure to volatile fossil fuel prices, making their operations more efficient, and lowering their energy bills over time. All told, electrifying the entire U.S. industrial sector could generate around $471 billion in total economic growth through 2035, according to a recent analysis by the Renewable Thermal Collaborative and the Industrial Heat Pump Alliance.
California is well positioned to capture some of those benefits, given its existing climate policies and high levels of industrial activity. The state could see over $31 billion from the construction, installation, and manufacturing of electrified technologies, as well as indirect effects from growing supply chains, the report said. That’s even accounting for the expected decline in economic activity and job losses from gas-equipment makers and service providers.
The gas industry, however, sees the Golden State’s electrification push as a threat.
Last year, Southern California Gas, the nation’s largest gas-distribution utility, helped sink the air district’s separate plan to push households away from gas-burning space and water heaters and toward electric heat pumps. Rinnai America, which manufactures gas appliances, has led the legal fight against the zero-emission standards for boilers and water heaters.
In July 2025, a U.S. district court upheld the clean boiler rules, rejecting opponents’ argument that the measure conflicts with the federal Energy Policy and Conservation Act and thus isn’t valid. Rinnai and other plaintiffs have continued to fight the policy, resulting in the Ninth Circuit’s July 2 decision to affirm the district court’s earlier ruling.
The opposition will still have a chance to challenge the policy again, by asking the Ninth Circuit to review its ruling, Youngblood said. In the meantime, Southern California regulators are preparing to propose a new set of rules for larger commercial and industrial systems in the region, which the agency staff aims to present to its board by the end of this year.
The startup closed the first tranche of Series B funding as it pushes to build a novel geothermal plant in Oregon and advance its rock-melting drilling tech.
Startup Quaise Energy has raised $134 million to advance its first superhot geothermal power plant in central Oregon.
On Tuesday, the Houston-based company announced the first tranche of its Series B financing round, which brings the firm’s total funding to $230 million. Quaise is developing a 50-megawatt plant near the Newberry Volcano that will use novel rock-melting technology to tap into significantly hotter geothermal resources than conventional plants can.
The fundraise comes as Quaise prepares to start drilling its first test well later this month for the Oregon plant, called Project Obsidian, which is slated to come online by 2030.
“Our ambition is to power civilization with Earth’s most compelling energy source,” Carlos Araque, CEO and president of Quaise, said in a statement. “This round takes us from field-proven technology to first commercial revenues.”
The Series B was led by Prelude Ventures, which backs early-stage climatetech firms, and included strategic investments from two major Japanese energy players: the power generation company JERA and the petroleum refiner Idemitsu Kosan. Japan is increasingly investing in cutting-edge geothermal projects to help meet the land-constrained nation’s need for clean, around-the-clock power — and to harness the potential of its 111 active volcanoes.
In the United States, the geothermal industry is experiencing a renaissance as new technologies make the energy resource viable in a wider range of geographies. Soaring power demand from data centers is fueling much of that interest, as are state renewable-energy targets and the electrification of vehicles and buildings.
In May, the startup Fervo Energy became the first next-generation geothermal firm to go public, netting about $1.9 billion. The company focuses on enhanced geothermal systems, an emerging approach that involves fracturing rocks and pumping them full of water to create artificial reservoirs. Fervo is developing a large-scale enhanced geothermal plant in Utah that is set to start sending power to the grid later this year.
At Quaise’s Project Obsidian site, the company will initially use standard drilling tools to build an enhanced system. But as early as next year, Quaise aims to deploy its millimeter-wave drilling techniques to access even hotter and deeper geothermal resources.
The technology uses high-frequency beams to melt and vaporize rocks at depths and temperatures that are too difficult or costly for conventional tools to access. Quaise aims to tap rocks at 300 to 500 degrees Celsius (572 to 932 degrees Fahrenheit) to heat fluids that drive steam turbines on the surface. The hotter the fluid, the more efficient and powerful the system, which means projects can derive more energy from a smaller number of wells.
Quaise isn’t alone in chasing the promise of superhot geothermal. The startup Mazama Energy is developing its own pilot project at the Newberry Volcano, where it says it can reach temperatures of over 330°C. And major research projects are moving forward in Iceland, Japan, and New Zealand.
As Quaise develops its Oregon plant, the company is continuously demonstrating its unique approach at its field site in central Texas. Quaise said it drilled through more than 100 meters (330 feet) of granite there last year and is now approaching 1 kilometer of depth, which would represent a milestone for its drilling technology.
Meanwhile, Quaise is looking to secure another $100 million in grants and debt for Project Obsidian, on top of the Series B funding. The firm has already inked a power-purchase agreement for the initial 50 MW with an undisclosed customer, and it’s working to sign deals for an additional 200 MW in future capacity.
“We have backed Quaise since the beginning because we believed accessing superhot rock would unlock geothermal energy at a scale the world has never seen,” Mark Cupta, managing director at Prelude Ventures, said in a press release. “What the team has achieved in the field and what they are now building at Project Obsidian validates that conviction.”
Startup Electra is outfitting induction stoves with slender batteries that enable the electric appliances to be plugged into a standard outlet — and help the grid.
BROOKLYN, N.Y. — When the startup Electra Research launched four years ago, its founders set out to hook more batteries up to the electric grid. Energy storage is key to balancing the coming and going of wind and solar power, and it can help reduce strain on the electricity system during the busiest hours.
But with the line to plug into the grid being very, very long, Electra opted for a faster route: It would put batteries directly in people’s homes, only with a twist. Instead of installing whole-home backup storage, the firm would pair smaller batteries with energy-intensive appliances. The goal was to help people clean up their homes, reduce energy use — and add some useful capacity to the broader electricity system.
“It became clear that the straightforward thing to do is to colocate a battery with the biggest loads in the house, which are water heating, refrigeration, HVAC, and cooking,” Bert Muthalaly, Electra’s CEO, told me from the startup’s new warehouse in Brooklyn.
“And when you look at it that way, there is one that people care about,” he said. “People love their stoves.”
Today, Electra makes battery-powered induction stoves, which it began shipping to U.S. customers in April. The startup recently gave me a first look at its operation on the edge of Brooklyn’s Bushwick neighborhood, where the glass-fronted warehouse sits somewhere between a pickle-packing plant and a kitchen-supply distributor.
When I visited on a cloudy day in late June, Alexia Avina was rewiring a 305-pound appliance to connect a slender battery pack, which replaces the drawer that holds broiler trays and pans. Electra does the metalwork for its stoves in China and final assembly at the Brooklyn facility, turning them into energy-storing, Wi-Fi-enabled devices — ones that won’t fill your kitchen with harmful pollution by burning natural gas.
Avina joined the team in May, having mainly worked in restaurants and as a musician before training with Electra’s engineers to outfit the stoves. “It’s been cool to learn something totally different,” she said later while standing next to stacks of stoves packed in cardboard boxes. “It’s rare to have hands-on opportunities like this.”
Unlike many induction stoves on the market, Electra’s model can plug into a standard 120-volt outlet and draw power to charge a 5-kilowatt-hour battery. The induction cooktop heats pans directly using electromagnetism, while the oven cooks food using electric-resistance elements.
Customers can choose to turn their batteries into helpful grid tools. With its software partners, Electra directs the batteries to charge up during the most beneficial times — for example, when solar power production is most abundant — and to discharge power during the grid’s peak demand periods. Electra estimates its appliance uses roughly 80% less peak power than a typical electric-resistance stove.
The company now employs nearly two dozen people, eight of whom work on the Brooklyn production line. It’s self-funded but declined to share financial details.
Electra’s appliances are hitting the market at a time when induction cooking is becoming increasingly popular in American kitchens. The technology cooks faster and more efficiently than gas and traditional electric appliances, and, unlike gas stoves, it doesn’t release pollutants that can harm people’s health. Although federal rebates for electrification expired early under the Trump administration, some states and utilities still offer incentives to help defray the upfront cost of going electric.
Electra’s induction stove costs $3,999. That’s more than triple the price of Wirecutter’s highest-rated electric range — although because that model uses 240 volts, it might require upgrading a home’s electrical panel, rewiring the kitchen, or hiring electricians to hook it up. All that can add thousands of dollars to the final bill. Electra says its unit avoids those added costs and, thanks to its battery, can even operate for several meals in a blackout.
The plug-in-ready approach is similar to that of Copper and Impulse Labs, two leading companies in the niche but growing category of battery-powered induction ranges (who, as it happens, are suing each other). California-based Copper has sold over 1,000 units, and it was awarded $32 million last year to design, test, and install 10,000 of its stoves in New York City public housing facilities. Electra says it designed its own model for that same competition.
The startup began receiving stoves from China around three months ago. Electra has since shipped 75 of its appliances from Brooklyn to customers across the United States, and it plans to send out thousands more by the end of this year. Early data show that people who cook frequently are still using only about a fifth of the battery’s power per day, which bodes well for the lithium iron phosphate device’s longevity, Muthalaly said.
The company is also developing a pilot program with the city of Burbank, California, to help residents electrify their kitchens. And it’s partnering with a property owner closer to home, in the Bronx, to equip an 80-unit apartment building with its stoves. In both California and New York, local building codes are effectively pushing natural gas appliances out of new buildings in order to reduce carbon emissions and improve air quality, raising the incentive for households to explore options like Electra’s.
Muthalaly described Electra as a “climate research lab,” and the company continues to refine and develop its stove technology. Greg Shakar, an electrical engineer on staff, was testing a unit for electromagnetic “noise,” or unwanted radio interference, when I walked through the side of the warehouse dedicated to R&D.
But as orders pick up, Muthalaly said the company is constantly evaluating which parts of the assembly process should remain in-house or should move overseas for higher-volume, lower-cost manufacturing.
“We’re thinking about this as an experiment,” Muthalaly said of the Brooklyn operation. “We’re going slow, but we’re learning from each install. And it’s getting smoother and smoother.”
A correction was made on July 6, 2026: This story originally stated that the battery sits beneath the drawer that holds broiler trays and pans, when in fact it replaces the drawer.
After insisting it wasn’t needed, Duke pitched a “large load tariff” for big energy users — a concession to critics before a hearing on its proposed rate hike.
For months, clean energy and consumer advocates in North Carolina have pressed Duke Energy to follow the national trend and create special rules and prices for data centers. The state’s predominant utility insisted such rules were unnecessary, rejecting claims that the power-hungry facilities could overwhelm the grid or burden households with unfair costs.
But now, the company is changing its tune.
In testimony submitted to the North Carolina Utilities Commission in late June, Duke proposed what it calls a “large load tariff” — a scheme by which data centers and other big electricity customers would pay a minimum bill amount for at least a decade, no matter their actual power use.
The transparent setup would replace the confidential, one-off service agreements that Duke makes with large energy users now. The system would result in a “measured set of customer protections” as data centers flock to the state, the company said.
Duke recently raised its 2035 forecast of electricity demand from large customers to 8 gigawatts in the Carolinas — an increase of 2 gigawatts since its projection from last year — with most of the new growth expected in the form of the gigantic computer warehouses. The company is using that prediction to help justify building a whopping 9.7 gigawatts of new gas plants over the next decade.
Around the nation, large load tariffs are gaining steam as states scramble to prevent the AI boom from exacting an enormous cost on consumers and the climate. At least 75 such tariffs have been proposed or approved in some 35 states, according to data tracked by the Smart Electric Power Alliance and the North Carolina Clean Energy Technology Center.
Duke’s about-face on large load tariffs comes as it prepares to defend its deeply unpopular bid to raise electricity prices at commission hearings that begin July 7. The company has lowered its original rate request but still seeks an increase of 11.6% over two years for residential customers.
The reversal on data centers follows advocacy from the state’s attorney general, state-sanctioned consumer advocate Public Staff, and clean energy groups — all of which have argued for large load tariffs.
“This is a welcome development,” said Munashe Magarira, senior attorney with the Southern Environmental Law Center, which is representing the Southern Alliance for Clean Energy, the North Carolina Housing Coalition, and other nonprofits at the commission as it weighs Duke’s rate-hike request.
“It builds on hard work that’s been done to push the commission to address these issues head on because of the impact large customers will have for the utility, the grid, and society as a whole in North Carolina,” he said.
Still, Magarira said, Duke’s proposal falls short in a few ways. The company recommends that large electricity users pay at least 75% of their maximum potential energy use, instead of the 85% proffered by advocates. The tariff would make minimum contract terms of 10 or 15 years — less than the 20 years proposed by the nonprofit coalition. And it would only apply to customers with loads of at least 50 megawatts, as opposed to the 25-megawatt floor that the nonprofits pushed for.
Advocates say these details matter because it’s vital to minimize risk as much as possible: If Duke builds expensive gas-burning power plants and other infrastructure in anticipation of data centers that don’t materialize as planned — a distinct possibility, according to some analysts — households could be left holding the bag.
Even more concerning for Magarira: Duke doesn’t appear to propose that data centers become a new class of customers. Instead, it offers to standardize the bilateral service agreements it already signs with tech companies.
The distinction is more than semantic, he said. A separate customer class would better enable regulators to design rates tailor-made for data centers and their immense energy needs.
“If the projections are right, we’re facing a pretty unique moment with regards to electricity growth,” Magarira said. “We think there’s a real need to create a separate customer class for these customers — just given how different they are.”
A final overarching concern: Duke’s most recent filing fails to mention a “clean transition tariff.” Such programs are vital in vertically integrated electricity markets like North Carolina’s, where entities that want 24/7 carbon-free energy can’t independently contract for it. Only Duke can sell them electricity, so if Big Tech firms want to pay for clean electrons for their data centers — as many say they do — they need a program like a clean transition tariff that lets the utility serve as a go-between.
A handful of other states have enacted clean transition tariffs. In North Carolina, the idea has been bandied about for years, and Duke has publicly agreed to consider it. But the utility has never formally proposed such a tariff to regulators.
“Let large customers who want to be good corporate citizens, who care about the environment, have the opportunity to purchase incremental clean energy to meet their power consumption,” Magarira said. “That feels like a win-win for everyone involved.”
Duke declined to comment for this story, pointing instead to its testimony. The five-member Utilities Commission could open a separate docket on the large load tariff proposal. Otherwise, its decision on that and other matters in the rate case is expected this fall.
Last year, nearly 40% of all power demand from global data centers came from facilities based in America, per a new report.
Data centers use more electricity in the U.S. than in any other country — China included.
In 2025, nearly 40% of all power demand from data centers came from facilities based in the U.S., according to this year’s Statistical Review of World Energy from the Energy Institute. It’s the first year the sweeping annual report has tracked data center demand, a sign of how central the question of powering these massive facilities has become.
To put that electricity use in perspective: American data centers alone consumed nearly 313 terawatt-hours last year, per the report — more than Australia, Italy, Spain, or the United Kingdom generated to power their entire economies.
This electricity demand has been driven by deep-pocketed Silicon Valley firms racing to build out data centers that can give them an edge in the AI race. Between 2022, when OpenAI shook the world with its release of the ChatGPT 3.5 model, and 2025, global data center power demand grew by 59%.
And it’s only expected to keep climbing. Demand in the U.S. could nearly triple by 2030, according to S&P Global — though estimates vary widely, and some analysts caution that a meaningful share of planned projects may be delayed or never get built.
Still, even conservative estimates find that data center power demand will remain high — and the prospect of yet more growth has spurred urgent conversations across the U.S.
Consumer advocates fear that without stronger regulation, ordinary Americans will be left covering the cost of the strain that data centers put on the grid. And climate advocates worry that, despite the climate goals of Big Tech firms, some new demand will be met with natural gas — a trend that would drive up carbon emissions and local air pollution.
Now the legislature must hammer out the differences between the Senate text and the House version, which includes major cuts to energy-efficiency funding.
The Massachusetts Senate yesterday passed a sweeping energy-affordability bill that aims to save residents $14 billion over 10 years in a state that has some of the country’s highest utility costs.
The legislation includes measures that would change the state’s energy procurement process, put guardrails on the activities of third-party electric suppliers, and allow utilities to securitize certain spending, essentially lowering the cost they pay to borrow money. Other provisions aim to cut energy costs by decreasing residents’ reliance on fossil fuels. The bill would authorize the use of plug-in solar systems and phase out a major source of gas infrastructure spending.
“We believe if we can reduce our overdependence on gas … then we’ll be better off,” said Sen. Michael Barrett (D), chair of the Joint Committee on Telecommunications, Utilities, and Energy, and a major voice on climate and energy issues in the legislature, during yesterday’s debate. “These high bills are all fossil fuel–driven.”
Several amendments were approved during the debate. One specifies that data centers will not be eligible for state tax credits unless they meet requirements for clean energy procurement, energy efficiency, and load flexibility. Others call for an investigation into whether utilities’ guaranteed rates of return on investment are excessive, and would close a loophole that might otherwise allow a contentious wood-burning power plant to go forward in western Massachusetts.
The goal of the legislation was to dig into the complexities of the sprawling electric and gas systems to find and eliminate unnecessary fees and costly inefficiencies, Barrett said.
“You cannot save people money, fundamentally, without going after the status quo,” he said. “What we don’t want to see is legacy overcharges that you pay every month.”
The legislation, notably, would not lower spending for Mass Save, the state’s energy-efficiency program, in sharp contrast to the controversial $1 billion reduction the House version calls for. The House’s proposed cut would represent about two-thirds of the roughly $1.5 billion remaining in Mass Save’s three-year budget. Supporters say the move would quickly bring down customers’ bills, but opponents argue that these savings would be small — and that every dollar spent on energy-efficiency programs lowers overall costs for everyone.
The House and Senate now have to hammer out the differences between their versions, and each chamber will need to vote on the final legislation.
One year ago, President Donald Trump signed a massive bill into law and ripped away clean energy tax credits. Renewables have rolled with the punches.
One year ago, President Donald Trump got his Fourth-of-July wish. Republicans rammed a massive tax and spending bill through Congress before his preferred July 4 deadline, allowing Trump to sign it into law during a showy holiday ceremony at the White House.
Alongside huge cuts to Medicaid, food stamps, and other programs aiding America’s neediest residents, the One Big Beautiful Bill Act repealed large swaths of the Inflation Reduction Act — the only significant piece of climate legislation the U.S. has ever managed to adopt.
That law would have marshaled as much as $1.2 trillion to transition the U.S. economy away from fossil fuels and toward renewable energy, largely through tax credits that make it cheaper to build wind turbines and solar panels. But Trump’s big bill sunsetted those incentives; as of Saturday, they will no longer be accessible to clean energy developers unless they have already hit certain construction benchmarks.
Still, despite the tax credits’ looming demise, and the Trump administration’s myriad other attacks on clean energy, developers have continued building renewables at a stunning pace over the past year. More than 90% of the power plants brought online in America in 2025 were solar, wind, or battery farms, according to the U.S. Energy Information Administration. And the agency projects that these clean resources will account for 93% of new additions to the power grid this year.
There’s a simple reason for clean energy’s unstoppable rise: America needs more energy fast, and only renewables and batteries can deliver it.
After decades of staying flat, energy demand is surging. Big Tech firms are building new data centers that use as much electricity as small cities. Homeowners are switching to electric stoves and heating. People are swapping gas vehicles for electric ones.
Meeting this new demand requires building more supply: more power plants, batteries, poles, wires, and transformers that can produce, store, and transport more electrons. And as gas power faces yearslong supply-chain delays, clean energy is the only thing that can be built quickly and cheaply enough to keep up.
It’s not as if clean energy will escape unscathed from the One Big Beautiful Bill Act — or from the Trump administration’s continued clean energy onslaught.
Over the long term, the disappearance of tax credits will take its toll: One estimate suggests the U.S. will build less than half as much clean energy between 2025 and 2035 as it would have with the incentives in place, with the biggest hit happening in the latter years of that range.
In the near term, the Trump administration’s blockade on federal permitting for wind and solar projects, its payouts to cancel offshore wind leases, and other attacks are having a real negative impact.
This past year has proven that clean energy can roll with some punches — and also that the Trump administration is prepared to keep on taking swings at the industry.
Independence nay: The U.S. Supreme Court rules the president can fire regulators at independent federal agencies, including FERC and the Nuclear Regulatory Commission. (E&E News)
Another wind payoff: The Trump administration says it will pay Duke Energy $129 million to abandon its offshore wind project off North Carolina, which the utility says it will reinvest in gas and nuclear power projects. (New York Times)
Farming the sun: Solar opponents in Ohio have used alleged threats to agricultural land to derail projects, but a new report makes clear that arrays only take up a fraction of a percent of prime farmland both in the state and beyond. (Canary Media)
Permitting plateau: Trump administration policies holding back clean energy permitting are putting 92 GW of projects at risk, representing $121 billion in investments, a new Wood Mackenzie report finds. (Reuters)
Sunrise, sunset: Connecticut passed a law that authorizes the use of plug-in balcony solar panels, expands the state’s community solar program, and extends solar incentives, while also instituting new restrictions on solar development. (Canary Media)
Steel’s clean opportunity: It’s been a year since Japan’s Nippon Steel acquired U.S. Steel, but former steelworkers and other residents in Northern Indiana are still waiting to see if the acquisition turns into clean, job-creating investments. (Canary Media)
Grid funding disconnect: A Government Accountability Office audit finds Puerto Rico has only received about 25% of the $14 billion it was allocated for grid repairs and a solar and battery buildout after 2017’s Hurricane Maria destroyed much of the island’s energy system. (Associated Press)
A head-to-head matchup of electric and gasoline cargo trucks shows how rising fuel costs make EVs much cheaper to run. Now, can manufacturers lower up-front costs?
Electric cargo trucks have been getting more cost-competitive for years. But the fuel price spike triggered by the Iran war has made it clear just how much cheaper it can be to move freight with trucks that run on electricity instead of gasoline or diesel.
New data from electric-vehicle manufacturer Workhorse, which runs identical routes with both gasoline cargo trucks and electric cargo trucks for its Stables by Workhorse business, provides a case study of how elevated gasoline prices make EV options more appealing.
Stables delivers packages as an independent service provider for FedEx in Ohio. Its use of internal-combustion-engine and battery-electric trucks side by side has given it a rare “controlled, real-world comparison” of the two vehicle classes with “the same routes, the same drivers, and the same weather,” as explained in a presentation at the ACT Expo trucking industry show in May.
The electric trucks Workhorse builds and runs in its Stables fleet, a type known as step vans, were already cheaper to operate last year than their gasoline-fueled counterparts — saving about 42.5 cents per mile, based on electricity at 11 cents per kilowatt-hour and gasoline at $2.98 per gallon.
But by May 1, gasoline had spiked to an average of $4.83 per gallon in Ohio, pushing the savings advantage for electric trucks up to 73.6 cents per mile. With gas prices so high, a Workhorse step van driving about 50 miles per day can expect to save about $11,000 per year on fuel costs.
The operating-cost difference matters a lot when it comes to electrifying truck fleets. EV trucks cost 50% to 100% more than fossil-fueled versions, according to industry estimates, which means they need to provide enough savings on operations to make up for that higher sticker price.
In the past few months, Workhorse CEO Scott Griffith said customers have grown more interested in buying trucks from his company, which is a small-scale producer in the broader world of medium-duty truck manufacturing.
“The phone is certainly ringing, and the interest is high, and everyone’s doing the math,” he said. “What is the cost of electricity, what are the lease costs, what are the operations and maintenance costs? They’re coming in with a much more sophisticated approach.”
Workhorse’s experience is only one example of how EV trucks are growing more appealing to fleet operators, said Corey Cantor, research director at the Zero Emission Transportation Association trade group. He noted that other fleet operations have observed similarly high savings as gas and diesel prices have spiked in recent months. While those prices have declined slightly since a purported peace deal between the U.S. and Iran last month, they remain significantly higher than before the war began.
Diesel, which is the primary fuel for trucks around the world, has seen an even greater increase in cost than gasoline, putting pressure on fleet operators.
“When diesel is at such an elevated price — even if it may come down over the longer term — it spurs a conversation,” Cantor said.
While the recent gasoline and diesel price spikes are driving conversations about electrification, it’s not clear whether that’s resulting in more purchases or leases of EV trucks.
That’s mainly because the data hasn’t yet come in, said Jacob Richard, technical project manager at Calstart, a nonprofit group whose members include energy producers, carmakers, and other businesses.
There’s plenty of room for growth. Electric trucks made up less than half a percent of the total U.S. truck stock as of mid-2025, according to Calstart’s January report Zeroing in on Zero-Emission Trucks.
Of the 72,000 electric trucks deployed in the U.S. at the end of last year, the vast majority were so-called “last-mile” delivery vans. Cargo vans — the smallest type of commercial cargo vehicle — are an ideal electrification target because they run relatively short routes to and from central depots where they can recharge overnight using slower, less-expensive charging infrastructure, said Mike Roeth, executive director of the North American Council for Freight Efficiency.
The nonprofit research group has put vehicles through real-world tests in its “Run on Less” events and found that battery-electric trucks cost less to operate than fossil-fueled equivalents on the sub-100-mile daily routes that make up about half of all freight miles traveled in the U.S.
Griffith agreed that shorter-haul, “return-to-base” freight routes have been a good fit for Workhorse customers like Purolator and Gateway Fleets, both of which have placed orders for 100 of the company’s electric step vans this year.
“Many of them are running what we call lollipop routes — 90 miles out from the depot, and coming back and charging up,” Griffith said. He added that “a significant chunk of medium-duty trucks” are running such routes, “especially the large fleets.”
But electrifying medium-duty trucks is more complicated than electrifying cargo van fleets, Roeth noted. Medium-duty trucks range from step vans like the ubiquitous brown UPS delivery vehicles to box trucks that have different types of rectangular cargo containers mounted on separately built “cutaway” chassis. They tend to be built for a wider variety of custom markets in much lower quantities than cargo vans, which more closely resemble mass-market passenger vehicles in how they’re manufactured and marketed.
“The smaller and more automotive you are, the greater the scale of production, the lower the cost,” Roeth said. “As you move to a cutaway, where you have to work with a different manufacturer to get that box on, the cost challenges go up.” That’s true for both EV and internal-combustion vehicles in this class, he said.
Still, manufacturers of battery-electric trucks stand a good chance of making headway across market segments while fuel prices are high, Cantor said.
He highlighted Harbinger Motors, a startup that manufactures medium-duty electric-vehicle chassis that can be customized for different classes of vehicles. The California-based startup has raised about $360 million in venture financing, including a $160 million round in November co-led by FedEx, which also ordered 53 of the company’s medium-duty truck chassis.
Workhorse has taken a more circuitous route, Roeth said. He worked at the company back when it was an affiliate of Navistar International making chassis for internal-combustion-engine trucks. In 2013, Workhorse was acquired by startup AMP Electric Vehicles and shifted to making battery-electric chassis.
Last year, it merged with long-time electric-chassis startup Motiv, in what Roeth described as “a perfect marriage.” Even so, it’s not easy to break into established medium-duty truck markets: Workhorse reported widening losses in its first earnings report as a combined company in the first quarter of this year, despite increasing revenues.
Those losses were driven in part by higher investments in manufacturing, as Workhorse retools its factory in Union City, Indiana, for the latest generation of its all-electric chassis, featuring more efficient batteries, drivetrains, and power-control systems. That factory is capable of producing up to 5,000 vehicles per year.
“We’re not just sticking an electrified powertrain on what we currently sell,” said Griffith, who was CEO at Motiv before the merger. “You can get some efficiencies out of that. But you can’t capture the full benefits of a fully software-defined vehicle without going all the way.”
The primary barrier to fleet electrification is the up-front cost of electric trucks. Right now, “a standard rule of thumb is that these vehicles are going to cost two times more than the equivalent cost of a diesel or gasoline version,” Calstart’s Richard said.
But there’s a lot of variation. Commercial vehicle pricing data “is not as transparent and easy to access as [data on] passenger cars,” Cantor said. Many vehicles are custom-designed, and pricing varies greatly depending on factors such as bulk purchase orders and preexisting relationships with fleet operators.
In the case of Workhorse, Griffith estimated that the company’s electric step vans cost about 30% to 40% more than comparable fossil-fueled vehicles. In early April, Workhorse dropped the price of its standard-sized W56 battery-electric step vans by roughly $60,000 to bring them just under $200,000 apiece, about level with the highest-end gasoline- or diesel-fueled alternatives.
The payback time on an electric truck depends on a mix of things — the model, state incentives, fuel prices, and so on. In states like California and Washington, which have generous incentives, buyers can recoup the extra costs on Workhorse’s larger step-van model in three to five years depending on gas prices, according to the company’s chief communications officer, John Williams.
Whether these kinds of paybacks are fast enough will depend on the fleet operator.
In general, bigger operators can afford to take a risk and wait longer, according to Richard. But Calstart presumes that the majority of buyers need to see a payback in three years, which coincides with how they structure financing and resale planning for their internal-combustion fleet vehicles, he said.
Today, the vast majority of electric trucks are being bought by big corporations that have both the deep pockets and the sustainability goals to make the up-front costs worth absorbing, Griffith said.
“But this is a $23 billion-a-year industry,” he said, citing estimates of annual U.S. sales of medium-duty vehicles — and to meet the needs of the broader market, “we’ve got to get the price point down.”
In certain regions, government incentives can nearly close that price gap, Richard said. Though the Trump administration and Republicans in Congress erased many of the federal tax credits that incentivized EV purchases, some EV-friendly states still provide incentives and rebates, he noted. “It makes sense for fleets to capture those up-front incentives while they stand.”
But electric truck manufacturers can’t bank on government incentives, Griffith said. “Those dollars are disappearing in the coming years. The industry has to get to the point where [total cost of ownership] blows internal combustion out of the water — and the buying price of an EV has to be closer to a 10% premium.”
To be clear, electric trucks offer significant benefits beyond lower fueling costs, Roeth said. Companies participating in his organization’s Run on Less events have tracked financial benefits like significantly lower maintenance costs as well as perks like increased driver comfort. Plus electric trucks release much less carbon and local air pollution — an important improvement, as commercial trucks are responsible for a disproportionate amount of such emissions from the U.S. transportation sector.
“For good or for bad, these trucks are used in routes that are sitting and idling for long periods of time,” Griffith said. “They emit three or four times per mile the emissions and carbon you get out of a passenger car. And they’re on routes that tend to affect dense populations,” he said.
Ultimately, he said, “if we can improve the economics and emissions together, make everything better on that route, fleets are going to adopt it.”
New York City’s green building laws are pushing developers toward cleaner technologies — even as state policymakers backtrack on climate change targets.
NEW YORK CITY — Manhattan is teeming with skyscrapers that seem to reach into the clouds. But a gleaming commercial building near the Hudson River is more impressive for how it stretches down into the dirt.
Beneath the floors of 555 Greenwich St. are 68 geothermal energy piles that run nearly 120 feet deep, dodging utility pipes and tunnels that crisscross the busy urban underground. During the sweltering summer, the long vertical piles collect heat from the 16-story building and dump it into the earth, cooling the offices above. In the chillier months, the equipment retrieves that warmth to keep the rooms cozy.
The geothermal system is a key reason why 555 Greenwich can operate without using fossil fuels, making it the city’s first commercial office building to hit that milestone. That’s according to the owner, Hudson Square Properties, which is a joint venture of the real estate company Hines, Trinity Church NYC, and the investment arm of Norway’s sovereign wealth fund.
The building, which finished construction in 2023, should be able to meet half of its heating and cooling needs from geothermal when fully occupied, said Jason Alderman, senior managing director and head of New York at Hines. The other half will be met primarily by the two enormous air-source heat pumps sitting on the rooftop, which overlooks the city’s most iconic towers and the green edges of Central Park.
When I visited the 270,000-square-foot property in early June, Alderman explained that the fossil fuel–free building is a reflection of both New York City’s aggressive climate change policies and the partners’ own ambitions for a highly efficient, carbon-cutting design.
“We wanted to think outside of the box and help set the standard for what others can do,” he said.
We were standing beside the only visible part of the geothermal system: an array of small, dusty pipes peeking out from the partially finished floor of a forthcoming restaurant. In a nearby utility room, I saw control boxes managed by the company Endurant Energy, which monitors temperatures in the underground geothermal piles to determine whether it’s more efficient for the building to grab heat from the earth or run the heat pumps on the roof.
On days when the geothermal setup can produce more energy than needed, it pipes the excess heat directly into its sister property, a nearly century-old Art Deco edifice on 345 Hudson St. The developers recently renovated the older building and combined it with 555 Greenwich to make a single 1.2-million-square-foot office complex in lower Manhattan.
The newer property uses 40% less energy than typical top-quality office buildings and well exceeds New York City’s 2030 climate targets, according to its owners. The older property, which is still transitioning to an all-electric energy system, is on track to reduce its carbon emissions by 90% within the next decade.
Geothermal heating and cooling systems are steadily proliferating beneath the city’s newest buildings, despite the complex engineering challenges and expensive installation costs. Property owners are looking to not just comply with regulations but also to generate long-term energy savings by avoiding natural gas.
Buildings account for more than two-thirds of New York City’s greenhouse gas emissions. Since 2019, city leaders have adopted laws to rein in that planet-warming pollution.
Local Law 154 prohibits the use of fossil fuels in most new construction and will start applying to high-rise buildings in 2027. Local Law 97 requires most buildings over 25,000 square feet, whether new or old, to meet escalating energy-efficiency and emissions standards, with stricter limits set to take effect in 2030.
The city’s deadlines are approaching at a time when New York state is abandoning its most ambitious climate targets. In late May, Gov. Kathy Hochul, a Democrat, signed a budget bill that effectively vaporizes a 2030 mandate to curb statewide emissions by 40% from 1990 levels, replacing the target with a watered-down goal that critics fear will slow the state’s buildout of clean energy technologies.
The rollback at the state level is causing some doubt within the city’s real estate sector about whether the building-decarbonization timelines are really as firm as they seem, experts say.
“When there’s a lack of clarity, it makes it a challenge for building owners to pull the trigger” on efficiency and electrification projects, said Laura Bendayan, director of strategic partnerships at Entech. The NYC-based firm helps buildings optimize their existing boiler systems to reduce energy bills and lower emissions.
“We always recommend that [owners] be ahead of the game,” she added. “But there’s this sense of uncertainty that you can’t take away.”
Hudson Square Properties, for its part, says it’s pushing ahead with its no-fossil-fuels approach in both of its buildings.
During my visit, Alderman led me to the top of the newer building, showing me the controls for the radiant heating and cooling system, which circulates chilled or warm water through tubing beneath every floor. This technology provides a “baseline comfort level” and supplements the larger geothermal system, he said. Vents above our heads draw fresh outdoor air into the building, a step that helps lower the structure’s overall energy use by taking strain off the HVAC equipment.
From there, we walked through a heavy set of doors leading into the old building. The highest of 345 Hudson’s 17 floors is a cavernous empty room that originally housed massive printing presses, whose humming sounds and ink smells filled the neighborhood until the 1980s.
The developers are working floor by floor to phase out the existing gas-fueled heaters and boilers and replace them with a kind of thermal energy network. A labyrinth of pipes circulates water throughout the building; heat pumps can then tap into or reject heat from this system to keep occupants comfortable.
“You’re trying to reuse all of the energy that you’ve brought into the building, in the different places where it’s needed,” Alderman said. It’s the complete opposite of New York City’s district steam system, which gets rid of excess heat by piping clouds of vapor out onto the streets.
The 345 Hudson retrofit won a $5 million grant from the New York State Energy Research and Development Authority, as part of the Empire Building Challenge, which advances low-carbon retrofits in the state’s tallest buildings. The developers also raised more than $30 million in private funding for the project.
New York state’s retrenchment from ambitious climate policies might wind up undermining some of those efforts. As buildings shift toward using all-electric technologies, the level of emissions reductions they achieve will largely depend on how clean the electric grid is, said Kelly Dougherty, president of FirstService Energy, a New York–based firm that helps manage energy systems for residential buildings.
“If it’s rolled back any further, then we may have some issues,” Dougherty said about New York state’s landmark climate law. Still, “a lot of work has been done on reducing greenhouse gas emissions in the city,” she added. “I don’t think it’s going to go away.”
At the end of our tour, standing on an enviable rooftop patio, Alderman said he’ll be watching to see how the two buildings perform as they fill up with tenants and operate over time. As of now, his firm estimates that 555 Greenwich alone should save around $3 million over 15 years in avoided energy bills.
“I hope we can prove to ourselves and to others some of the long-term operating-cost savings — and that people will look to these as examples of what can be accomplished,” he said.
A nation-leading program that encourages superefficient manufactured homes is underway in Vermont, and will produce significant energy savings for residents.
Vermont just got its biggest delivery of superefficient manufactured homes — the latest example of how a pioneering state program can lower energy bills for residents of this type of affordable housing.
The all-electric, heat-pump-equipped homes slash energy use by more than half compared with new conventional manufactured homes. To achieve that feat, each meets the exacting specifications under the Advanced Manufactured Home program, which was created by the state’s energy-efficiency utility Efficiency Vermont in 2024.
The standards aren’t mandatory; it’s up to the federal government to regulate the efficiency of manufactured homes. Instead, Vermont’s initiative certifies best-in-class options that will help the state meet its housing and climate goals — and offers a $3,000-per-unit incentive for the builders who opt in.
This month, manufacturer Titan Homes has been installing 18 of these prefabricated buildings at the largest manufactured-home park in Vermont, Tri-Park Cooperative Housing in Brattleboro. Residents who live in the floodplain and have suffered home damage in past storms will become the new occupants.
Including this latest batch, Titan Homes, based in New York, and Clayton Lewistown in Pennsylvania, have together built more than 30 units that have been installed around the state. Any Vermonter can purchase an Advanced Manufactured Home and work with Efficiency Vermont to get one.
When residents move in, they’ll enjoy much lower utility bills. Older manufactured homes are notoriously inefficient, and those of any vintage are difficult to weatherize after leaving the factory. In Vermont, the structures are typically heated with costly and polluting fuel oil or propane, driving average energy bills to about $4,000 annually, according to Efficiency Vermont.
Though they cost more up front, certified Advanced homes can save residents about $2,700 per year on energy bills over existing manufactured homes on average, and more than $1,300 over new manufactured homes built to the U.S. Department of Housing and Urban Development’s current standards, according to Peter Schneider, principal engineering consultant at VEIC, the nonprofit that operates Efficiency Vermont.
That’s a significant difference. While the median income for occupants of site-built single-family homes is $85,000, it’s $40,000 for manufactured home dwellers, said Mark Kresowik, senior policy director at the American Council for an Energy-Efficient Economy, a nonprofit research organization.
“These families are facing some of the most acute stresses and pain of making decisions about whether to pay their energy bill or their home loan or put food on the table or buy medicine,” he said. “Their energy bills shouldn’t put them back in the streets or back into a rental.”
Vermont’s Advanced homes “are setting a benchmark for the rest of the country,” Kresowik said.
The utility’s program pushes some of the most energy-efficient manufactured homes in the country, going beyond a comparable definition set at the federal level.
Once called mobile or trailer homes, manufactured homes make up 7% of new housing. On average, they sell for about a third of the price of site-built homes, or $123,000, according to federal data.
Under the Biden administration, the Department of Energy developed standards to certify what it called “Zero Energy Ready Homes,” including one for manufactured homes. (The program under the Trump DOE is now called “Efficient New Homes.”) This rubric requires a slew of efficiency measures, but also allows for gas furnaces and water heaters, which take two to four times the energy required by their heat-pump counterparts. Homes that meet or exceed these standards allowed the builder to qualify for the up to $5,000-per-unit New Energy Efficient Home Credit, or 45L, although that incentive expires tomorrow.
Kresowik isn’t aware of any other standard outside of Efficiency Vermont’s that outdoes the DOE’s, he said.
Soon, however, the entire nation may have stricter requirements for manufactured homes — if not as stringent as those in Vermont.
Last week, U.S. lawmakers passed a sweeping bipartisan housing bill that President Donald Trump then abruptly announced he wouldn’t sign until the passage of a voting reform bill. As of Monday, the legislation remained in limbo.
If the 21st Century ROAD to Housing Act becomes law, it will change regulations around manufactured homes in two big ways. First, by ditching a requirement that they be built on a permanent steel chassis, a 10- to 12-inch-deep metal frame that’s used for transport. And second, by making them more energy efficient. The bill would require HUD to set a new efficiency standard within a year of the bill being signed into law, and at least every three years thereafter. The agency set the current standard more than three decades ago.
Efficiency Vermont’s Advanced homes come with a smorgasbord of efficiency improvements over conventional options: more insulation in the floors, the walls, and ceiling; ultraefficient windows and doors; programmable thermostats; tighter air seals and ductwork under the floors in the structure’s belly; Energy Star appliances; a cold-climate ducted heat-pump system that heats, cools, and dehumidifies; a heat-pump water heater; a solar-ready roof; and continuous fresh air via an energy recovery ventilator.
These features add up to a residence that dramatically reduces indoor air pollution and is more comfortable and resilient than those with fossil fuel heating, Schneider points out.
Manufactured homes meeting the standard do cost more, though: about $21,000 over an average new HUD-baseline unit. Still, assuming a 6% interest rate on a 30-year mortgage and including utility bills, the total cost of owning an Advanced home is about the same as owning a much less efficient one that relies on fossil fuels, Schneider calculates.
Moreover, “that’s at today’s energy costs,” he said. Schneider expects fossil fuel prices to continue to grow at a much faster pace than electricity prices, enabling the energy savings in an Advanced home to further offset the higher monthly mortgage payments.
Plus, most of today’s premium stems from the fact that manufacturers are installing the heat pumps and energy recovery ventilators on-site rather than at the factory. “As the market transforms and in-factory heat pump installation becomes more common, that will significantly lower the cost of an all-electric manufactured home,” Schneider said.
Like much of the country, Vermont is in a housing crunch. The Green Mountain State is likely to need roughly 30,000 new homes by 2029. Meanwhile, the pace of construction has been slow and the costs high.
Manufactured homes could help relieve some of the pent-up pressure for new housing. To give them a boost, the state has several programs, such as the Rapid Response Mobile Home Infill Program and the new initiative Move-In Vermont.
“We’re seeing investments in affordable housing funding going to manufactured housing programs more than we ever have,” said Schneider, who’s working with administrators to incorporate the Advanced Manufactured Homes standard. “I feel like that’s just going to grow.”
With the federal 21st Century ROAD to Housing Act, HUD has a chance to make the same opportunity available across the country.
“The question is simply: Is HUD going to do that? Are [HUD’s new] standards going to ensure that people moving into these homes can actually afford their energy bills?” said Kresowik with the American Council for an Energy-Efficient Economy. “Vermont is showing it can be done.”
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