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When Connecticut Gov. Ned Lamont, a Democrat, first nominated Marissa Gillett to the Public Utilities Regulatory Authority in 2019, he praised the “outsider’s perspective” she would bring to the state’s energy challenges. This September, just months after a bruising reconfirmation process, she stepped down, citing a tangle of acrimonious disputes with investor-owned utilities and lawmakers who bristled at her novel approach to regulation and accused her of inappropriate, even unlawful, bias.
Public utility commissions are essential but largely invisible forces regulating and shaping electricity, gas, and water services at the state level. Traditionally, these boards have been thought of as working in tandem with utilities, rarely challenging their proposals and claims. Recently, though, the tides have shifted, as more states and advocacy groups look at ways for commissioners to advance state energy policy.
The need for decisive action from utility commissions is becoming more acute as electricity prices climb almost everywhere in the country and many states push to meet decarbonization goals. The regulatory status quo just doesn’t lend itself to the systemic changes needed to fight these battles.
Gillett has been hailed by some as an exemplar of the assertive regulator, bringing a decidedly proactive sensibility to her work on the Connecticut commission, commonly called PURA. Following her resignation from the board, Gillett sat down for a conversation with Canary Media about what that involved regulation should look like as states face down a crucial moment for consumers and climate alike.
“Regulators need to roll up their sleeves and figure out how to provide continuous, sustained rigorous oversight,” she said.
The traditional model for investor-owned utilities guarantees them a set rate of return on every dollar spent building new distribution lines, upgrading substations, and other such projects. This dynamic has led to criticism that utilities are prone to overspending on infrastructure that might not be in the interest of customers or the environment, for the simple reason that it will bolster their earnings and please their investors.
A key job of leaders like Gillett is to weigh these utility requests against the need for adequate, reliable infrastructure, and the needs of consumers and the state’s energy policy goals. But for too long, critics say, commissioners have functioned more as umpires calling balls and the occasional strike, approving most utility requests.
Before coming to Connecticut, Gillett worked for seven years at the Maryland Public Service Commission, contributing to the development of initiatives including the state’s electric vehicle programs and its offshore wind plan. After a brief stint with the Energy Storage Association, a trade group, she threw her hat in the ring for the Connecticut commissioner position.
Gillett came into the job ready to be the “change agent” the governor said he wanted. Her aim was to reform an entrenched system that had led to some of the country’s highest electricity rates and mixed progress on climate goals — and to move away from the “balls and strikes” mentality that she found unrealistic and limiting.
“I acknowledge you have to make decisions based on the evidence and record in front of you,” she said.
But she was not willing to accept that the only evidence available was what was contained in utility filings and the responses to them. She offered this analogy: If one party came before PURA saying the sky was green, and another argued it was purple, the board should not be forced to choose between those two options.
To dig deeper into the issues before the commission, she assembled a staff of 80 “who are the best in the business and are very passionate about the work,” a group she hopes stays in place despite her departure.
“It is important who sits in the commissioners’ seats, but it’s also important who staffs them,” she said.
Right from the beginning, she and her staff led PURA in several controversial decisions that left utilities and Republican lawmakers claiming she was creating a hostile and uncertain environment for the state’s two major investor-owned utilities — Eversource and United Illuminating — and their shareholders.
After the utilities struggled to restore power following Tropical Storm Isaias in 2020, PURA ordered Eversource to return $28.4 million to customers in the form of bill credits. In 2023, the commission reduced United Illuminating’s requested $123 million rate increase by $100 million. The utility challenged this move in court, but PURA’s decision was upheld.
Gillett argues she always just applied rules that were on the books but rarely enforced. She points to her track record in court cases: Five times utility challenges have made it to the Connecticut Supreme Court, and five times the court supported PURA’s rulings, she said.
“For years we heard in public that I was acting illegally, making decisions that were arbitrary and capricious,” she said. “I was now holding them to standards they had not been held to. I viewed myself as somebody tasked with implementing state policy.”
While the financial penalties and rate reductions Gillett’s PURA imposed garnered headlines, she also made changes that were less widely noticed, with the goal of prepping the grid to handle more renewable energy. Within Gillett’s first year, the board launched the Equitable Modern Grid initiative, a series of investigations into 11 topics, including advanced metering, energy storage, and affordability. The process yielded ongoing action, including a battery incentive for homeowners and businesses and a program to fund pilots trying out innovative grid technologies.
“Considering how slowly regulatory processes usually work, I think designing and launching those programs in that amount of time was very impactful,” Gillett said.
It’s difficult to assess the effect of Gillett’s philosophy on Connecticut’s energy and climate landscape quite yet: Changes to the utility industry are notoriously slow-moving, and the pandemic added an extra level of disruption to her tenure.
Electricity prices remain high there, as they are throughout the entire Northeast, but Gillett leaves behind programs intended to reduce the energy burden on low-income households. During her tenure, the state implemented its first discount electricity rate for such families and launched an outreach program to help disadvantaged households access assistance offerings.
Gillett does not yet have her next move mapped out, but she does have a degree of optimism that utility regulation is evolving toward the sort of goal-driven, engaged model she brought to her time in Connecticut.
More states are already taking seriously the need to seek out “competent, qualified” regulators with a background relevant to the work, she said. She pointed to a Brown University study that found, nationwide, the share of commissioners with previous work on environmental issues grew to 29% in 2020 from 12% in 2000. States like Maine and Colorado have taken steps to direct their utility regulators to consider emissions, equity, and environmental justice when making decisions.
“As electricity affordability becomes more front-and-center, and folks are looking to who is supposed to be watching out for them, there will be a moment when regulators embrace that philosophy more,” she said.
CEOs of artificial-intelligence companies want to spend hundreds of billions of dollars building their energy-gobbling data centers, but that can’t happen without the necessary electricity supply. And they want to move way faster than electric utilities are used to.
One idea gaining traction is to allow data centers to come online more quickly if they agree to occasionally pull less power from the grid when demand is high, a concept endorsed by none other than Energy Secretary Chris Wright in a rulemaking proposal filed Thursday. The massive computing facilities could accomplish such flexibility with the help of on-site renewables and batteries, but precious few projects using this model have materialized. That’s about to change.
On Wednesday, Aligned Data Centers announced it would pay for a new 31-megawatt/62-megawatt-hour battery alongside a forthcoming data center in the Pacific Northwest. The battery, developed by energy-storage specialist Calibrant Energy in partnership with the local utility, is now entering the construction phase and should be operating sometime next year. The kicker is, this deal will let Aligned get up and running “years earlier than would be possible with traditional utility upgrades,” per the companies.
If the plan works, would-be AI leaders will be jumping all over this battery-first strategy. In fact, many already are, they just haven’t publicly acknowledged it yet.
“There’s so much chatter right now about the potential to use energy storage in this manner to facilitate the connection that large power users want from the grid. But there hadn’t really been evidence of that theory being reality,” said Phil Martin, CEO at Calibrant, which is owned by Macquarie Asset Management. “It is possible, and it is being done — not as a proof of concept in a lab somewhere, but really a commercial project.”
Batteries aren’t, at first glance, a tool well matched to the needs of AI computing.
Lithium-ion chemistries have become quite competitive for short-form activities: First, it was managing second-by-second frequency fluctuations on the grid; now, in places like Australia, California, and Texas, batteries are shifting solar generation to compete with gas plants in the evening when demand rises.
Data centers, though, use energy around the clock — not literally at full blast 24/7, but a lot closer to it than current batteries can keep up with. Data-center developers have chased new gas, hydropower, and an exotic array of nuclear power plants in hopes of feeding the beast. But those options will take several years to come online, if they ever get built. The headlong rush into AI demands nearer-term solutions.
As a lot of exceedingly well-funded firms contemplated this conundrum, some thinkers started focusing on grid flexibility as a way to accelerate the computing-infrastructure buildout. Earlier this year, Duke University researcher Tyler Norris made waves in the AI-energy world with research that found today’s grid could handle quite a lot more data centers if the facilities could simply dial back their consumption for a couple hours at a time during moments of maximum demand.
The Aligned battery offers a concrete example of that kind of research. The utility studied just how big the battery would need to be to compensate for challenges imposed on the local grid by the data center. Aligned and Calibrant had their own calculations, Martin said, “but the validation of that, and the actual specification of that, came out of the interconnection study done on the utility side.”
Due to the local nature of the power constraint, the battery had to be built close to Aligned’s facility; the company ultimately provided the land to host the grid storage installation. In other cases, where a proposed data center runs up against a system-wide capacity constraint, a battery solution could be further away.
Another glimpse of the battery-enabled future came this summer when Redwood Materials, a richly funded battery-recycling startup, unveiled a new business line that repackages old EV batteries to serve data-center demand. The first installation, at Redwood’s campus near Reno, Nevada, fully powered a very small, modular data center using a solar array and a field of former EV battery packs laid out on the desert floor.
Redwood just got its own vote of confidence in that concept: On Thursday, it raised another $350 million from investors including AI-chip leader Nvidia.
Aligned’s commitment to paying for the battery itself could serve as a model of socially responsible AI-infrastructure development.
Some utilities around the country are jumping to build new power plants to support the projected data-center buildout, and charging their regular customers for the investment, hoping the AI titans eventually become paying customers. But this approach risks saddling consumers with unnecessary costs if the AI hubs don’t materialize.
Because Aligned is footing the bill, the utility’s other customers won’t be forced to pay for the data-center firm’s growth ambitions. But, though this one large customer will provide the land and funding, the battery will sit on the utility side of the meter. That means the utility can leverage the tech for other grid uses, like frequency management and capacity, when it’s not maintaining the flow of power to the data center during otherwise scarce hours.
In this case, Martin said, the permitting and buildout could move faster with the battery connecting to the utility grid instead of directly to the data center. In other situations, bigger batteries on the customer side of the meter might make more sense. Calibrant is already working on more and even larger batteries for the AI sector, he added.
“Whereas right now, we think this is unique, I think over a relatively short time horizon it’s going to be much more common,” Martin said. “It’ll start to look surprising if we don’t see projects like this at the largest loads as they connect [to the grid].”
A clarification was made on Oct. 25, 2025: This story originally stated that the local utility studied how many times per year the local grid could run out of electricity if the data center got built. The piece has been updated to clarify that the utility studied how big the battery would need to be to compensate for challenges imposed on the local grid by the data center.
Energy affordability has become a flash point over the past few months. It’s a key issue in this year’s gubernatorial races. It’s something President Donald Trump has promised to fix by boosting fossil-fuel production. And of course, it’s showing up in the bills that arrive in mailboxes every month.
Three-quarters of Americans count electricity costs as a source of stress in their lives, according to a new Associated Press-NORC survey. But a recent study from the Lawrence Berkeley National Laboratory provides more nuance to the conversation. When adjusted for inflation, 31 continental states actually saw their power prices decline from 2019 to 2024, while the other 17 states experienced increases.
One reason why some states saw prices jump? Utility spending on disaster recovery and preparedness. Take California, where utilities have added billions of dollars in wildfire-recovery costs and mitigation programs to retail electricity prices in recent years, the national lab found. It’s a bracing fact as the planet warms and disasters become more frequent and destructive.
But the report also tempered fears that the growth of data centers and other power-hungry industries will jack up electricity prices. Grid maintenance has been a top driver of increased electricity costs over the last few years, but spreading these expenses among more customers — like data centers and manufacturers — has helped lower retail electricity prices, researchers found. One caveat: That dynamic tends to benefit large, commercial consumers more than residential ones.
The Trump administration has elevated fossil fuels as a solution to rising electricity bills, positing that more coal and gas power can cut prices. But building a new gas-fired plant is increasingly expensive and takes years, and the U.S. is preparing to ship more liquefied natural gas out of the country anyway.
If you look at two rare examples of power utilities reducing their rates, it’s clear that falling back on coal isn’t the answer either. In Oregon, Idaho Power Co. has asked regulators to lower electricity prices by nearly 1%, saying the closure of a coal-fired power unit and demolition of another coal plant have brought down costs. And in Virginia, where a state law is pushing the electricity sector to lower emissions, Appalachian Power cited the addition of renewable power in its request to lower rates. West Virginia is meanwhile pushing to keep its coal plants running — a move that Appalachian Power said would raise prices for its electricity customers in that state.
But putting the national lab’s inflation-adjusted numbers aside, it’s clear that rising utility bills are reaching a fever pitch across the country — and it’s going to take both more clean energy and smarter utility regulation to rein them in.
Trump sinks a global shipping-decarbonization plan
Until a few weeks ago, the International Maritime Organization was on track to approve a global shipping-decarbonization strategy. That is, until the Trump administration launched a last-minute offensive and got the United Nations body to delay adoption of the plan, Maria Gallucci and Dan McCarthy reported late last week.
The tens of thousands of shipping vessels that travel the oceans are responsible for about 3% of the world’s annual greenhouse gas emissions. But as Maria points out in her follow-up dive into shipping decarbonization, the industry doesn’t currently have much incentive to replace dirty diesel-powered vessels with lower-carbon alternatives.
Some good news, some bad news for U.S. battery startups
The U.S. Department of Energy slashed another wave of federal funding this week, targeting $700 million in grants for battery and other clean manufacturing projects. Nearly half of that funding had been awarded to Ascend Elements, which had already canceled a portion of its planned battery-recycling facility in Kentucky earlier this year. A smaller portion was going to American Battery Technology Co., which said it will carry on with its lithium mine and refinery project in Nevada.
But it wasn’t a bad week for every battery company. Redwood Materials raised $350 million, which it’ll use to expand its unique energy-storage business that packages together used EV batteries into grid-scale resources that can power data centers and other industrial users. And Pila Energy raised $4 million to keep building batteries that provide backup power to large appliances, but are more affordable and portable than whole-home systems like the Tesla Powerwall.
Losing the reactor race: China has a clear head start on the U.S. when it comes to nuclear power, as China has figured out how to produce reactors cheaply and quickly, while the U.S.’s last project went billions of dollars over budget. (New York Times)
What whales? The Trump administration has repeatedly blamed offshore wind farms for whale deaths but just canceled funding for research meant to protect the marine mammals in an increasingly busy ocean. (Canary Media)
Drill here, drill there, drill everywhere: The Trump administration opens 1.56 million acres of the Arctic National Wildlife Refuge’s coastal plain to new oil and gas leasing, and reportedly plans to open significant swaths of the East and West coasts to offshore drilling as well. (New York Times, Politico)
Testing the grid: Xcel Energy is taking different approaches to building out distributed energy resources depending on the state, installing batteries at local businesses in Minnesota while pursuing a more complicated, legislatively mandated model in Colorado. (Latitude Media)
Battling battery blazes: California passes a new law to strengthen fire-safety standards for grid battery systems after a devastating blaze in Moss Landing earlier this year, though new storage-facility designs have already made similar fires unlikely. (Canary Media)
Flagged and forgotten: The United Nations says governments and oil and gas companies are ignoring nearly 90% of leaks that methane-tracking satellites have detected for them. (Reuters)
A winding road to decarbonization: Rondo Energy’s “heat batteries” could be key to decarbonizing heavy industry, but the company’s first industrial-scale test is at a controversial site: a California oil field. (Canary Media)
If you thought the world built a lot of renewables in the past few years, just wait for the next half of this decade.
Between 2025 and 2030, the world is expected to build nearly 4,600 gigawatts — or 4.6 terawatts, if you please — of clean power, according to a new report from the International Energy Agency.
That’s nearly double the amount built over the previous five-year period, which was in turn more than double the amount built across the five years before that. Put differently, the growth has essentially been exponential.
Solar is the driving force behind this expansion, which is key to transitioning the world away from planet-warming fossil fuels. It accounts for more than three-quarters of the expected increase in renewables between 2025 and 2030 — the result, IEA says, of not only low equipment costs but also solid permitting rules and a broad social acceptance of the tech.
This solar boom will be almost equally split between utility-scale installations and distributed projects, meaning panels atop roofs or shade structures in parking lots, for example. Just over 2 TW of large-scale projects will be built compared to 1.5 TW of the smaller, distributed stuff, IEA predicts. The latter category is increasingly popular both in countries with rising electricity rates and in places with unreliable grids, like Pakistan, where residents are taking refuge in the affordable and stable nature of the tech.
China is installing most of the world’s solar, but the technology is a global phenomenon at this point. At least 29 countries now get over 10% of their electricity from the clean energy source, per a separate report released by think tank Ember earlier this month.
Other types of clean energy are set to grow, too, just not at anything close to solar’s scale.
Installations of onshore wind will leap from 505 GW over the previous five-year period to 732 GW between 2025 and 2030. Offshore wind will more than double from 60 GW to 140 GW. Hydropower will rebound modestly from a down couple of years, but still won’t expand at the levels seen in the early to mid-2010s.
Still, renewables are not gaining enough ground to triple clean capacity by the end of this decade compared with 2023 — a goal countries around the world set two years ago at COP28, the annual United Nations climate conference. In just a few weeks, global leaders will reconvene in Brazil for COP30. The IEA figures, while a sure sign of progress, underscore the steep climb ahead.
The Trump administration has repeatedly blamed offshore wind farms for whale deaths, contrary to scientific evidence. Now the administration is quietly abandoning key research programs meant to protect marine mammals living in an increasingly busy ocean.
The New England Aquarium and the Massachusetts Clean Energy Center, both in Boston, received word from Interior Department officials last month stating that the department was terminating funds for research to help protect whale populations, effective immediately. The cut halted a 14-year-old whale survey program that the aquarium staff had been carrying out from small airplanes piloted over a swath of ocean where three wind farms — Vineyard Wind 1, Sunrise Wind, and Revolution Wind — are now being built.
Federal officials did not publicly announce the cancellation of funds. In a statement to Canary Media, a spokesperson for the New England Aquarium confirmed the clawback, saying that a letter from Interior’s Bureau of Ocean Energy Management dated Sept. 10 had “terminated the remaining funds on a multi-year $1,497,453 grant, which totaled $489,068.”
The aquarium is currently hosting the annual meeting of the North Atlantic Right Whale Consortium, a network of scientists that study one of the many large whale species that reside in New England’s waters. News of the cut to the aquarium’s research project has dampened the mood there. And rumors have been circulating among attendees about rollbacks to an even larger research program, a public-private partnership led by BOEM that tracks whales near wind farm sites from New England to Virginia.
Government emails obtained by Canary Media indicate that BOEM is indeed shutting down the Partnership for an Offshore Wind Energy Regional Observation Network (POWERON). Launched last year, the program expanded on a $5.8 million effort made possible by the Inflation Reduction Act, deploying a network of underwater listening devices along the East Coast “to study the potential impacts of offshore wind facility operations on baleen whales,” referring to the large marine mammals that feed on small krill.
POWERON is a $4.7 million collaboration, still in its infancy, in which wind farm developers pay BOEM to manage the long-term acoustic monitoring for whales that’s required under project permits. One completed wind farm, South Fork Wind, and two in-progress projects, Revolution Wind and Coastal Virginia Offshore Wind, currently rely on POWERON to fulfill their whale-protecting obligations.
With POWERON poised to end, wind developers must quickly find third parties to do the work. Otherwise, they risk being out of compliance with multiple U.S. laws, including the Marine Mammal Protection Act and the Endangered Species Act. Dominion Energy, one of the wind developers participating in POWERON, did not respond to a request for comment.
BOEM officials made no public announcement of POWERON’s cancellation and, according to internal emails, encouraged staffers not to put the news in writing.
“It essentially ended,” said a career employee at the Interior Department who was granted anonymity to speak freely for fear of retribution. The staffer described the government’s multimillion-dollar whale-monitoring partnership as “a body without a pulse.”
The grim news of cuts coincided with the release of some good news. On Tuesday, the North Atlantic Right Whale Consortium published a new population estimate for the North Atlantic right whale, an endangered species pushed to the brink of extinction by 18th-century whaling. After dropping to an all-time low of just 358 whales in 2020, the species, scientists believe, has now grown to 384 individuals.
Concern for the whale’s plight has been weaponized in recent years by anti–offshore wind groups, members of Congress, and even President Donald Trump in an effort to undermine the wind farms in federal court as well as in the court of public opinion.
“If you’re into whales … you don’t want windmills,” said Trump, moments after signing an executive order in January that froze federal permitting and new leasing for offshore wind farms.
This view stands in stark contrast with conclusions made by the federal agency tasked with investigating the causes of recent whale groundings.
A statement posted on the National Oceanic and Atmospheric Administration’s website reads: “At this point, there is no scientific evidence that noise resulting from offshore wind site characterization surveys could potentially cause whale deaths. There are no known links between large whale deaths and ongoing offshore wind activities.”
Climate change has made it difficult for researchers to discern the impacts of wind turbines on whales’ food supply. A government-commissioned report released by the National Academies in 2023 concluded that the impacts of New England’s offshore wind farms on the North Atlantic right whale were hard to distinguish from the effects of a warming world.
For much of the past month, since the aquarium got word of its funding being cut, its researchers have not been able to conduct whale-spotting flights. During this time, construction on Vineyard Wind and Revolution Wind in the southern New England wind energy area plowed forward.
Developers are required to have dedicated observers keeping watch for marine mammals from all construction and survey vessels. But, when it comes to spotting elusive leviathans, nothing quite beats a birds-eye view. The aquarium’s work surveying whales is important for several reasons, according to Erin Meyer-Gutbrod, an assistant professor at the University of South Carolina, who called the clawback “disappointing.”
The project has generated America’s longest-running dataset tracking whale movements near planned and active wind farm areas, she said.
The aquarium’s aerial monitoring dates back to 2011, when the footprints of today’s wind projects were first being sketched out. Historically, North Atlantic right whales were known to feed near southern New England during the winter and spring seasons. In 2022, the aquarium’s dataset allowed researchers to make a remarkable discovery: Unlike in most places on the East Coast, a small number of whales were appearing there year-round. The scientists believe that warmer waters driven by climate change have made the area an “increasingly important habitat” for these whales.
Meyer-Gutbrod said the species’ newly established presence should be a reason for the government to better scrutinize wind farm plans and adapt construction activities.
“Monitoring in and around the lease sites is critical for characterizing right whale distribution. The whales often have seasonal patterns of habitat use, but these patterns are changing. We can’t rely exclusively on historical surveys to guide future offshore development projects,” said Meyer-Gutbrod.
She stressed the importance of continued monitoring to better understand the well-documented hazards to these whales — vessel strikes and rope entanglement from fishing activities — which carry on along the margins of New England’s wind farms. Life-threatening entanglement has been documented in the zone long monitored by aquarium staff. For example, in 2018, aerial researchers were the first to identify that a male right whale, known to scientists as #2310, was caught in fishing rope. A rescue team was unsuccessful at dislodging the rope.
The Interior Department’s cuts come at a time when its own leader is expressing concern for whale populations.
“I’ve got save-the-whale folks saying, ‘Why do you have 192 whale groundings on the beaches of New England?’’” said Interior Secretary Doug Burgum, at an event on Monday hosted by the American Petroleum Institute. He said he was paying attention to people claiming that humpbacks, rights, and other whale species started stranding en masse when “we started building these things,” referring to turbines.
No evidence supports these claims. In fact, Tuesday’s news that the North Atlantic right whale population grew by about 2% from 2023 to 2024 may be the strongest rebuke of Burgum’s statements. That time period coincided with the busiest time for U.S. offshore wind farm construction to date.
Since 2017, the imperiled whale has in fact experienced an annual “unusual mortality event.” Between 10 and 35 whales have shown up dead or seriously injured each year, many displaying injuries consistent with a boat strike. Vineyard Wind 1, America’s first commercial-scale offshore wind farm to get underway, didn’t start at-sea construction until 2022.
Remarkably, there’s been no right whale deaths documented in 2025 — even as five massive wind projects press on with construction in their home range. Heather Pettis, a scientist with the New England Aquarium, attributed this milestone to ongoing “management and conservation efforts,” which include the kind of close monitoring just scuttled by federal cuts.
The aquarium’s spokesperson told Canary Media that its aerial survey team conducted a flight over the southern New England wind energy area on Saturday “using other funding.” It’s unclear how long the program can survive without federal support.
On Monday, an aquarium staffer emailed a group of external scientists, welcoming “any suggestions that you might have for how to continue these surveys.”
From AI to Facebook to Google Maps, the nation’s demand for computing power is growing, with households in the U.S. now averaging a whopping 21 devices — think smartphones, TVs, and thermostats — all connected to the internet.
That was one of many statistics lobbed at North Carolina utility regulators last week as they gathered to grapple with the coming onslaught of data centers, the immense buildings filled with hardware that make our around-the-clock connectivity possible but could strain the state’s electric grid, raise utility bills, and increase pollution.
Over the course of a two-day discussion on how to avoid these downsides, one simple solution came up again and again: Data centers could commit to limiting their electricity consumption slightly for a handful of periods during the year, formalizing the practice of modulating energy use that’s already standard across the industry.
“One of the issues that the commission is particularly interested in is load flexibility,” Karen Kemerait, the commissioner presiding over the technical conference, said to more than one presenter last week, before pressing them on the concept.
In response to Kemerait, experts from Google and other tech giants, along with North Carolina’s predominant utility, Duke Energy, all voiced degrees of support for the notion.
Yet how and whether regulators move to actualize load flexibility remains unclear. The Utilities Commission isn’t required to take action following its Oct. 14 and 15 meeting. And unlike other reforms repeatedly mentioned, such as a special tariff for data centers, the policy doesn’t easily translate to a rate case or other dockets before the panel.
That’s part of why Tyler Norris, a former solar developer and a thought leader on load flexibility who presented last week, hopes it will become a choice for data centers if nothing else.
“At minimum, why not have a voluntary service option that enables a large load to connect faster in exchange for bounded flexibility?” Norris told Canary Media. “In every conversation I’ve been in, I’ve heard no objection to the idea. Obviously, it’s at the discretion of the commission — whether they want to encourage it.”
Data centers aren’t the only new large customers driving ever-growing electricity demand forecasts in North Carolina, which Duke used to justify a massive new fleet of gas plants in its most recent proposed long-term plan. But the centers are the most voracious consumers by far, accounting for over 85% of the energy demand in the economic development pipeline, the utility said last week.
Not all of these facilities in the pipeline will come to fruition: It’s not uncommon for tech companies to request grid connections in multiple locations before deciding where they’ll actually build. But many will materialize, posing thorny issues for the utility and its regulators.
What if Duke can’t build generation quickly enough to serve the energy-hungry centers? Can the company do so while still zeroing out its carbon pollution, as required by state law? How can regulators assure that tech giants, not residential customers, pay for new power plants and associated upgrades to the grid?
Load flexibility could provide an elegant answer to these vexing questions.
The idea is rooted in a counterintuitive reality: Data centers don’t run at maximum tilt 100% of the time — they routinely adjust processing power even as we can post videos to Instagram or EMS responders can transmit lifesaving patient data in the middle of the night.
That’s true for a number of reasons, Norris wrote on his Power and Policy site, including the fact that computer chips could overheat if stretched to their maximum theoretical processing speeds 24/7 and also that data centers plan for redundancy.
“Many facilities are overbuilt to ensure uptime, with servers periodically taken offline for routine maintenance, software upgrades, or hardware replacements,” Norris explained in the August post.
Information on data centers’ exact electricity use is scant, and it appears to vary based on type, but research suggests the facilities’ peak consumption is about 80% of what they could pull from the grid.
Yet utility planners typically assume otherwise, categorizing data centers as “firm loads” that need “firm capacity,” such as an on-demand power plant with an ample supply of fuel, plus an extra reserve margin — in Duke’s case, 22% — in the event of emergency.
In the simplest terms, while Duke might build 122 megawatts of generation to serve a data center that can draw a maximum of 100 megawatts of electricity, the center may never use more than 80 megawatts.
But if prospective data centers were transparent about their electricity-utilization plans and committed to them on paper, utilities could adjust how they anticipate new power capacity — averting the construction of massive amounts of fossil-fuel infrastructure as well as expensive grid improvements.
In September, analytics groups GridLab and Telos Energy published a report finding that Nevada’s biggest utility could delay the need for hundreds of megawatts of new power plants if data centers committed to modest flexibility terms that allow “uptimes” of 99.5%.
Similarly, Norris, a Ph.D. student at Duke University — which has no connection to the utility — is the lead author of a February paper showing that if data centers shaved just 0.5% off their use over the course of the year, 4.1 gigawatts of power capacity in Duke’s territory in the Carolinas could be avoided.
The figure “isn’t everything in terms of their load forecast,” Norris told regulators last week, “but it is arguably a meaningful share.”
While enlisting data centers to curtail their own energy use is still more theory than practice, that’s slowly starting to change. Pacific Gas and Electric in California, for instance, has piloted flexible service agreements that could get data centers online more quickly.
In August, Google announced voluntary flexibility agreements with Indiana Michigan Power and the Tennessee Valley Authority. The following month, the tech giant revealed a similar arrangement with Entergy in Arkansas.
The company vaunted those agreements, along with its plans to self-generate carbon-free electricity, at last week’s meeting. “Google is leaning in,” Rachel Wilson, a representative for the company, told commissioners.
The Data Center Coalition is an alliance of Google, Microsoft, Meta, Amazon, and dozens of other companies that own, operate, or lease data-center capacity. The coalition listed “voluntary demand response and load flexibility” as a recommendation to regulators last week, so long as data centers could get something in return — such as a quicker connection to the grid.
“There has to be some reciprocal value for data centers,” said Lucas Fykes, director of energy policy for the coalition.
Still, the AI race, a lack of transparency about data-center electricity use, and a genuine inability of anyone in this space to predict the future could complicate efforts around load flexibility.
“Not even the most sophisticated data center owner-operators” know what their load will look like in “a rapidly shifting competitive landscape,” Norris wrote in August. “Amid such uncertainty, their preference is generally to maintain maximal optionality.”
Indeed, though Duke expressed openness to load flexibility last week, the company advised caution for the long term.
“Looking at these [load-flexibility agreements] as temporary is important,” said Mike Quinto, the company’s director of planning analytics. “A well-designed voluntary program, that’s great. It’s not something we think should be mandated on a long-term basis.”
And while utilities are well-practiced in demand response for large industrial customers, Public Staff, the state-sanctioned customer advocate, voiced worry last week about scaling the same concept to data centers.
“We haven’t seen these magnitudes trying to interconnect and … potentially drop off the system,” said Dustin Metz, director of the agency’s energy division. “From an academic standpoint, if we can shave off some of those peaks, then that could potentially reduce some of the generation assets that we need to build out,” he said. But enforcement would be essential, and North Carolina is still new to data-center growth. “We’re a little bit of a living lab,” he said.
Utilities tend not to be big fans of rooftop solar, which eats into their revenues by reducing customer reliance on the power grid. A new Ohio lawsuit spotlights the tension between utilities and customers over the clean-energy technology.
The case deals with a monthly charge imposed by the city of Bowling Green’s municipal utility on its few customers with solar panels on their rooftops. Customers who use batteries to store surplus solar power pay even more.
Residents Leatra Harper and Steven Jansto claim the charge, which for them amounts to roughly $56 per month, is an unlawful “tax or penalty.” When combined with the city’s partial payment for power fed back into the grid, it almost doubles the payback period for their $37,000 solar system, the couple said.
The city argues the fee is needed to make sure other customers don’t subsidize those with rooftop solar. As households that produce some of their own electricity buy less from the utility, they pay less for fixed costs built into its retail rates, such as staffing, grid equipment, and maintenance. The utility would then look to other customers to make up the difference.
The situation echoes “cost-shift” arguments that have dogged rooftop solar around the nation. It could also be a preview of a statewide battle to come as the Public Utilities Commission of Ohio gears up to review and revise its net-metering rules, which determine how solar owners are compensated for the energy they send to the grid. Municipal utilities like Bowling Green are not subject to these rules, but the dynamics around the fairness of rooftop solar rates are similar in either case.
For their part, Harper and Jansto installed rooftop solar panels and battery storage at their home in 2019 and 2020 with hopes of lowering their electric bills and cutting their carbon footprint. The investment will eventually pay for itself because they now buy less electricity from the utility while getting some credit for excess fed back to the grid.
“We could get to near net-zero with a cost up front, but with a payback,” said Harper, who is managing director of the FreshWater Accountability Project, an environmental group.
Residential solar doesn’t just help those who invest in it.
“Rooftop solar helps to provide electricity locally. It reduces overall demand,” said Mryia Williams, Ohio program director for the nonprofit group Solar United Neighbors. That means less wasted energy because the power doesn’t need to travel as far as imported electrons, and it lowers stress on the transmission system as climate change exacerbates extreme weather and energy demand grows.
Energy fed into the grid from homeowners’ renewable energy systems can save other customers money, too.
“The highest demand periods on the grid tend to coincide with times when residential solar power is producing at its peak,” said Tony Dutzik, an associate director and senior policy analyst for the Frontier Group, a sustainability-focused think tank. “Those tend to be the times that utilities spend the most money to provide power for their customers.”
The health and environmental benefits of rooftop solar are “pretty obvious,” especially when excess energy offsets purchases from inefficient gas-fueled peaker plants, Dutzik continued. Less consumption of fossil fuels lowers greenhouse gas emissions and other pollution that is linked to multiple illnesses and more than 8 million deaths per year worldwide — problems that could worsen in the U.S. as the Trump administration rolls back climate policy.
Policymakers have “oftentimes undervalued the benefits that rooftop solar can bring, and when you fail to really account for the benefits, you tend to wind up in the situation where people think it’s not fair,” Dutzik said.
Along those lines, Brian O’Connell, utilities director for Bowling Green, said via email that the city adopted its $4-per-kilowatt monthly charge for installed renewable capacity “to ensure rooftop solar customers were paying for the electric service they were receiving, and that the rooftop solar customers were not being subsidized by non-solar customers.”
The rationale resembles an argument promoted by ALEC, the American Legislative Exchange Council, since 2014. The Center for Media and Democracy has long criticized the group for coddling the fossil-fuel industry while working to suppress the vote and stifle dissent.
Consumer advocates and some academics have made similar cases in California, whose solar capacity leads the nation for both rooftop and overall.
But Harper and Jansto were surprised when they learned Bowling Green adopted its “Rider E” charge roughly six months after work on their home’s renewable energy system wrapped up.
The utility had seemed friendly toward solar: Its website touts the significant share of its power that comes from renewables. Yet while the city aims to reduce greenhouse gas emissions, it does have a long-term “take-or-pay” contract to get about half of its electricity from the Prairie State coal plant in Illinois.
Legal and constitutional claims in the couple’s Sept. 19 complaint include unlawful and irrational discrimination. The City of Bowling Green filed its answer on Oct. 14, denying liability and asserting governmental immunity and other defenses.
O’Connell said the $4/kW rate for the charge resulted from a cost-of-service analysis by the municipal utility’s consultant, Sawvel & Associates. The city charges a general retail rate of about 13 cents per kilowatt-hour for any electricity it sells to customers. However, it credits rooftop solar owners just 7.5 cents per kilowatt-hour for whatever they supply to the grid.
O’Connell responded to Canary Media’s request for information about how the Rider E rate was calculated by sharing two spreadsheets. Each lists total savings or costs for the utility from a rooftop solar customer’s energy production, including what the utility saves by not paying other sources for capacity, transmission, and wholesale energy when customers feed excess power onto the grid.
But the documents don’t detail how the utility spends the solar surcharge. It’s unclear whether the rooftop solar fees are helping pay for the Prairie State coal plant: O’Connell’s response to Canary Media’s question merely noted the city still has to purchase energy from the electric market.
Harper and Jansto’s case will move through legal motions and pretrial fact-finding, called discovery, during the coming months. Meanwhile, advocates worry about the broader questions the case raises.
“We can look at it both ways with who’s supporting whom whenever rooftop solar is installed,” said Williams of Solar United Neighbors. In her view, “it’s hard to believe that it’s some sort of subsidized rate,” especially if solar customers get only partial credit for letting others use their excess energy.
Ultimately, Dutzik said, rate systems still should not discourage people from investing in renewable energy for their homes. Indeed, if high fees delay recovery of investments for too long, “fewer people are going to get solar,” Dutzik said. “And that is going to drive up costs for other consumers.”
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.”
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