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Ecolectro, a maker of electrolyzers, has a new manufacturing deal with Re:Build.
By all outward appearances, the green hydrogen industry is in a state of arrested development. The hype cycle of project announcements stemming from Biden-era policies crashed after those policies took too long to implement. A number of high profile clean hydrogen projects have fallen apart since the start of the year, and deep uncertainty remains about whether the Trump administration will go to bat for the industry or further cripple it.
The picture may not be as bleak as it seems, however. On Wednesday, the green hydrogen startup Ecolectro, which has been quietly developing its technology for more than a decade, came out with a new plan to bring the tech to market. The company announced a partnership with Re:Build Manufacturing, a sort of manufacturing incubator that helps startups optimize their products for U.S. fabrication, to build their first units, design their assembly lines, and eventually begin producing at a commercial scale in a Re:Build-owned factory.
“It is a lot for a startup to create a massive manufacturing facility that’s going to cost hundreds of millions of dollars when they’re pre-revenue,” Jon Gordon, Ecolectro’s chief commercial officer, told me. This contract manufacturing partnership with Re:Build is “massive,” he said, because it means Ecolectro doesn’t have to take on lots of debt to scale. (The companies did not disclose the size of the contract.)
The company expects to begin producing its first electrolyzer units — devices that split water into hydrogen and oxygen using electricity — at Re:Build’s industrial design and fabrication site in Rochester, New York, later this year. If all goes well, it will move production to Re:Build’s high-volume manufacturing facility in New Kensington, Pennsylvania next year.
The number one obstacle to scaling up the production and use of cleaner hydrogen, which could help cut emissions from fertilizer, aviation, steelmaking, and other heavy industries, is the high cost of producing it. Under the Biden administration, Congress passed a suite of policies designed to kick-start the industry, including an $8 billion grant program and a lucrative new tax credit. But Biden only got a small fraction of the grant money out the door, and did not finalize the rules for claiming the tax credit until January. Now, the Trump administration is considering terminating its agreements with some of the grant recipients, and Republicans in Congress might change or kill the tax credit.
Since the start of the year, a $500 million fuel plant in upstate New York, a $400 million manufacturing facility in Michigan, and a $500 million green steel factory in Mississippi, have been cancelled or indefinitely delayed.
The outlook is particularly bad for hydrogen made from water and electricity, often called “green” hydrogen, according to a recent BloombergNEF analysis. Trump’s tariffs could increase the cost of green hydrogen by 14%, or $1 per kilogram, based on tariff announcements as of April 8. More than 70% of the clean hydrogen volumes coming online between now and 2030 are what’s known as “blue” hydrogen, made using natural gas, with carbon capture to eliminate climate pollution. “Blue hydrogen has more demand than green hydrogen, not just because it’s cheaper to produce, but also because there’s a lot less uncertainty around it,” BloombergNEF analyst Payal Kaur said during a presentation at the research firm’s recent summit in New York City. Blue hydrogen companies can take advantage of a tax credit for carbon capture, which Congress is much less likely to scrap than the hydrogen tax credit.
Gordon is intimately familiar with hydrogen’s cost impediments. He came to Ecolectro after four years as co-founder of Universal Hydrogen, a startup building hydrogen-powered planes that shut down last summer after burning through its cash and failing to raise more. By the end, Gordon had become a hydrogen skeptic, he told me. The company had customers interested in its planes, but clean hydrogen fuel was too expensive at $15 to $20 per kilogram. It needed to come in under $2.50 to compete with jet fuel. “Regional aviation customers weren’t going to spend 10 times the ticket price just to fly zero emissions,” he said. “It wasn’t clear to me, and I don’t think it was clear to our prospective investors, how the cost of hydrogen was going to be reduced.” Now, he’s convinced that Ecolectro’s new chemistry is the answer.
Ecolectro started in a lab at Cornell University, where its cofounder and chief science officer Kristina Hugar was doing her PhD research. Hugar developed a new material, a polymer “anion exchange membrane,” that had potential to significantly lower the cost of electrolyzers. Many of the companies making electrolyzers use designs that require expensive and supply-constrained metals like iridium and titanium. Hugar’s membrane makes it possible to use low-cost nickel and steel instead.
The company’s “stack,” the sandwich of an anode, membrane, and cathode that makes up the core of the electrolyzer, costs at least 50% less than the “proton exchange membrane” versions on the market today, according to Gordon. In lab tests, it has achieved more than 70% efficiency, meaning that more than 70% of the electrical energy going into the system is converted into usable chemical energy stored in hydrogen. The industry average is around 61%, according to the Department of Energy.
In addition to using cheaper materials, the company is focused on building electrolyzers that customers can install on-site to eliminate the cost of transporting the fuel. Its first customer was Liberty New York Gas, a natural gas company in Massena, New York, which installed a small, 10-kilowatt electrolyzer in a shipping container directly outside its office as part of a pilot project. Like many natural gas companies, Liberty is testing blending small amounts of hydrogen into its system — in this case, directly into the heating systems it uses in the office building — to evaluate it as an option for lowering emissions across its customer base. The equipment draws electricity from the local electric grid, which, in that region, mostly comes from low-cost hydroelectric power plants.
Taking into account the expected manufacturing cost for a commercial-scale electrolyzer, Ecolectro says that a project paying the same low price for water and power as Liberty would be able to produce hydrogen for less than $2.50 per kilogram — even without subsidies. Through its partnership with Re:Build, the company will produce electrolyzers in the 250- to 500-kilowatt range, as well as in the 1- to 5-megawatt range. It will be announcing a larger 250-kilowatt pilot project later this year, Gordon said.
All of this sounded promising, but what I really wanted to know is who Ecolectro thought its customers were going to be. Demand for clean hydrogen, or the lack thereof, is perhaps the biggest challenge the industry faces to scaling, after cost. Of the roughly 13 million to 15 million tons of clean hydrogen production announced to come online between now and 2030, companies only have offtake agreements for about 2.5 million tons, according to Kaur of BNEF. Most of those agreements are also non-binding, meaning they may not even happen.
Gordon tied companies’ struggle with offtake to their business models of building big, expensive, facilities in remote areas, meaning the hydrogen has to be transported long distances to customers. He said that when he was with Universal Hydrogen, he tried negotiating offtake agreements with some of these big projects, but they were asking customers to commit to 20-year contracts — and to figure out the delivery on their own.
“Right now, where we see the industry is that people want less hydrogen than that,” he said. “So we make it much easier for the customer to adopt by leasing them this unit. They don’t have to pay some enormous capex, and then it’s on site and it’s producing a fair amount of hydrogen for them to engage in pilot studies of blending, or refining, or whatever they’re going to use it for.”
He expects most of the demand to come from industrial customers that already use hydrogen, like fertilizer companies and refineries, that want to switch to a cleaner version of the fuel, or hydrogen-curious companies that want to experiment with blending it into their natural gas burners to reduce their emissions. Demand will also be geographically-limited to places like New York, Washington State, and Texas, that have low-cost electricity available, he said. “I think the opportunity is big, and it’s here, but only if you’re using a product like ours.”
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On coal mines, Energy Star, and the EV tax credit
Current conditions: Storms continue to roll through North Texas today, where a home caught fire from a lightning strike earlier this week • Warm, dry days ahead may hinder hotshot crews’ attempts to contain the 1,500-acre Sawlog fire, burning about 40 miles west of Butte, Montana• Severe thunderstorms could move through Rome today on the first day of the papal conclave.
The International Energy Agency published its annual Global Methane Tracker report on Wednesday morning, finding that over 120 million tons of the potent greenhouse gas were emitted by oil, gas, and coal in 2024, close to the record high in 2019. In particular, the research found that coal mines were the second-largest energy sector methane emitter after oil, at 40 million tons — about equivalent to India’s annual carbon dioxide emissions. Abandoned coal mines alone emitted nearly 5 million tons of methane, more than abandoned oil and gas wells at 3 million tons.
“Coal, one of the biggest methane culprits, is still being ignored,” Sabina Assan, the methane analyst at the energy think tank Ember, said in a statement. “There are cost-effective technologies available today, so this is a low-hanging fruit of tackling methane.” Per the IEA report, about 70% of all annual methane emissions from the energy sector “could be avoided with existing technologies,” and “a significant share of abatement measures could pay for themselves within a year.” Around 35 million tons of total methane emissions from fossil fuels “could be avoided at no net cost, based on average energy prices in 2024,” the report goes on. Read the full findings here.
Opportunities to reduce methane emissions in the energy sector, 2024
IEA
The Environmental Protection Agency told staff this week that the division that oversees the Energy Star efficiency certification program for home appliances will be eliminated as part of the Trump administration’s ongoing cuts and reorganization, The Washington Post reports. The Energy Star program, which was created under President George H.W. Bush, has, in the past three decades, helped Americans save more than $500 billion in energy costs by directing them to more efficient appliances, as well as prevented an estimated 4 billion metric tons of greenhouse gas from entering the atmosphere since 1992, according to the government’s numbers. Almost 90% of Americans recognize its blue logo on sight, per The New York Times.
President Trump, however, has taken a personal interest in what he believes are poorly performing shower heads, dishwashers, and other appliances (although, as we’ve fact-checked here at Heatmap, many of his opinions on the issue are outdated or misplaced). In a letter on Tuesday, a large coalition of industry groups including the Air-Conditioning, Heating, and Refrigeration Institute, the Association of Home Appliance Manufacturers, and the U.S. Chamber of Commerce wrote to EPA Administrator Lee Zeldin in defense of Energy Star, arguing it is “an example of an effective non-regulatory program and partnership between the government and the private sector. Eliminating it will not serve the American people.”
House Speaker Mike Johnson suggested that the electric vehicle tax credit may be on its last legs, according to an interview he gave Bloomberg on Tuesday. “I think there is a better chance we kill it than save it,” Johnson said. “But we’ll see how it comes out.” He estimated that House Republicans would reveal their plan for the tax credits later this week. Still, as Bloomberg notes, a potential hangup may be that “many EV factories have been built or are under construction in GOP districts.”
As we’ve covered at Heatmap, President Trump flirted with ending the $7,500 tax credit for EVs throughout his campaign, a move that would mark “a significant setback to the American auto industry’s attempts to make the transition to electric vehicles,” my colleague Robinson Meyer writes. That holds true for all EV makers, including Tesla, the world’s most valuable auto company. However, its CEO, Elon Musk — who holds an influential position within the government — has said he supports the end of the tax credit “because Tesla has more experience building EVs than any other company, [and] it would suffer least from the subsidy’s disappearance.”
Constellation Energy Corp. held its quarterly earnings call on Tuesday, announcing that its operating revenue rose more than 10% in the first three months of the year compared to 2024, beating expectations. Shares climbed 12% after the call, with Chief Executive Officer Joe Dominguez confirming that Constellation’s pending purchase of natural gas and geothermal energy firm Calpine is on track to be completed by the end of the year, and that the nuclear power utility is “working hard to meet the power needs of customers nationwide, including powering the new AI products that Americans increasingly are using in their daily lives and that businesses and government are using to provide better products and services.”
But as my colleague Matthew Zeitlin reported, Dominguez also threw some “lukewarm water on the most aggressive load growth projections,” telling investors that “it’s not hard to conclude that the headlines are inflated.” As Matthew points out, Dominguez also has some reason to downplay expectations, including that “there needs to be massive investment in new power plants,” which could affect the value of Constellation’s existing generation fleet.
The Rockefeller Foundation aims to phase out 60 coal-fired power plants by 2030 by using revenue from carbon credits to cover the costs of closures, the Financial Times reports. The team working on the initiative has identified 1,000 plants in developing countries that would be eligible for the program under its methodology.
Rob and Jesse go deep on the electricity machine.
Last week, more than 50 million people across mainland Spain and Portugal suffered a blackout that lasted more than 10 hours and shuttered stores, halted trains, and dealt more than $1 billion in economic damage. At least eight deaths have been attributed to the power outage.
Almost immediately, some commentators blamed the blackout on the large share of renewables on the Iberian peninsula’s power grid. Are they right? How does the number of big, heavy, spinning objects on the grid affect grid operators’ ability to keep the lights on?
On this week’s episode of Shift Key, Jesse and Rob dive into what may have caused the Iberian blackout — as well as how grid operators manage supply and demand, voltage and frequency, and renewables and thermal resources, and operate the continent-spanning machine that is the power grid. Shift Key is hosted by Robinson Meyer, the founding executive editor of Heatmap, and Jesse Jenkins, a professor of energy systems engineering at Princeton University.
Subscribe to “Shift Key” and find this episode on Apple Podcasts, Spotify, Amazon, or wherever you get your podcasts.
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Here is an excerpt from our conversation:
Robinson Meyer: So a number of people started saying, oh, this was actually caused because there wasn’t enough inertia on the grid — that Spain kind of flew too close to the sun, let’s say, and had too many instantaneous resources that are metered by inverters and not by these large mechanical generators attached to its grid. Some issue happened and it wasn’t able to maintain the frequency of its grid as needed. How likely do you think that is?
Jesse Jenkins: So I don’t think it’s plausible as the precipitating event, the initial thing that started to drive the grid towards collapse. I would say it did contribute once the Iberian grid disconnected from France.
So let me break that down: When Spain and Portugal are connected to the rest of the continental European grid, there’s an enormous amount of inertia in that system because it doesn’t actually matter what’s going on just in Spain. They’re connected to this continen- scale grid, and so as the frequency drops there, it drops a little bit in France, and it drops a little bit in Latvia and all the generators across Europe are contributing to that balance. So there was a surplus of inertia across Europe at the time.
Once the system in Iberia disconnected from France, though, now it’s operating on its own as an actual island, and there it has very little inertia because the system operator only scheduled a couple thousand megawatts of conventional thermal units of gas power plants and nuclear. And so it had a very high penetration on the peninsula of non-inertia-based resources like solar and wind. And so whatever is happening up to that point, once the grid disconnected, it certainly lacked enough inertia to recover at that point from the kind of cascading events. But it doesn’t seem like a lack of inertia contributed to the initial precipitating event.
Something — we don’t know what yet — caused two generators to simultaneously disconnect. And we know that we’ve observed oscillation in the frequency, meaning something happened to disturb the frequency in Spain before all this happened. And we don’t know exactly what that disturbance was.
There could have been a lot of different things. It could have been a sudden surge of wind or solar generation. That’s possible. It could have been something going wrong with the control system that manages the automatic response to changes in frequency — they were measuring the wrong thing, and they started to speed up or slow down, or something went wrong. That happened in the past, in the case of a generator in Florida that turned on and tried to synchronize with the grid and got its controls wrong, and that causes caused oscillations of the frequency that propagated all through the Eastern Interconnection — as far away as North Dakota, which is like 2,000 miles away, you know? So these things happen. Sometimes thermal generators screw up.
Music for Shift Key is by Adam Kromelow.
Then again, there are reasons why he’d want to focus on existing generation.
Just how big is the data center boom, really? How much is electricity demand going to expand over the coming decades? Business plans, government policy, and alarming environmental forecasts are all based on the idea that we’re on an unrelenting ride upwards in terms of electricity use, especially from data centers used to power artificial intelligence.
It’s one reason why the new Trump administration declared in the first days of its return to power that the country was in an “energy emergency,” and hasbeen used as a justification for its attempted revival of the coal industry.
But one mildly dissenting voice came from a perhaps-unexpected corner: the power industry.
Constellation Energy’s Chief Executive Officer Joseph Dominguez spent a portion of the company’s quarterly earnings call Tuesday throwing lukewarm water on the most aggressive load growth projections, even as the company looks to profit from increased demand for the power that its over 30,000-megawatt, largely nuclear fleet serves.
Dominguez told his audience of investors and analysts that utilities and their power customers have been telling Constellation that “the same data center need is being considered in multiple jurisdictions across the United States at the same time, just like fishing. If you’re a fisherman, you put a bunch of lines in the water to try to catch fish, and the data center developers are doing exactly the same thing.”
This means that different electricity markets or utility territories could report the same future data center demand, when ultimately the developer will pick just one site.
Tallying the demand growth projections from a few large power markets — namely MISO, which largely serves the Midwest; PJM, which largely serves the East Coast; and ERCOT, the Texas energy market — which together “account for less than half” of U.S. power demand, Dominguez said, Constellation finds that they project “notably higher” demand growth than many third-party consultants and analysts foresee for the country as a whole.
“It’s hard not to conclude that the headlines are inflated,” Dominguez said. He further claimed that Constellation had “done the math,” and that “if Nvidia were able to double its output and every single chip went to ERCOT, it still wouldn’t be enough chips to support some of the load forecasts.”
He argued that utilities tend to overstate load growth — an observation backed up by research from the Rocky Mountain Institute. “We get it,” he said. “Utilities have to plan to ensure that the system is reliable.” That frequently means erring on the side of having more generation and transmission to serve future demand as opposed to being caught short.
Dominguez is hardly the first voice to call into question load growth forecasts. Energy industry consultant Jonathan Koomey told Heatmap more than a year ago that “everyone needs to calm the heck down” about AI-driven load growth. Data center developers, chipmakers, and AI companies would likely find efficiencies to get more computing power out of less electric power, he predicted, similar to how the original data center buildout avoided catastrophic predictions of imminent power shortages and spiking electricity prices in the early 2000s.
Since then, demand growth projections have done nothing but rise. But even just a few weeks ago, Peter Freed, Meta’s former director of energy strategy, told Heatmap’s Shift Key podcast, “It is simultaneously true that I think this is going to be a really large demand driver and that we have bubble-like characteristics in terms of the amount of stuff that people are trying to get done.”
Now, to be clear, Dominguez has a reason to talk down expectations of future demand growth — and with it the expectation that there needs to be massive investment in new power plants. Constellation owns and operates a fleet of nuclear power plants, and is bringing on a gas-heavy fleet with its planned acquisition of Calpine.
Dominguez also said that new natural gas and renewables were likely to prove expensive to build.
“The cost of new entry, whether that be for combined cycle machines or solar with storage, has gone up substantially, as has the time to build and site these assets,” Dominguez said. “Now, at the end of the day, in a tightening market, we compete with the cost of new entry.”
This is halfway consistent with what other big players in the energy industry have been saying. John Ketchum, the chief executive of NextEra, which has a large renewables development business,has been telling anyone who will listen that the way to meet urgent load growth is with renewables and batteries, as they can be built cheaper and faster than natural gas, let alone nuclear.
Dominguez’s take, however, is that it’s all quite expensive and lengthy considering the likely level of need.
“When I listen to some of the comments on these calls, I just have to tell you, folks, I think the load is being overstated. We need to pump the brakes here.”