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Thermal energy storage systems, which turn electricity into heat that can be tapped for hours or days at a time, could help decarbonize the production of everything from cement to beer.
But in the U.S., where the economics of replacing fossil fuels with electricity remain challenging, thermal-battery startup Rondo Energy has found its first industrial-scale opportunity in a more controversial place: the oil fields of California.
Last week, the San Francisco Bay Area-based firm announced the start of commercial operations for its first 100-megawatt-hour “heat battery,” located at a Holmes Western Oil Corp. facility in Kern County, the heart of the Central California oil patch.
The installation is housed in what looks like a four-story prefabricated office building. Inside sits a massive stack of refractory bricks, which are heated to temperatures of more than 1,000 degrees Celsius (1,832 degrees Fahrenheit) by an adjoining 20-megawatt solar array. That heat is tapped to generate steam that is injected into oil wells to increase production — a job previously done by a fossil-gas-fired boiler.
The project is something of a Faustian bargain. It will reduce carbon dioxide emissions by about 13,000 metric tons per year, said John O’Donnell, Rondo’s cofounder and chief innovation officer. But, of course, those reductions are in service of bringing more planet-warming fossil fuels to market.
Rondo’s argument for pursuing this application is twofold. For one, fossil fuels will be in use for decades to come, and so we might as well reduce emissions from the sector where we can. Second, thermal-storage startups need paying customers in order to scale up their technology, which could prove necessary to minimize pollution from a host of hard-to-decarbonize sectors.
“We’ve got to decarbonize the world the way it is right now,” O’Donnell told Canary Media in a Thursday call from the Washington, D.C., hotel hosting the annual summit of the Renewable Thermal Collaborative, a coalition of organizations working to cut emissions from heating and cooling. “And because California is kind of an island unto itself, we see this opportunity to make a very big impact in the state.”
Finding cost-effective projects in the U.S. has become even more important after the Trump administration canceled hundreds of millions of dollars in federal grants for industrial decarbonization efforts across the country. The defunded projects included ones that planned to use Rondo heat batteries: International spirits maker Diageo wanted to install the tech at its production sites in Illinois and Kentucky, while chemicals giant Eastman had agreed to add it to a plastics-recycling facility being built in Texas.
Those companies haven’t said if they plan to continue work on those projects absent federal funding, and O’Donnell declined to comment on their prospects. “We are ready to work with them when they’re ready to go,” he said.
But industry experts have pointed out that building first-of-a-kind thermal batteries is challenging without government funding to absorb some of the risk. The recent rollbacks jeopardize the U.S.’s ability to develop a technology that could play a major role in cleaning up industrial heating, which is responsible for roughly 13% of U.S. energy-related carbon emissions.
“Transitioning the world’s industrial economy to clean is going to take a minute — and by a minute, I mean multiple decades,” said Blaine Collison, executive director of the Renewable Thermal Collaborative. “This is a big shift that has to happen at a lot of discrete points. There are tens of thousands, hundreds of thousands of facilities that have to be addressed.”
Rondo’s first 2-megawatt-hour pilot-scale heat battery started operating two years ago at a California ethanol-production facility. But that served more as a “constructability test” for the company’s technology than as a full-scale proof point for commercial viability, O’Donnell said.
Rondo’s Kern County battery, meanwhile, is its first major installation, though it has several others in the works across Europe. It’s building similar heat batteries at a chemicals plant in Germany, a green industrial park in Denmark, and an undisclosed food-and-beverage processing facility in Spain or Portugal.
The market for Rondo’s tech is stronger in Europe, where companies pay much higher prices for fossil gas and face sizeable fees and taxes on their greenhouse gas emissions, O’Donnell said. In the U.S., by contrast, fossil gas is cheap, and only a handful of states impose costs on industrial carbon emissions.
California is one of those states. Under its cap-and-trade program, industrial polluters must reduce their greenhouse gas emissions below certain thresholds — otherwise they have to pay fines or purchase offsets to make up the difference. And under the state’s Low-Carbon Fuel Standard, companies that produce and sell fossil fuels with lower embodied emissions can earn credits they can use to reduce compliance costs.
Still, even in more competitive markets like Europe and California, Rondo has additional work to do to hit its long-range cost goals. O’Donnell said the company is targeting $30 per megawatt-hour for the energy storage services its heat batteries provide, which would put it well within the range of lithium-ion batteries, albeit for a system that stores heat rather than electrical energy.
But the Holmes Western project is “not close” to that price point, he said. Rather, it’s “owned by the customer at a price point that was economical to them.”
The holy grail for thermal storage — the thing that will make it broadly cost-competitive with fossil-fueled heating — is tapping into cheap, clean power.
That’s because the cost of electricity is ultimately what dictates whether a thermal battery makes financial sense. But unlike fossil fuels, electricity prices vary not just from week to week, but from hour to hour. That makes it tricky for would-be customers to evaluate whether to stick with a gas boiler or to make a bet on an electricity-powered system like Rondo’s.
Solar and wind, however, reliably generate power at a very low cost. In some parts of the U.S. and the world, the amount of renewable energy available exceeds electricity demand for hours at a time, driving wholesale power prices to zero or even negative.
Storing this excess carbon-free electricity as heat can significantly cut costs for owners of thermal storage systems, O’Donnell said. The challenge for providers of the tech is to get utilities, regulators, and energy-market operators to allow industrial customers to access those low or negative energy prices, O’Donnell said. Today, most industrial sites buy their electricity from utilities at retail rates that don’t pass through these wide wholesale fluctuations.
This is especially true in California, where thermal batteries are “in many ways the perfect solution,” said Teresa Cheng, California director at Industrious Labs, an advocacy group focused on cutting emissions from heavy industry.
Solar power is close to overtaking fossil gas as the state’s predominant source of electricity. Much of it is generated at times when there isn’t enough demand for electricity to use it or enough battery capacity to save it for later, forcing the state’s grid operator to curtail increasing magnitudes of solar.
Thermal batteries could soak up that cheap renewable energy while helping industries decarbonize, Cheng said. But “to make this work, we need state leaders to fix industrial electricity rates so they actually reward companies for using cheap, clean power instead of letting it go to waste.”
Holmes Western Oil Corp. is in an unusual position of owning enough land surrounding its facility to build its own 20-MW solar array without connecting to the grid. That “islanded” system allows the company to self-supply solar power at a cost that justifies the project, O’Donnell said.
But that’s a rare occurrence. Most industrial customers will need to source power from the grid — and opportunities for them to access electricity at wholesale prices are few and far between.
Doron Brenmiller, cofounder and chief business officer of Israel-based thermal energy storage provider Brenmiller Energy, said Europe is moving more quickly than the U.S. to support heat batteries, including a number of projects his company is building. He cited the European Commission’s upcoming $1.2 billion pilot auction to fund efforts to decarbonize industrial process heat.
“The utilities in Europe are also very engaged in this space,” he said. Brenmiller has partnered with German energy-trading firm Entelios to integrate its growing roster of industrial thermal storage projects into a variety of “short-term flexibility markets” for specialty grid services like frequency regulation and demand response.
But getting the first large-scale projects up and running remains the most important next step for the industry, he said. Brenmiller expects its first industrial-scale project, a 32-megawatt-hour thermal storage unit at a beverage-processing plant in Israel, to start operations before the end of 2025. A second 30-megawatt-hour system at a pet-food factory in Hungary is scheduled to begin running in 2026.
“All the eyes of clients and investors are on these first few big projects,” he said. “We’ve done pilots, even at scale. But these are the real thing.”
This summer, an ammonia-powered ship completed its maiden voyage in eastern China, becoming the first of its kind to run purely on the carbonless compound. Around the same time, in Denmark, the shipping giant Maersk launched a big container ship that can use methanol, making it the fourteenth and largest vessel yet in the company’s growing low-carbon fleet.
Efforts like these are playing out worldwide as the maritime industry works to replace dirty diesel fuel in oceangoing ships, which haul everything from T-shirts and tropical fruit to solar panels, smartphones, and steel rebar. But the progress to date has been piecemeal, representing only a sliver of the world’s oil-guzzling freighters and tankers.
Up until last week, the United Nations’ International Maritime Organization appeared on the cusp of approving a strategy to supercharge shipping decarbonization worldwide. The plan was set in motion in 2015, after the U.N. adopted the Paris Agreement, clarifying the urgent need for countries and companies to reduce planet-warming pollution to zero.
“It sent a signal for the [maritime] industry to start thinking ahead,” said Narayan Subramanian, an expert on international climate policy and clean energy finance at Columbia Climate School.
In the ensuing decade, the IMO worked to hash out regulations that could jumpstart a universal transition toward cleaner ships. The agency landed on the Net-Zero Framework, which would require ships to use more low-carbon fuels and also establish a tax on carbon emissions — setting the first binding carbon-pricing scheme for an entire industry.
“This is not coming out of left field. It’s not being imposed overnight,” Subramanian said last week before IMO officials put the framework to a vote.
Yet on Oct. 17, after a full-throttle offensive from the Trump administration, the IMO moved to delay making any decision on the landmark decarbonization strategy by one year, keeping the industry locked in limbo. Many fuel producers, shipbuilders, and cargo owners have said they need reassurance that shipping is, in fact, charting a cleaner course before they invest billions of dollars in making new fuels and building related infrastructure.
“There is a lack of incentive globally for shipping operators to use clean fuels,” said Jade Patterson, an analyst for the research firm BloombergNEF. He said the framework would improve the business case for using hydrogen-based fuels like ammonia and methanol, which are significantly more expensive than oil- and gas-based fuels.
A smaller group of IMO members is meeting in London this week to drill down on the finer details of the proposed regulations, which will come up for a vote again in October 2026. But it’s unclear whether any global environmental agreement can succeed while President Donald Trump is in office.
In the meantime, the industry will continue guzzling greater volumes of fossil fuels as shipping activity grows over time.
Tens of thousands of merchant ships ply the oceans every year to haul roughly 11 billion metric tons of goods. Together, they’re responsible for about 3% of the world’s annual greenhouse gas emissions.
The Net-Zero Framework was meant to give teeth to the nonbinding climate goals that IMO adopted in 2023. Member countries set near-term targets for reducing cargo-ship emissions by at least 20% by 2030, compared to 2008 levels. They also called for curbing emissions by at least 70% by 2040, and for reaching net-zero emissions “by or around” 2050.
Countries further agreed to have 5% to 10% of shipping’s energy use come from zero- or near-zero-emissions fuels and technologies by 2030.
Current adoption of those fuels amounts to a tiny droplet in an ocean’s worth of oil. Much of it is driven by voluntary efforts by companies like Maersk, which face pressure from investors and customers to clean up their fleets. Meanwhile, regional environmental policies are taking effect. European nations and China are working to rein in ship-engine pollution, and they and other countries — including Brazil, India, and, until recently, the United States — are steering government funding into hydrogen production.
Hydrogen is a key component of ammonia and methanol — two common chemicals that can be used in engines or fuel cells. How clean those fuels actually are depends largely on whether the hydrogen is produced using renewables, or the way that most H2 is made today: with fossil fuels. Renewable diesel, another lower-carbon option for powering vessels, also uses hydrogen in its production process.
If every project to produce green ammonia, green methanol, and renewable diesel comes online as planned, and if the fuels only go toward powering ships — not airplanes or vehicles or to other uses — they would make up less than 20% of global shipping’s fuel needs in 2030, which are expected to reach 290 million metric tons that year, Patterson said.
Those are two enormous “ifs.” Many of the announced fuel projects are facing serious headwinds, including high inflation, soaring production costs, and the Trump administration’s steep tariffs and clean-energy funding cuts. IMO’s recent decision to punt on its net-zero vote only deepens those challenges.
Last year, Danish energy giant Ørsted canceled plans to build a green-methanol plant in Sweden, citing weaker-than-expected interest from the maritime sector. Another Ørsted methanol project in Texas is facing uncertainty after the U.S. Department of Energy in May revoked an award of up to $99 million for the facility, as part of sweeping cuts to the Office of Clean Energy Demonstrations. In the Netherlands last month, Shell said it is abandoning construction on a biofuels plant in Rotterdam owing to the fuel’s lack of competitiveness.
“What we’ve seen is that this lack of demand and the shift in policy has led many projects to fold,” said Ingrid Irigoyen, president and CEO of the Zero Emission Maritime Buyers Alliance. “But that’s not because they weren’t good projects. These are good fuels that we need, and which are vastly scalable.”
The buyers alliance is a nonprofit group of about 50 multinational companies that helps negotiate clean-fuel contracts — including for waste-based biomethane — between producers, vessel operators, and firms that put their goods on ships. Irigoyen said such voluntary initiatives are meant to be a “catalyst” that helps to scale production and bring down costs of alternative fuels, not the sole engine of shipping decarbonization.
“We can’t do it alone,” she added.
Even as shipping-industry groups and climate experts push for a global policy, there’s still widespread disagreement about how the framework should work in practice. Environmental groups oppose including crop-based biofuels, like soy and palm oil, given that their production can lead to forest loss and increase overall emissions. Policy analysts note that the ripple effects of higher fuel costs and carbon taxes across supply chains could disproportionately affect small and developing economies.
As IMO members navigate those questions, shipbuilders and owners are holding their breath for the answers.
This year, the number of new orders for alternative-fueled vessels has markedly declined compared to last year as companies adopt a “wait and see” approach, according to Jason Stefanatos, global decarbonization director at DNV.
In September, the advisory firm recorded no fresh orders for ships capable of running on methanol or ammonia, though nearly 360 methanol ships and nearly 40 ammonia ships are on the books through 2030.
Subramanian noted that vessels and port equipment are often designed to last for decades, and that many shipping firms are at the point of deciding whether to invest in a status-quo fleet or the next, cleaner generation.
Decarbonization “is a very natural opportunity to upgrade shipping infrastructure that’s otherwise been around for 30 or 40 years,” he said. “And the investment-certainty piece is key to that.”
Tech firms and automakers both need lots of steel to build their data centers and vehicles. The metal is sturdy, ubiquitous — and highly carbon-intensive when it’s produced using traditional coal-fired furnaces.
The startup Electra says it’s working to scale a dramatically cleaner method for making the key material. On Tuesday, the company unveiled the site of its new demonstration plant in Jefferson County, Colorado. Electra also announced purchase agreements with the tech giant Meta and with Nucor and Toyota Tsusho America, both of which supply steel to car manufacturers.
Instead of using a scorching furnace, Electra produces iron — the main ingredient in steel — with electrochemical devices, which are powered by renewables and can run at the same temperature as a fresh cup of coffee. The method, known as “electrowinning,” is time-tested for removing impurities from metals like copper, nickel, and zinc. Now Electra is using it to make high-purity iron.
“We’re reinventing how iron has been made for centuries through an electrified process,” Sandeep Nijhawan, the startup’s cofounder and CEO, told Canary Media ahead of this week’s announcement.
Steelmaking is responsible for up to 9% of total global greenhouse gas emissions, and most of that pollution comes from the coal-fueled blast furnaces that convert iron ore into iron.
Electra will soon begin installing equipment inside an existing 130,000-square-foot building south of the company’s headquarters in Boulder, Colorado. The demonstration project is backed by a new $50 million grant from the Breakthrough Energy Catalyst program, adding to the $186 million Electra raised from investors earlier this year and its $8 million tax credit from the Colorado Energy Office.
The plant is set to start operations in mid-2026 and will deliver up to 500 metric tons of iron per year — a minuscule amount compared to the roughly 1.4 billion metric tons of iron produced globally in 2023. But it’s an important step toward commercializing the emerging technology, the company and its partners say.
Nucor, the largest U.S. steel producer and an early investor in Electra, has committed to purchasing iron from the demonstration facility, which it will then add to electric arc furnaces to make steel. Toyota Tsusho America said it plans to sell Electra’s clean iron to steelmakers, then distribute the resulting steel to automakers. A third partner, Germany’s Interfer Edelstahl Group, will use the iron in its specialty steel applications.
“We’re excited to see Electra’s demonstration facility become a reality,” Al Behr, Nucor’s executive vice president of raw materials, said in an Oct. 21 press release. He added that the project “lays the groundwork for a new era of low-carbon materials.”
Meta, for its part, struck a different type of deal to buy environmental attribute certificates from Electra. This relatively new concept allows the data-center developer to count the emissions reductions associated with a ton of Electra’s iron toward Meta’s own sustainability targets. The certificates won’t apply to the iron that other partners buy, but rather to a separate batch, Electra said.
Through its offtake agreement, Meta aims to “demonstrate a pathway for these innovative materials to scale,” John DeAngelis, the firm’s head of clean technology innovation, said in the press release.
Electra and its partners didn’t provide more details about the financial value or volumes of iron associated with the new deals.
Electra launched in 2020 with a vision to “use renewable electricity, along with electrochemistry, to produce iron without using fossil fuels,” said Nijhawan, who cofounded the company with Quoc Pham. The startup now operates two pilot plants at its research lab in Boulder, though it didn’t disclose how much clean iron it’s produced to date.
Across the steel industry, another alternative to the blast-furnace process is already gaining traction: “direct reduced iron” production, which can use fossil gas or hydrogen. About 9% of global iron was made this way in 2023.
A handful of commercial-scale direct-reduction projects are underway in Europe and China that will specifically use green hydrogen made with renewable power, which could curb the overall CO2 emissions from steelmaking by up to 90%. Among the most prominent efforts is Stegra’s green-steel plant in northern Sweden that’s set to be completed in late 2026 or early 2027.
Green-steel developers have recently faced soaring production costs, uncertain market demand, and a shifting policy landscape, leading some companies to cancel or postpone projects. Last week, Stegra said it plans to raise another $1.1 billion in funding to build its first-of-a-kind facility, for which the steelmaker has already raised $7.6 billion. In the United States, meanwhile, the Trump administration is gutting federal funding for producing low-carbon hydrogen meant to benefit industries like steelmaking.
“We are seeing a slowdown in the market among our peers, which is also exacerbated by the policy uncertainty” in the U.S., Nijhawan said. “But our long-term and even near-term strategies remain unchanged.”
Electra’s technology is still in the early stages of development, while direct-reduction plants have operated for decades, albeit using fossil fuels. But if electrowinning can scale, it would offer a few key advantages.
The method involves dissolving iron ore into a water-based acid solution to separate iron ions from impurities in the ore. The company then electrifies the solution to deposit pure iron onto sheets the size of a basketball backboard. This process doesn’t require fossil fuels or hydrogen. It can also incorporate iron ores with more impurities — such as those from older mines — than direct-reduction plants typically use, giving Electra access to cheaper materials.
Plus, electrowinning doesn’t need constant, extreme heat, so Electra can tune its operations to the fluctuations of wind and solar power plants, ramping up when clean electricity is most available and affordable. The company said it purchases 100% renewable energy for its Boulder pilot operations through an Xcel Energy utility program, which Electra will also leverage for its Jefferson County demonstration facility.
As the five-year-old firm prepares to open its new plant, Electra is already looking for places to build a commercial-scale manufacturing site, which could be operational in 2029.
The steel industry is “definitely in this phase where the [green steel] transition and meeting climate goals looks a lot more difficult today,” Nijhawan said. But, he added, “I believe the solutions are in hand, and it’s a matter of scaling to drive those economics as fast as we can.”
Home batteries tend to come in two flavors. There are the no-frills, portable systems meant for emergencies, not for full-on integration with solar panels or the power grid. And then there are the Tesla Powerwalls of the world: smart, large devices that can power an entire home but which require a lot of time and money to install.
Cole Ashman, CEO of Pila Energy, wanted to build a battery that combines the best of both of those options — something that is affordable and useful in an emergency but also able to help customers on a daily basis. His years of work at smart-electrical-panel startup Span and as a Powerwall engineer at Tesla gave him the technical chops. His experience growing up in New Orleans and witnessing the aftermath of post-Hurricane Katrina power outages gave him the motivation.
“There’s this need for energy resilience — and hurdles for adoption that exist today,” he said. “We want to bring forward this notion that you don’t have to compromise on the not-so-smart battery or overspend on the primo solution. This is a middle ground.”
The result, the Pila Mesh Home Battery, debuted at the South by Southwest 2025 conference in Texas this spring. On Tuesday, Pila announced it has raised $4 million to scale up manufacturing, via a seed funding round led by R7 Partners and joined by Toyota Ventures, Refactor Capital, GS Futures, and others. The startup aims to deliver its first batteries to customers in early 2026.
Pila’s 1.6-kilowatt-hour batteries retail for $1,299, which is more than what you’d spend for another portable battery with roughly equivalent storage capacity. But unlike the typical portable backup battery, Pila’s sleek, briefcase-sized units are designed to be a constant companion for key home appliances. Set-up is simple: Just plug the battery into a standard wall outlet and connect the equipment you want backed up.
Take a refrigerator — one of the most important things to keep powered when the electricity goes out. Ashman recalled seeing thousands of them on New Orleans street curbs following Hurricane Katrina, abandoned after multiday power outages left them filled with spoiled food.
One Pila battery can power a typical refrigerator for 32 hours, or double that for customers that tack on an “expansion pack.” It also comes with wireless sensors that can be placed inside a fridge to monitor internal temperatures and with on-board sensors that can detect signs of incipient failure of refrigerator compressors from fluctuations in electricity use.
Pila’s batteries don’t just provide value to their owners during blackouts; the devices are also functional when the grid is up and running. They can be programmed to store energy when it’s cheap — say, during midday hours when grid prices are low or rooftop solar is abundant — and deploy that power during afternoon or evening hours, when households often pay higher rates for electricity from utilities.
These are the kinds of features that come standard with large, high-end home batteries like the Tesla Powerwall, sonnenCore+, Enphase IQ, and FranklinWH. But a typical Powerwall costs between $12,000 and $16,000 to buy and install — and the vast majority of them are in owner-occupied single-family homes that went through fairly extensive permitting and utility interconnection processes.
Pila batteries, by contrast, are what Ashman describes as “permissionless” energy infrastructure.
“You don’t ask for permission to put in a new refrigerator,” he said. “Why does this have to be any different?”
That puts Pila in a category of “do-it-yourself” energy systems that are gaining traction around the world.
Take balcony solar systems, which now power more than a million households in Germany and are starting to take off in other European countries. These portable panels generate only a fraction of what rooftop solar systems can provide, but they cost a lot less and can simply plug into an outlet — a much simpler process than getting a professionally installed rooftop array.
Yet balcony solar hasn’t caught on in the U.S., where electrical codes put strict limits on devices that send power back into household circuits. For now, Pila’s software is configured to only allow power to flow from wall sockets into its batteries, not vice versa, Ashman emphasized.
However, as more states pass laws promoting DIY solar and as electrical codes evolve to allow intelligently controlled devices to safely deliver power through wall sockets into household circuits, Pila Mesh batteries can flip to serve that task, Ashman said.
The do-it-yourself design also makes Pila batteries suitable for renters and people living in multifamily housing, who are largely locked out of the solar and battery market today, he said — a frustration Ashman himself has experienced as a renter in New York City.
Consumers want to be able to adopt batteries, solar panels, EV chargers, and the latest all-electric appliances as they see fit, said Andrew Krause, CEO of Northern Pacific Power Systems, a California-based contractor that specializes in solar and battery installations. He’s involved in the Agile Electrification coalition, a group of companies and researchers working to overcome barriers to people electrifying their homes.
“It’s important not to view these things as standalone assets, because as standalone assets they’re marginal. A Pila battery on the grid looks like a vacuum cleaner,” Krause said. “But I’m buying a Pila battery because I have solar on my roof, and I’m trying to handle certain end-use loads that will benefit from a battery and solar, and for which I don’t want to overcommit for a whole-home battery system.”
“It’s just a fractional Powerwall,” he said.
That ethos is appealing to Mackey Saturday, an investor at R7 Partners, which led this week’s investment in Pila. He splits his time between a New York City apartment and a home in Nosara, Costa Rica — and he’d like to have more flexible options for backup power in both places.
“In Costa Rica, while power is readily available, it’s consistently on and off,” he said. “If you want to keep your critical appliances available — not resetting clocks, not having food waste, not having your internet die — that’s hugely valuable.”
Meanwhile, “in New York we have pretty reliable energy,” he said. “But we also have some pretty challenging weather as of late,” like the June heat wave that forced utilities and government officials to issue emergency alerts asking people to conserve energy.
Someday, when Pila’s batteries get the OK to send electricity back to the grid, they could help relieve pressure on the power system, Ashman said.
Ashman highlighted numerous features that could allow Pila batteries to work together as virtual power plants, starting with the wireless mesh network built into each system. The network runs on a 900-megahertz band and allows the batteries to communicate through the walls of a home or even “a 200-unit New York City skyscraper,” he said.
Each battery also contains a cellular modem along with WiFi connections to ensure that individual and meshed batteries have multiple ways to stay in contact with their owners, building managers, or utility control centers, Ashman said. That kind of redundancy is a must-have for eventual use as a grid asset, he added.
Pila is in preliminary discussions with utilities on this front, although it isn’t naming any names. But Ashman noted that the startup presented alongside other providers of plug-and-play home-energy tech, like CraftStrom Solar, at a September pitchfest hosted by the California utility Pacific Gas and Electric.
U.S. utilities have a decidedly mixed track record in terms of how they treat customers installing rooftop solar and backup batteries. Across the country, utilities have campaigned to claw back net-metering incentives for consumers who send solar energy back to the grid, seeing that framework as a threat to electricity sales and a risk to the power system’s stability.
But utility regulators and policymakers are increasingly eager to use these distributed technologies to avoid expensive upgrades to the grid. As electricity demand grows and these cost pressures become more acute, the appeal of systems like Pila’s could grow even larger.
“We’re firm believers that batteries will be inside everything,” Ashman said, echoing a conviction shared by an increasing number of startups, especially in the induction-stove sector. “But we need those batteries to be smart. Having an unintelligent battery in everything might be good for backup, but it doesn’t help solve broader problems in the home or for energy.”
In January, the coastal California town of Moss Landing witnessed the most destructive battery fire in U.S. history. Now, Gov. Gavin Newsom (D) has signed SB 283, a law designed to prevent a repeat of the disaster by strengthening statewide fire safety standards for grid battery installations.
Batteries have become an integral part of California’s push to clean up its electricity system. But the Moss Landing conflagration jolted the state as it burned for several days, provoked evacuations of surrounding communities, and destroyed an old power-plant hall that electricity company Vistra had packed full of lithium-ion batteries in 2020. That disaster has since become a symbol of the apparent risks of adopting large-scale batteries, popping up in conversations about proposed battery projects around the country.
In the years since Moss Landing came online, though, the grid battery industry has moved on from that type of design. These days, most every project places batteries in individual containers spaced out across an open field, which minimizes the chances of a fire spreading between them.
Even with those advances in grid battery designs, state Sen. John Laird saw an opportunity to tighten state requirements in light of what happened in January, and he authored SB 283 to do just that.
“Moss Landing was approved through local planning processes — the state was not involved,” said Laird, a Democrat who represents Moss Landing and much of California’s central coast. “What this bill was designed to do was provide guidance from the state.”
Instead of leaving everything up to local jurisdictions — which may be reviewing a large battery project for the first time — the law requires developers to collaborate with first responders on emergency-response plans. Battery developers must now meet with fire authorities during the design phase, and then bring them in to inspect fire-suppression systems prior to launching commercial operations.
That requirement “codifies an industry best practice to ensure early outreach to the fire department” or other relevant authorities, noted Nick Petrakis, director of engineering at Energy Safety Response Group, a firm that works with battery owners on crafting their emergency-response plans.
An earlier draft of the law would have required California to adopt the National Fire Protection Association’s standards for battery safety. As it happened, the Office of the State Fire Marshal did so back in March, so SB 283 didn’t need to force the issue.
The final text does call for the fire marshal, in the next building code update, to “review and consider proposing provisions that restrict the location of energy storage systems to dedicated-use noncombustible buildings or outdoor installations.” That could lead to an effective ban on projects like Moss Landing that insert batteries into existing structures.
This law isn’t the only state action afoot on this topic. The California Public Utilities Commission updated its own battery standards in March and will monitor compliance. That regulatory body is leading an investigation into the cause of the Moss Landing fire. No official determination has been released yet, but the public can expect the PUC to share its findings when they are complete, Laird said.
California leaders see a safe, sustainable grid storage industry as crucial to reaching the state’s long-term climate goals, because the battery plants facilitate the ongoing buildout of clean energy generation.
In 2020, the year Moss Landing came online, the state had mere hundreds of megawatts of batteries hooked up to help the grid. This year, the state surpassed 15,000 megawatts of installed batteries, and it’s aiming for 52,000 megawatts by 2045. The battery fleet is already helping prevent shortages during summer heat waves and cutting into fossil-gas consumption during evening hours, pushing down the cost of energy at those times.
Energy storage trade groups, eager to maintain the pace of the battery buildout, welcomed the new guidance from SB 283 rather than resisting the imposition of new regulations.
The national group American Clean Power, which advocates for the battery industry among others, spoke favorably of the bill’s potential impact. “SB 283 strengthens safety protocols with support from firefighters, electricians, industry, and utilities — ensuring California can continue leading this growing clean energy sector,” the group wrote in a June fact sheet.
“The latest standards for this technology have proven extremely effective,” said Alex Jackson, executive director of American Clean Power’s California branch, in an emailed statement. “Every state should give local officials the tools and the authority to ensure those standards are in place.”
The California Energy Storage Alliance similarly said it was “proud to support this bill” and praised Newsom for signing it.
Responsible developers already work closely with local emergency-response teams, so the new requirements won’t increase their workload appreciably. Many battery firms worry about how the few battery fires that do happen reflect poorly on the industry as a whole; communities debating whether to allow a battery in their proximity might not appreciate the differences in safety between a Moss Landing–era plant and the state of the art today. In that sense, the fact that California has enhanced its battery safety laws could serve the industry better than an absence of new regulations.
“Everybody’s realistic about how serious the Moss Landing fire was,” Laird said. “The whole industry rests on public confidence that they’re not at risk next to a huge battery storage facility, and the industry wants to help in that assurance.”
Data centers are creating problems for the congested, overburdened U.S. power grid. One company thinks it can crowdsource the solution.
California-based Voltus operates “virtual power plants” across North America, controlling the amount of electricity that participating homes and businesses consume or send to the grid via resources like rooftop solar and batteries.
Last month, the firm unveiled its “bring your own capacity” plan. Put simply, the idea is for data center operators to pay other utility customers to reduce their power use when electricity demand peaks, a move that would diminish strain on the system without disrupting computing processes at data centers.
The proposal comes as the nationwide boom in data center construction pushes electricity demand — and prices — to new heights. These conditions are putting pressure on data center developers, utilities, regulators, and regional grid operators to find ways to enable rapid construction that don’t break the grid, or customers’ wallets.
That’s where the bring-your-own-capacity concept could fill the gaps, said Dana Guernsey, Voltus’ CEO and cofounder.
The approach benefits utilities and their customers because it’s a lot cheaper to reduce energy use than it is to build new power plants and infrastructure. And it benefits data centers by offering a much faster route to getting a grid interconnection, as developers wouldn’t have to wait years for utilities to bring new power generation online.
“The hyperscalers and data center developers are eager to fund this,” Guernsey told Canary Media. “It’s more affordable, it’s faster, and it’s an investment back into the communities.”
Voltus is in a good position to spearhead this work, she said. As a virtual power plant operator, it already aggregates backup batteries, electric vehicles, smart appliances, and other fast-responding technologies to provide on-demand relief to the grid. Voltus was recently dubbed the top company in this sector by analytics firm Wood Mackenzie, and after several years of rapid growth, it now has more than 7.5 gigawatts of scattered “demand response” capacity under management.
In general, virtual power plants, or VPPs, could meet 10% to 20% of U.S. peak grid needs in the coming years and save utility customers roughly $10 billion in annual costs, according to a U.S. Department of Energy analysis released in January. Voltus’ new plan is to harness the power of VPPs to help specifically with the data-center-driven electricity crunch — a creative idea with big potential, if the company can convince utilities to play ball.
Voltus already has one developer on board to participate in its bring-your-own-capacity plan: Cloverleaf Infrastructure, which builds gigawatt-scale data centers.
“The right way to serve data center load quickly, at scale, and less expensively and more sustainably, is to leverage the existing resources on the grid as efficiently as possible,” said Brian Janous, Cloverleaf’s chief commercial officer.
Data centers, which are facing yearslong wait times to connect to the grid, are considering every available option. In Wisconsin, Cloverleaf is planning a flagship data center project that could draw up to 3.5 gigawatts of power from the grid when it’s fully built at the end of 2030. Cloverleaf has worked with utility We Energies and its parent company, WEC Energy Group, to develop a tariff that will put the onus on Cloverleaf to pay for the new resources the utility is building to meet its facility’s energy needs.
While specifics on that deal remain confidential, Janous noted that it could include demand response and VPP resources.
“The conversation we’ve been having with utilities is, we want to connect fast. If you tell us, ‘You have to come back in seven years, after the completion of my latest gas-fired power plant,’ I’ll go somewhere else,” he said. But if Cloverleaf can work with a company like Voltus to supply the necessary energy capacity within months, a utility may be able to connect a data center faster.
Guernsey highlighted other examples of data centers bringing their own capacity to utilities. In August, Google announced agreements with Indiana Michigan Power and the Tennessee Valley Authority to reduce the peak loads of data centers in their territories.
Most of the attention on those deals focused on Google’s commitment to shift its computing workloads to reduce peak grid demand — a novel approach to data center power flexibility that tackles the electricity consumption of the massive racks of servers within the facilities’ walls.
But part of Google’s deal with Indiana Michigan Power includes transferring credits for a portion of carbon-free energy Google has contracted to serve its data centers in the region to help the utility meet its capacity requirements. In this case, the tech giant offered up its renewable-energy resources to cover its data centers’ power use, but Google could have leveraged VPPs for that purpose just as easily, Guernsey said.
Ben Hertz-Shargel, global head of grid-edge research for Wood Mackenzie, agreed that VPPs are theoretically a faster and cheaper means of achieving data center flexibility compared to the alternatives.
Most tech companies haven’t done the hard work that Google has done over the past decade or so to enable flexible computing, he said. Data center developers will face cost and air-quality challenges in using their ubiquitous diesel-fueled backup generators for on-site power. And they may be loath to invest in more expensive options like on-site solar, batteries, and gas-fired generators and microturbines — the “build-your-own-power plants” model some developers are pursuing.
“We don’t think that’s going to be faster or cheaper or more sustainable,” Janous said of the latter model. “We think the better approach is to work with companies like Voltus on how to bring more available resources into the mix.”
Demand-response programs and VPPs can also counteract utility customers’ rising power bills, since these initiatives financially compensate the individuals who allow their energy use to be managed.
“You’re paying homeowners and business owners to be part of the solution to accommodate data centers,” Hertz-Shargel said. “They’re already facing large and growing bill increases, not just because of large loads but because of utility investments, costs of climate change. This is a way to offset that.”
It won’t be easy to turn these ideas into reality.
Utilities and regional grid operators consider demand response and VPPs primarily as a tool for managing existing grid stresses, but are far less eager to allow VPPs to substitute for building more traditional power plants and upgrading the grid. It’s always a tall order to get utilities to do something for the first time, but especially so when dealing with data centers, which can require a small city’s worth of electricity for their operations.
Guernsey conceded these challenges to Voltus’ plan. “Most of the deals we’re discussing start in 2027 or 2028 time frame,” she said. “We’re just running as fast as we can to keep up. We’re growing at a clip of about a gigawatt a year across North America. … In particular regions where data centers are getting built, we usually respond with, ‘We can get a couple hundred megawatts in a given territory within that time.’”
One of Voltus’ key early targets is PJM Interconnection, a grid operator responsible for the transmission system and energy markets serving Washington, D.C., and 13 states from Virginia to Illinois. Electricity bills are spiking for the region’s more than 65 million residents — primarily due to data centers. Similar pressures are pushing up costs across the Midwest, and in data center hotspots like Georgia and Texas.
Johannes Pfeifenberger, a grid-planning expert and principal with The Brattle Group, has argued for years that grid operators need to embrace VPPs and other innovations to deal with rising demand. Among those options, “a VPP is very attractive, whether it’s storage, or controlled EV charging, or heating and air conditioning controls,” he said.
But putting this solution into practice will require grid operators to restructure the rules by which VPPs can directly reduce a data center’s impact on the system, he said. PJM and the Southwest Power Pool, which serves 14 Midwest and Great Plains states, are starting to take on these challenges, but their efforts remain a work in progress.
Data centers may also be limited by the capacity of the power lines and substations at the points they’re seeking to connect to the grid, he said. VPPs that consist of customers scattered across a grid operator’s territory can’t relieve those specific stresses, although other options could, such as data centers colocating at spots with ample grid capacity and building their own generation to fill those gaps, he said.
Guernsey agreed that Voltus’ bring-your-own-capacity construct “can only be a solution when capacity is the problem. If the data center is creating an acute distribution level constraint or requires a substation upgrade, that’s a different type of problem.”
Janous thinks data center developers are willing to pay even more than the currently inflated prices for energy if it means they can move faster. Grid operators just have to be willing to allow them to cut deals with companies like Voltus to go do it.
“Our view from our side is that the market is still undervaluing capacity relative to the willingness to pay for a data center to go faster,” he said.
In the face of those pressures, allowing data centers and VPP providers to bring their own capacity is the kind of fast-track effort that could actually succeed at the speed needed, Guernsey said. And it’s a way to make sure that big developers — rather than ordinary consumers — are the ones paying for the energy capacity that data centers require.
Electric vehicle sales just hit an all-time high in the U.S. — but don’t expect the boom to last long.
For every 10 cars that automakers sold from July through September, one was an EV, according to fresh data from Cox Automotive. In other words, nearly 440,000 new battery-powered vehicles hit the nation’s roads during the third quarter of 2025. The previous single-quarter record, set in the final three months of last year, isn’t even in the same ballpark.
But the sales surge has a catch. Buyers flocked to EVs last quarter because it was their final opportunity to take advantage of a $7,500 federal tax credit that disappeared at the end of September under President Donald Trump’s One Big Beautiful Bill Act. The incentive was previously slated to last until 2033.
Under these conditions, “the all-time sales and share records in Q3 were all but certain,” Cox wrote in a blog post accompanying the data. This quarter, by contrast, the company expects EV sales to “drop notably.”
Still, the U.S. electric vehicle market isn’t dead in the water without the tax credit. Already, automakers that have invested huge sums in the EV transition are making changes to try and keep sales going in America. Hyundai, for example, announced in early October that it will cut the price of its popular Ioniq 5 EV by nearly $10,000 next year. One week later, General Motors unveiled a $29,000 version of its Chevy Bolt.
Some state and local governments are taking action, too: Colorado boosted the discounts it offers for both new and used EVs. Burlington, Vermont, launched a similar program.
Meanwhile, the country’s public EV charging network is growing steadily, and the Trump administration is moving ahead with a $5 billion Biden-era program to build out charging infrastructure.
It’s clear, as Cox points out, that electrified vehicles are the future of transportation. Indeed, some countries are already living in that era: In Norway, more than eight in 10 new cars sold are fully electric. The roadblocks set up by the Trump administration might delay progress in the U.S., but it can’t stave off the inevitable.
The United Nations agency that governs global shipping has voted to delay the adoption of its landmark decarbonization strategy by one year, following intense opposition from the Trump administration.
The Friday decision by the International Maritime Organization in London casts uncertainty over the future of the Net-Zero Framework, which would have been the world’s first binding emissions target for an entire industry.
“Today’s delay in adopting the [framework] is a missed opportunity,” Natacha Stamatiou, who leads the Environmental Defense Fund’s global shipping work, said in a statement to Canary Media. “Every delay means that innovation will struggle to scale, inequities will deepen, and the transition to clean shipping will become harder and more costly.”
International shipping is responsible for about 3% of the world’s annual greenhouse gas emissions. Climate pollution from diesel-guzzling vessels — which haul virtually everything we buy and use — is projected to soar in the coming decades if nothing changes.
The Net-Zero Framework would require large ships to progressively reduce greenhouse gas emissions as much as possible by 2050. The strategy, which leans on a carbon tax, would force ships to swap out dirty fuels with cleaner alternatives, such as e-methanol or green ammonia, and adopt other energy-saving technologies like wind-assisted propulsion.
The delayed vote puts that progress on ice — and represents a stunning reversal from where negotiations sat just a few weeks ago.
In April, over 60 countries in the IMO, including Brazil, China, and India, agreed to put the framework to a vote in October. In the months leading up to this week, diplomats, environmental groups, and even industry organizations said they expected relatively smooth sailing toward approval.
However, on Oct. 10, ahead of the negotiations, the Trump administration issued a statement forcefully opposing an international environmental agreement, claiming it “unduly or unfairly burdens the United States.” U.S. officials also began calling and writing to countries that supported the measure, threatening to impose tariffs, withdraw visa rights, and take other retaliatory measures, The Guardian reported on Wednesday.
On Friday, the final day of talks, the U.S., Singapore, Liberia, and Saudi Arabia all called on IMO to postpone adoption of the climate rules. The motion to delay was ultimately put forward by Singapore and called to a vote by Saudi Arabia. While 49 countries voted against the delay, 57 were in favor. Twenty-one nations abstained.
Without a clear framework in place, progress toward decarbonizing shipping will remain slow going. Efforts to kickstart alternative, lower-carbon fuels have emerged in recent years, but shipping companies and fuel producers have been hesitant to invest at a meaningful scale without a clear directive from the IMO.
Shipping companies, for their part, had said they welcomed the certainty that a global, finalized net-zero standard would provide — particularly as the European Union presses ahead with its own ship-emission rules. A coalition of major shipping industry groups said in an Oct. 9 statement that without an international strategy, a patchwork of separate regulations could bog down the industry in costs without advancing decarbonization.
“This delay unfortunately continues the business uncertainty that hampers investment for private sector actors that are ready and eager for this energy transition to accelerate,” said Ingrid Irigoyen, president and CEO of the Zero Emission Maritime Buyers Alliance.
The Net-Zero Framework is the product of the IMO’s now decade-long attempt to institute a climate strategy.
While the details are still being sorted out, the basic idea behind the regulation is as follows: Every year, shipping companies must calculate their “GHG fuel intensity” — the emissions per unit of energy used, on a lifecycle basis — the results of which determine their next steps. Ships that don’t meet IMO’s fuel-intensity standards must buy “remedial units” to cover their compliance gap; the dirtiest ships must pay an additional penalty to IMO for every metric ton of CO2 above the established threshold.
Had the strategy passed, the global fuel standard and carbon-pricing mechanism would have taken effect in 2027, and ships would have needed to start reporting their GHG fuel intensity in 2028. That timeline will now be revised.
There’s no clear deadline yet for when the group will reconvene and conduct a final vote to officially adopt the framework. The IMO will hold a technical meeting to discuss the design of the framework next week.
But experts and advocates warned that there is no more time to delay.
“This is catastrophic for confidence, and therefore also for the equitable and ambitious decarbonisation we need,” Tristan Smith, professor of energy and transport at University College London, said in a statement. “We will now have to double-down on other means to drive shipping GHG reduction and energy transition. Climate science tells us that the challenge of decarbonisation does not go away, it gets harder.”
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy, and the environment. Sign up for their newsletter here.
During a recent visit to a Long Island power station, U.S. Department of Energy Secretary Chris Wright criticized Biden-era policies that supported the development of renewable energy sources.
“There was a lot of that money allocated under the Biden administration that was to encourage business and utilities to … spend money to make electricity more expensive and less reliable,” Wright said during a press conference.
The next day, the Trump administration announced the termination of 321 awards, claiming $7.5 billion in cuts for clean-energy projects. Inside Climate News recently reported that many of these awards were already past their end date.
Empire Clean Cities, which promotes the advancement of alternative fuels and alternative-fuel vehicles to reduce greenhouse gas emissions, was among the organizations that had its funds cut.
The Manhattan-based nonprofit will lose more than 90% of the funds for its $1.7 million award. So far, Empire Clean Cities had received only $162,631 of its award for a project designed to reduce emissions in Hunts Point in the Bronx, according to federal spending data. Largely due to truck traffic, this neighborhood has an annual child asthma hospitalization rate double the citywide average.
“It’s where folks live and work, and so they see every day the impact of truck traffic emissions on their air quality, on their health,” said Joy Gardner, the executive director of Empire Clean Cities. “This was a real opportunity to make a drastic change in just the general quality of life.”
Hunts Point attracts a high volume of freight traffic partly due to its proximity to food centers, including the Hunts Point Food Distribution Center. The city estimates that the center distributes around 4.5 billion pounds of food every year.
Empire Clean Cities is on the cusp of publishing an electrification plan for Hunts Point, with engagement from local businesses, communities, and city agencies. The plan would offer a pathway to electrification for vehicles operating in the neighborhood—and subsequently help alleviate the health issues many residents face.
Though Gardner said the plan is likely to still be published, other aspects of the plan could be delayed or may not happen at all. The nonprofit planned to install six fast-charging electric ports in the neighborhoods, for personal and freight vehicles, according to Gardner.
Empire Clean Cities also planned to provide technical assistance to businesses looking to electrify their truck fleets and information sessions for community members who might want to buy an electric vehicle. According to federal spending data, the nonprofit would “undertake an extensive suite of community outreach activities designed to break down the knowledge barriers preventing [electric vehicle] adoption in the neighborhood.”
“It’s really disappointing not to be able to take this over the finish line, especially with just a year left on the grant,” said Gardner. “We would have been able to do a tremendous amount with that.”
In a statement about the grant cancellations, New York Gov. Kathy Hochul (D) said, “These cuts directly impact local businesses and major companies, putting workers out of jobs, shuttering factories, and slowing our state’s economic progress.”
In response to questions from Inside Climate News, Ken Lovett, Hochul’s senior communications advisor on energy and environment, wrote that the announcement “came as no surprise given the Trump administration’s full-on assault on clean energy.”
The Trump administration announced the termination of 321 grants on Oct. 2. An Inside Climate News analysis of federal government spending data for the awards found that only 188 were still active, according to their stated end dates, at the end of September.
ICN subtracted money already sent to recipients from the sums obligated to be spent, calculating a total of $4.87 billion in cuts, roughly two-thirds of the dollar amount announced by the Department of Energy.
For recipients based in New York state, 20 awards were still active when the Trump administration announced the cuts. After accounting for the money already distributed, the state lost out on about $146 million.
But for Hochul, the grant cuts seem to be just the latest setback to her plans to deliver on the state’s lofty climate goals and address energy concerns. She has recently admitted that New York is unlikely to meet its climate targets, drawing the ire of many residents.
Hochul says she remains committed to reducing emissions in the state and has invested considerable funds toward that goal. She recently allocated $1 billion to clean-energy projects and emissions-reduction efforts and has directed the state-owned utility, the New York Power Authority, to build at least one new nuclear plant by 2040.
At a Brooklyn church in early September, the advocacy group Public Power NY hosted a People’s Hearing for Public Renewables, where officials, environmentalists, and a few dozen New York residents discussed the state’s renewable-energy plans and expressed disappointment with Hochul’s progress.
“We have a movement behind us that is fighting for something better,” said state Sen. Jabari Brisport, a Democrat who represents a district in Brooklyn. “We have a governor who wants to drag her feet.”
New York’s Climate Act requires the state to achieve a 40% reduction from 1990 levels in economy-wide greenhouse gas emissions by 2030 and an 85% reduction by 2050. The act also requires that 70% of the state’s electricity come from renewable sources by 2030.
Residents were advocating for the New York Power Authority to build 15 gigawatts of renewable energy by 2030, which they view as necessary to meet the state’s goal of net-zero emissions from the electricity grid by 2040. Currently, the utility plans to build 7 gigawatts of renewable energy, despite state law requiring it to fill all gaps in electricity generation left by the private sector.
“Hurricane Ida completely destroyed my district,” said former Democratic U.S. Rep. Jamaal Bowman, whose district included White Plains and Yonkers. “We need a governor with human-centered leadership … and if not, we need a new governor.”
Much of the focus on achieving these climate goals has been on electrifying building heating and cooling with heat pumps and moving away from gas systems. In 2023, the state passed the All-Electric Building Act, which mandated that most buildings use electric appliances, and the all-electric standard was written into the state building code in July.
The legislation effectively requires most new buildings to be completely electric — so no gas heating or cooking. A similar law was passed in New York City in 2021.
At a recent press conference, Wright, the federal energy secretary, alluded to the “many productive dialogues” he has had with the governor, and said that two proposed gas pipelines, which would pass through the state and which state officials have rejected in the past, were “already planned” and would “lower the cost of heating.”
There has been speculation, fueled by a May post on X by Secretary of the Interior Doug Burgum, that Hochul “would move forward on critical pipeline capacity.” The implication was that this was a trade-off for allowing the Empire Wind offshore wind project south of Long Island in the Atlantic Ocean to proceed after the administration halted construction.
Within a month, two previously rejected gas pipelines — the Constitution pipeline and the Northeast Supply Enhancement pipeline, or NESE — entered the regulatory process once again. Hochul has denied that she made a deal with the White House, but the Trump administration has said that she “caved” and agreed to allow the pipeline construction, according to Politico’s E&E News.
The Constitution pipeline, which the state rejected in 2016, would run from Pennsylvania’s Marcellus shale fracking sites to upstate New York. The NESE pipeline would extend an existing pipeline, building off the coast of New Jersey and Staten Island to eventually connect with existing pipes in Queens, and add gas infrastructure to Pennsylvania. The state has rejected it three times.
In July, National Grid, the gas utility that serves Staten Island, Long Island, and parts of Brooklyn and Queens, added the NESE pipeline to its long-term gas plan as an addendum.
The utility has to file a long-term gas plan as a result of a dispute with former Gov. Andrew Cuomo (D). The heart of the 2019 dispute was, ironically, an earlier proposal for the NESE pipeline, which the Department of Environmental Conservation had rejected due to its potential impacts on water quality.
The rejection led to a standoff between the utility and state officials, with National Grid refusing to connect customers to gas lines. The dispute only ended because Cuomo threatened to suspend the utility’s license to operate in the state. In the end, National Grid agreed to periodically file a long-term gas plan for review by the state’s Public Service Commission, which regulates utility rates.
While reviewing the utility’s plan for the future last month, members of the Public Service Commission found that the NESE project would help the state meet the energy needs of its residents and businesses, particularly in the wake of Winter Storm Elliott in 2022. A report by the Federal Energy Regulatory Commission found that some areas of New York were at extreme risk of experiencing gas shutoffs at one point during the storm.
But many New Yorkers were dismayed by the commission’s choice, which has no regulatory authority over the pipeline, but which many believe could signal to the Department of Environmental Conservation that the pipeline is necessary and that it should approve its water permit.
“We are in a week-by-week, hour-by-hour, fight to hold [Hochul] off and keep her from approving this thing,” Pete Sikora, the climate and inequality campaigns director with New York Communities for Change, said about the fight to stop the NESE pipeline.
Several public officials, including Staten Island Borough President Vito Fossella (R) and U.S. House Minority Leader Hakeem Jeffries (D), spoke out against the pipeline, as did the city of New York. Water-quality concerns and fears of substantial rate increases abound.
“The governor is willing to put the law off to the side in order to appease fossil-fuel interests, big private business interests … and for New York families to foot the bill for that,” said Kim Fraczek, the executive director of Sane Energy, a nonprofit organization that is advocating for the replacement of gas infrastructure with renewable energy. “Our costs will only increase, and that’s for ratepayers and for businesses.”
A report by the Institute for Energy Economics and Financial Analysis, an energy-research think tank, estimated that the pipeline would cost $1.25 billion — almost $200 million more than what National Grid had said — due to construction inflation. Even if National Grid’s figures are correct, ratepayers would suffer a substantial monthly increase.
National Grid has predicted that the pipeline will cost ratepayers an additional $7.50 per month if approved. But it has also argued that the pipeline could help lower electricity bills by reducing the price of natural gas, which powers many of the state’s electricity plants.
Hochul is also experiencing pressure from the other side of the aisle. Energy Secretary Wright recently criticized the state’s Climate Act, which requires the state to have a net-zero-emissions electricity grid by 2040, calling it “totally nuts.”
“The longer and more aggressively [net-zero] is pursued, the more you elevate your energy prices and impoverish your citizens,” Wright told journalists at the press conference in Long Island earlier this month. “Let’s build more energy infrastructure to drive down the cost of energy here in New York state, across New England, and across our country.”
Whether the Climate Act drives the state’s high energy prices remains a subject of debate. A recent Public Service Commission report found that cost recovery for Climate Act measures accounted for anywhere from 5% to 9.5% of a residential customer’s monthly electric bill — but consistently 2% or less of their gas bill — in 2024.
Another factor contributing to higher rates has been large-scale improvements in gas infrastructure. Last year, residents in downstate New York experienced rate hikes when National Grid began a $5 billion system upgrade, which included replacing “leak-prone” pipes across the region.
Roasting coffee requires high temperatures — up to 500 degrees Fahrenheit for as much as 20 minutes per batch. Today, the vast majority of that heat is generated by fossil fuels. Most of the world’s coffee is roasted in gas-burning machines that emit carbon dioxide and require elaborate venting and afterburner equipment.
Ricardo Lopez, CEO of Bellwether Coffee, has spent the past 12 years fine-tuning a more climate-friendly, electricity-powered alternative, one that, crucially, cuts down on some of the costs and complexities of other electric roasters.
“Our goal is to make a sustainable industry through coffee,” he said. For Bellwether, that includes working with small farms to source beans grown with environmentally friendly practices.
But Lopez, a former data-center construction manager, knows that making a new technology competitive in a crowded field takes more than good intentions. “You have to have a better product,” he said. “As long as you have a better product that’s more affordable from a cost standpoint, it can spread.”
Achieving that has taken quite a bit of ingenuity. For starters, Bellwether’s system doesn’t require the industrial-scale voltages that many European-made electric coffee roasters do. The company’s appliances run on the 240-volt or 208-volt current available in commercial buildings.
The machines also use closed-loop heat recovery to capture and filter the smoke and particulate matter that the roasting process produces, avoiding the ventilation, ductwork, and energy-intensive “afterburner” systems needed to clean up exhaust.
That makes the Berkeley, California-based company’s technology suitable for ordinary retailers. Bellwether refrigerator-sized or countertop-sized roasters are now in cafes and coffee shops in 40 U.S. states and more than a dozen countries.
“Distributed roasting means that every coffee shop can become a roaster,” Lopez said during a recent tour of Bellwether’s headquarters, which featured a sampling of some of the specialty blends sourced from farms the company works with.
That said, making the switch to roasting coffee beans in house isn’t cheap. Bellwether’s latest countertop roasters sell for $22,000, or $27,000 for its “continuous roasting” variant. This sounds like a lot, until you realize that a high-end espresso machine is about the same price, Lopez said.
And the savings from buying raw coffee beans for about $5 to $6 per pound rather than roasted beans at about $12 to $14 per pound add up quickly. Bellwether has a calculator to help determine how long it takes to recoup the up-front cost of its roasters — typical customers pay off their machines in two to 12 months, depending on the volume of coffee they roast, Lopez said. The company offers financing deals with monthly payments that can put most buyers at a cash-flow break-even point within the first month, he noted.
Bellwether’s electric roasters also appeal to large-scale roasting facilities seeking to make small-batch, high-end blends for an increasingly sophisticated coffee-drinking public. One example: the Hero collection from Red Bay Coffee, one of two Oakland, California-based industrial coffee roasters using the startup’s machines.
The closed-loop, electric roasting process is more energy efficient than traditional fossil-gas roasting — about 2 to 3 cents of energy spent per pound of roasted output, compared to about 10 cents per pound, Lopez said.
And, of course, the whole process is less emissions-intensive than relying on fossil gas to produce coffee. Roasting accounts for up to 15% of the coffee industry’s carbon footprint, and a Bellwether roaster cuts about 87% of the carbon footprint of traditional roasting, said Jonathan Bass, the company’s executive vice president of marketing and communications. That’s a significant reduction in what admittedly is a relatively slender slice of the industry’s overall climate impact, which is heavily tied to land use and deforestation.
But those emissions reductions are the end-of-day bonus to a fundamentally economic proposition, Lopez said.
“Our customers love the fact that this is the most environmentally friendly way to roast coffee, and love to communicate that to their customers. But most of them wouldn’t be able to do it if not for the quality benefits or the economics,” he said. “You’re able to take one of your highest expenses and cut it in half while having a better, fresher product that’s environmentally friendly because it’s no longer dependent on natural gas.”
Electric coffee roasters have served as niche products for small-scale craft roasters for years now. But companies like Bellwether and others in North America and Europe are scaling them up.
Bellwether’s technology has evolved over the years. Its early coffee roasters were cobbled together with steel plating and wooden two-by-fours, Lopez said during the August tour of the company’s headquarters and manufacturing space in West Berkeley. More improvements have followed since its first commercial models rolled out in 2018, including a steep cut in their initial price of about $60,000.
Bellwether has put particular effort into honing its roaster’s closed-loop heat-recovery system, which retains much of the warmth that gas-fired roasters lose in their exhaust, Lopez said. Capturing heat that would otherwise be wasted also helps control for the variables of temperature and humidity that can make it hard to achieve consistent roasting quality, he said.
Plus, Bellwether has fine-tuned the “set-and-forget” software controls that allow busy employees to program precise outputs for each batch of green coffee beans being put through the roaster, Lopez said. “The freshness and consistency of the roasting has so much impact on the quality,” he said.
Just ask Keba Konte, founder of Red Bay Coffee. The photographer-turned-entrepreneur started roasting coffee in his garage and moved into a warehouse that has housed successively larger gas-fired coffee roasting machines, including his current one capable of roasting 120 kilograms of coffee beans per batch.
In 2023, Red Bay won a $643,000 grant from the California Energy Commission to defray the cost of installing eight Bellwether machines. The undertaking did require some wiring upgrades, Konte said — but that’s a lot less onerous than designing and installing the gas lines, vents, and other infrastructure required for his gas-fired roasters.
The Bellwether machines also “allowed us to engage in another segment of the market,” he said. “We work with farmers, and our team is super-interested in these experimental coffees. … There are so many interesting things happening in the industry right now.”
It’s hard to dedicate a batch run of Red Bay’s 120-kilogram roaster to these more experimental blends. With the Bellwether roasters, “we were able to distinguish ourselves by introducing some of these small lots,” including ones from former employees who’ve struck out on their own, he said.
Konte is also exploring how Bellwether’s technology could help the company expand to new markets. Rachel Konte, his wife and Red Bay cofounder, was born in Denmark, and the couple has been looking for opportunities to expand into that country. Denmark currently charges luxury taxes on gourmet coffee imports, which made the plan infeasible.
But “if we have a Bellwether sitting there, and we import the same raw green coffee that we have here, that’s sort of a production thing — and so now, that’s just industrial ingredients. There’s no barrier,” he said. “And then the machines, because they’re already preprogrammed — we have our master roaster here making adjustments based on age of coffee, based on humidity, etc. — we can be producing our coffee, branded, in that country.”
Coffee roasting isn’t the only industry that could deploy smaller-scale, lower-carbon technologies to decentralize production. Companies are developing factory-built, electricity-powered modular systems to purify iron for steelmaking, synthesize industrial chemicals, and produce ammonia fertilizer.
Food and beverage production is a particularly appealing target, given that nearly all of the industry’s current fossil-fueled heating needs are for relatively low-temperature processes well suited to electric heat pumps, electric boilers, waste-heat recovery systems, and other lower-emissions options.
Nancy Pfund, founder and managing partner of investment firm DBL Partners, one of the lead investors in Bellwether’s $40 million Series B funding round in 2019, said mass-produced technologies like these have the potential to quickly drive down costs, similar to what has happened with solar panels and lithium-ion batteries.
“The greatest way to increase the impact of sustainable technologies is to make them, one, affordable enough to be widely adopted, not niche, and two, to achieve greater quality than approaches that are more harmful to the environment,” Pfund said.
In the case of cafes and restaurants, “that allows them to pay employees more, or pay their rents,” she said. In the case of coffee-roasting facilities, it’s “affordably reducing air pollution in communities. All of that wonderful, good stuff — and you have this amazingly delicious cup of coffee.”
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