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The share of power generated by wind and solar exceeded 30% in over a dozen states in 2025, which was a banner year for renewables even amid Trump’s attacks.

Quick — ignore the map above and take a guess: Which three states get the highest share of their power from wind and solar?

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If you said Iowa, South Dakota, and New Mexico, well done. If you had Texas or California in there, fair enough — but neither of those clean-energy behemoths made it onto the podium, per the latest report from trade group American Clean Power Association.

Of the electricity produced in Iowa last year, 61% came from wind and solar — and pretty much all of that was wind. For decades, the state has been a leader on wind energy, though in recent years, development of new projects has dried up because of mounting local opposition and the Trump administration’s broader attacks on renewable energy.

South Dakota is a similar story, at 59%. Consistently gusty weather and ample land have led the state to install lots of wind turbines, and solar is scant in comparison.

New Mexico, which got about half its electricity from wind and solar in 2025, is a bit more balanced. Wind accounted for 36% of its power, and solar for 17%. The state is also a leader in grid batteries, which it is building out quickly to save more renewable energy for periods when the sun isn’t shining and the wind isn’t blowing.

The leaderboard could soon change as some states charge toward ambitious 2030 clean energy targets. California, for one, saw a massive leap in renewable energy production last year, with solar and wind accounting for 44% of its generation. The year before, that figure was 38%.

In total, 13 states generated more than 30% of their electricity from wind and solar last year, and the clean energy sources provided 17% of the nation’s grid-scale electricity overall — a new record.

Wind and solar are growing in the U.S. despite fierce opposition from the Trump administration, which has ripped away tax credits and slow-rolled or withheld permits for dozens of gigawatts’ worth of projects.

The reason for the sector’s ascent is simple. As electricity demand and utility bills spike, solar and wind — along with batteries — are cheap and fast ways to get more power flowing. The same cannot be said for coal plants (which are expensive to run) or natural gas facilities (which take a long time to build because of an equipment supply crunch).

These facts add up to one outcome: Solar and wind will keep rising to new heights in states across the nation.

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‍Facing new regulations and stiff competition from China, Sweden and other EU countries are racing to decarbonize steel production. It all hinges on green hydrogen.

In 1872, while on a trip to Europe, Andrew Carnegie met with an engineer and inventor named Henry Bessemer. During the Crimean War, Bessemer had accidentally discovered an efficient (for the time) new method of making steel, which involved blowing air through molten iron to remove its impurities. He later developed it into a process that a few small steelworks had already adopted by the time of Carnegie’s visit. Carnegie had been following Bessemer’s invention from the U.S., but none of the steelworks employing it there had really taken off. The future titan of industry was nonetheless wowed by the older man’s presentation, and returned home convinced that steelmaking should be his next venture.

There was no doubt as to where to make such an investment. Manufacturing steel required huge volumes of iron ore and coal, and both were abundant around Pittsburgh. The city also enjoyed an advantageous location for transporting the heavy end product by barge. The Allegheny and Monongahela rivers merge there into the Ohio, down which one can navigate to the Mississippi and the Gulf of Mexico. Plus, Carnegie had a ready customer in the expanding railroad industry and political help in the form of a recently enacted steep tariff on imported rails. So, the Edgar Thomson Steel Works was erected in 1875, 10 miles outside Pittsburgh, in Braddock. (The thing is still running.)

One hundred fifty years later, a similar confluence of circumstances can be found nearly 100 kilometers (62 miles) south of the Arctic Circle, in Luleå, Sweden — one that could lead to the next big innovation in steelmaking. In 1872, no one knew, or cared, that Bessemer’s method was actually carbon manufacture with a side hustle in steel: Even in today’s furnaces, 1.8 metric tons of carbon dioxide are emitted for every ton of steel, give or take. But now, a new, cleaner method of steelmaking exists. It involves using hydrogen instead of coal to produce iron from iron ore in a process called direct reduction, then fashioning that iron into steel in an electric arc furnace.

When renewable electricity powers the hydrogen production and the electric arc furnace, the CO₂ per metric ton of steel in direct and indirect emissions can be reduced to 0.4 metric tons — about 80% less than from the most efficient methods developed since Bessemer’s time.

Hybrit Development, a joint venture of the Swedish companies LKAB (iron ore mining), SSAB (iron and steel production), and Vattenfall (energy), is developing an end-to-end process for steelmaking using hydrogen in Luleå. The group opened a pilot plant in 2020 and is working to build its first commercial-scale plant. Stegra, another Swedish startup, is aiming to do the same thing about 40 kilometers (25 miles) north, in Boden.

Much like the Pittsburgh area in the 1800s, northern Sweden enjoys certain geographical advantages: a surplus of hydropower, enormous iron ore mines 250 kilometers (155 miles) to the north, and a thriving seaport.

Sweden is also getting a nudge from the European Union, which aims to make Europe the first carbon-neutral continent by 2050. Starting this year, the steel industry across the 27 member states has to start paying for its emissions under the EU Emissions Trading System — the allowances initially granted to give it time to adjust are being phased out. The new regulations will sink its business model.

Germany, Norway, and other European countries are making similar efforts to decarbonize steel production, and as with many things concerning the energy transition, China is leaping ahead. The world’s largest ironmaking plant fueled by hydrogen started operating at full capacity late last year in Zhanjiang City, Guangdong. The U.S., meanwhile (as with many things concerning the energy transition), lags behind. The Biden administration sought to spur green hydrogen projects with tax credits and subsidies, but since January 2025, President Donald Trump has killed $12.5 billion in federal funding for clean energy projects — including some in green hydrogen — and threatened to scrap an additional $12.2 billion in existing grants. (SSAB was behind one of those projects, in Mississippi, but — perhaps seeing the writing on the wall — it quit the subsidy award process just before Trump took office and says it has no plans to try again in the U.S.)

With more than 300,000 jobs and 152 billion euros in economic activity tied to the EU’s steel industry, the stakes are high for Europe in the global race to decarbonize steel. And given the industry’s 5% contribution to overall bloc emissions, if it succeeds, the benefit to the climate will be enormous.

The hulking, rusting blast furnace that greets visitors just inside the gate of SSAB’s Luleå facility is a working remnant of traditional steelmaking. A short drive across the 265-hectare (1-square-mile) site follows the route of an elevated conveyor belt connecting the coking plant, where coal is cooked down, to the blast furnace. The road continues on to the building that houses Hybrit’s direct-reduced-iron demonstration plant. At 50 meters (164 feet) high, it’s about as tall as the blast furnace, but the similarities end there. The demonstration plant’s right angles and light-gray aluminum siding stand in stark contrast to the older structure’s tangle of rusted, ashen cylinders and beams.

General Manager Gunilla Hyllander met me in the parking lot that divides the demonstration plant from Hybrit’s administration building. Just inside the door to the offices, a loose pile of employees’ shoes dripped snow — though at minus 11 degrees Celsius (12°F), it was almost balmy for January in northern Sweden. We sat down in a large room with samples of iron made in the DRI plant laid out on tables. Though the facility wasn’t in operation that day, Hyllander could see the future starting to take shape.

“Hydrogen reduction in itself is not new,” she said. ​“People have been thinking about that for years. But in an efficient, safe, and productive manner? That has not been proven before. We think that all the processes from mine to steel could be converted to a fossil-free manner. We’re using all existing technologies and putting it together in a new value chain.”

Steel has been produced on this site since the 1940s, originally by Norrbottens Järnverk. In 1978, Sweden’s government decided to socialize the country’s steel industry by merging Norrbottens and two other struggling companies under state ownership, as Svenskt Stål AB (Swedish Steel Ltd.). SSAB reprivatized in 1992, though the government now owns a 16% share. A major investment in the Luleå operation came in 1998, when the company built the current blast furnace at a cost of 850 million kronor (around $150 million, inflation-adjusted). That timing is significant. A blast furnace requires major maintenance about every 15 years. After relining its facility once, SSAB realized that by 2030 at the latest, it would need to either make that investment again, which would mean producing 7% of the country’s carbon emissions even after the carbon allowances had expired, or figure out a way to do things differently. The company took the second path, banding together with LKAB and Vattenfall to form Hybrit — short for ​“hydrogen breakthrough ironmaking technology” — in 2016.

SSAB’s decarbonization challenge is a microcosm of the European steel industry’s. It’s going to be a heavy lift. The company’s gigantic share of Sweden’s carbon emissions is no outlier. Globally, the sector produces about 7% to 9% of anthropogenic CO₂ emissions, according to the World Steel Association — about the same as all the world’s passenger vehicles — and accounts for over a quarter of the EU’s industrial emissions. Demand for steel is projected to grow by nearly 20% by 2050, according to BloombergNEF.

The traditional steelmaking process that Carnegie helped popularize primarily emits carbon in two ways: First, coal is burned as fuel to heat blast furnaces to above 1,000°C (1,832°F). Second, a purified form of coal, called ​“coke,” is heated inside the furnace to induce a necessary chemical reaction that strips oxygen from iron ore (the ​“reduction”), producing iron and — the second emission — releasing CO₂.

Hydrogen-based direct reduction addresses both problems. Instead of carbon, hydrogen serves as the reducing agent for the iron, combining with oxygen to produce water vapor instead of CO₂. The process operates at lower temperatures than blast furnaces do, requiring less energy. When that energy comes from renewables and the hydrogen is produced from electrolyzers — machines that split hydrogen from water — powered by wind or solar, the result is near-zero emissions. ​“In the development program, we are close to zero CO₂ emissions per tonne of crude steel — 42 kilograms, instead of 1.6 tonnes,” Hyllander said.

Direct reduction with natural gas has been used in commercial operations for decades, particularly in the Middle East and India, where cheap gas has historically been abundant. What’s changing now is the fuel source. Hybrit started with natural gas to establish a baseline for emissions, but in 2021 it began producing hydrogen with two stacks of electrolyzers. Situated behind the DRI plant, the electrolyzers aren’t much to look at. With their cylindrical shape and multiple rubber tubes, they resemble sewage pipes on life support. But inside is a complex system of wires, tanks, valves, and gaskets that passes an electrical current through an alkaline solution between an anode and cathode, splitting the water into hydrogen on one end and oxygen on the other.

Over the past five years, Hybrit has operated its pilot plant for 61 weeks, producing 5,000 metric tons of fossil-free sponge iron pellets, each about the size of a chocolate-covered almond, which a microscope reveals to have a porous structure. The company has also conducted over 400 trial melts at the research institute Swerim, down the road, which operates its own electric arc furnace. At least one automaker is already using the end product in its vehicles, and Hybrit’s green steel has been incorporated into production lines for heavy machinery and consumer products. The process works. The question is whether it can scale economically.

Europe has positioned itself as the global leader in green steel, and major producers have set ambitious targets. SSAB and Thyssenkrupp aim for carbon neutrality by 2045; ArcelorMittal aims for 2050. Already, more than half the near-zero-emissions steel projects in the global Green Steel Tracker are in the EU. Among them are Hybrit’s neighbor and competitor, Stegra, with a goal of producing 5 million metric tons of green steel annually by 2030 at its Boden plant; and Finland’s Blastr, targeting 2.5 million metric tons by 2026. (In comparison, Edgar Thomson outside Pittsburgh, now part of the Mon Valley Works complex, produces 2.9 million tons annually.) Thyssenkrupp, ArcelorMittal, and Salzgitter have all announced hydrogen-based projects in Germany. The EU has approved nearly 9.3 billion euros in state aid for these ventures. The European Steel Association forecasts emissions reductions of 81.5 million metric tons of CO₂ equivalent per year by 2030 if current projects are completed on schedule.

But progress has stalled. As of August 2024, 80% of announced direct reduction capacity hadn’t moved forward. Only 3% had become operational. Recent setbacks have raised serious doubts about whether hydrogen-based steelmaking can scale up in time to meet the emissions-reductions targets.

Stegra, which, like Hybrit, aims to produce hydrogen on-site, has struggled through at least two seismic funding shortfalls. ArcelorMittal, meanwhile, has scrapped plans to convert two steel plants to green production in Germany because of the high electricity costs of running an electric arc furnace. And Thyssenkrupp announced in March 2025 that it might need to ditch a $3.3 billion conversion project, citing the lack of affordable green hydrogen needed to supply its steel mill.

Steel producers such as Thyssenkrupp that plan to outsource their hydrogen face a classic chicken-and-egg problem. They need confidence there will be a hydrogen supply before they’ll commit to building. But hydrogen producers need committed offtake before they’ll invest in production, and pipeline operators need both before they’ll convert networks to use H₂. Nobody wants to move first.

“Companies are not going to invest if they don’t know the pipeline is going to be ready on time and that the offtake is there,” said Leif Christian Kröger, Thyssenkrupp’s head of public affairs.

In 2022, European leaders tried to address the lack of supply by setting an ambitious target of 10 million metric tons of domestic green hydrogen production and 10 million metric tons imported by 2030. Hydrogen conferences sprouted up in Rotterdam and Düsseldorf, replete with optimistic projections of when green hydrogen would meet price parity with ​“gray hydrogen” (produced using natural gas) and ​“blue hydrogen” (natural gas with carbon capture). But then the reality hit of how much renewable electricity would be required to meet the targets. With estimates running to the equivalent of almost twice the entire United Kingdom’s consumption in 2020 (a pandemic year), it’s not surprising that progress so far has been an underwhelming 1% of the goal. ​“They need to show a lot of progress in the next 12 to 18 months” to get there, Daniyal Sheikh, hydrogen market analyst at ICIS, a commodities research service in London, told me in October.

Nima Pegemanyfar is executive vice president of customer operations at Quest One in Hamburg, Germany. His company was making 1-megawatt electrolyzer stacks as far back as 1997 (as H-TEC Hydrogen Energy Systems) and in 2023 launched a 10-MW-to-100-MW modular plant. ​“Capacity was the restraint a few years ago, so we built that up as an industry,” he said. ​“Now, demand is what’s lagging.” This isn’t just the self-interested complaint of an electrolyzer manufacturer. Christine Falken-Großer, of Germany’s Ministry of Economic Affairs and Climate Action, agreed that ​“demand is the essential element right now to unlock growth” in green hydrogen production.

But the economics are punishing to buyers. Green hydrogen costs at least twice as much as its fossil-based alternative. Though natural gas prices have spiked with the closure of the Strait of Hormuz, futures contracts indicate the market believes this will be a temporary disruption that will be resolved before green hydrogen scales up enough to compete on price.

“Producer costs are higher than the price, and customers are not willing to pay the premium,” said Camilla Montemurro, a policy adviser at the trade association Eurogas. BloombergNEF doesn’t expect green hydrogen to reach price competitiveness before 2030, leaving scant time before the carbon allowances expire to achieve what it took Hybrit a decade to do.

Electricity costs in Germany — Europe’s leader in steel production — are a significant hurdle. ​“The green steel industry doesn’t want to decarbonize as fast as planned, because of the high cost of renewable electricity,” Pegemanyfar said. A million-metric-tons-per-year direct reduction plant running fully on hydrogen requires about 70,000 metric tons of hydrogen annually. That amounts to roughly 800 MW to 900 MW of electrolyzer capacity with around 1 gigawatt of electrical transformer capacity — a capital expenditure of 350 million euros to 700 million euros before you’ve bought any iron ore.

Infrastructure gaps compound the cost hurdle. Europe envisions several ​“hydrogen backbones” — networks of converted natural gas pipelines carrying hydrogen from ports or production sites to industrial (and perhaps commercial and residential) users. But the chicken-and-egg problem persists. ​“Pipeline operators won’t invest without offtake, and users won’t buy without infrastructure,” said Dirk Niemeier, director and Clean Hydrogen Solutions lead at PwC in Munich.

The backbone is only the half of it. Just as electricity requires tall transmission towers to move large volumes of power long distances and smaller wires to distribute it to users from central hubs, hydrogen requires both thick pipes (the backbone) and skinny pipes (for delivery to the end customers). Barbara Jinks, director of Ready4H2, an industry group that promotes using gas distribution grids to deliver hydrogen, described the scale of the undertaking: ​“More than half the gas won’t get to the end user with current infrastructure. Anything more than 3 kilometers [1.8 miles] from the backbone needs a distribution line.” The gas industry would rather sell capacity in the pipelines in which it has already invested billions to hydrogen producers than see this asset stranded as the world switches to running on electricity.

But ​“hydrogen has rather unique effects on materials, and many of them are not good,” noted P. Chris Pistorius, co-director of the Center for Iron and Steelmaking Research at Carnegie Mellon University in Pittsburgh. The pipeline networks can be converted, but that takes money and time.

Storage presents its own conundrum. Daniel Mercer, managing director of Storengy, a subsidiary of French energy giant Engie, hopes to provide ​“the hydrogen battery for all of Europe” by storing the gas in underground geologic formations near Hamburg, Germany. But funding is scarce. ​“We are the only part of the hydrogen system not supported by the government, yet we’re the part that takes the longest to develop,” he said. ​“Finding funding is the toughest part of my job right now. I need somebody to give me 1 billion euros and be OK with not making any money for eight years” while the underground H₂ storage project is built out.

Importing hydrogen instead of producing it in Europe wouldn’t really help. Several European ports are developing terminals to import ammonia, which contains hydrogen molecules and is easier, cheaper, and safer to ship than pure H₂. But converting hydrogen to ammonia and back again loses about half the energy contained in the original batch. So when the buyer collects a shipment ​“in Rotterdam or Hamburg, the price is suddenly double,” said Alexander Fleischanderl, chief technology officer of the London-based Primetals Technologies, which developed a proprietary technology called Hyfor for making green steel. ​“This is by far not competitive anymore.”

Like Hybrit, Primetals Technologies gets around problems with importing hydrogen by attaching production to its green-steel manufacturing process. It hopes to offer green steelmaking as a kind of service and secure contracts to build plants for companies shutting down their blast furnaces.

Amid these converging pressures, European policymakers and industry leaders must confront tricky questions about the continent’s industrial future. Can Europe keep steel production at today’s levels while ratcheting down emissions through the necessary conversion? Can the current political environment withstand losing jobs to countries where steel can be produced at lower cost?

“I would bet that at least some capacity will move away from Europe to more competitive regions,” Fleischanderl said. The logic is straightforward. With steelmaking, 80% of the energy and just 20% of the jobs are in converting iron ore to iron. Turning that iron into steel takes 20% of the energy and 80% of the jobs. ​“Why should we transport hydrogen if we could use the hydrogen locally” in producing iron? Fleischanderl asked. Most of the world’s iron ore is in places with ample opportunity for renewable energy — Australia, Brazil, Canada — and thus relatively cheap hydrogen. Decoupling the two processes geographically — producing the iron overseas and then shipping it to Europe, where it can be made into steel in an electric arc furnace running on renewable energy — would sacrifice relatively few jobs to gain a lot in savings on green hydrogen.

Pistorius also thinks that the less labor-intensive part of the steelmaking process could move overseas, where renewables are cheaper. ​“There’s a lot going for that argument,” he said. ​“Shipping iron is a relatively good way to [move] the energy around rather than trying to ship ammonia and regenerate it to hydrogen at the destination.”

But Germany’s 79,000 steel jobs hold an outsize place in the country’s identity. Next door in the Netherlands, farmers representing 1% of jobs and 1% of GDP almost brought down the government when it threatened to tighten pollution regulations. Germany’s ascendant populist forces, at least, are likely to resist sacrificing even 20% of steel jobs on the altar of green energy.

Either way, strategic considerations argue for maintaining at least some domestic production. Steel is essential for defense, infrastructure, and the energy transition itself — wind turbines and transmission towers are largely steel. The current energy crisis spurred by the war in Iran has driven home once again the risks of long supply chains, and the EU’s Carbon Border Adjustment Mechanism, which functions as a tariff on high-carbon imports, aims to protect European producers that invest in decarbonization.

Additional policy changes could further accelerate progress. The EU’s Renewable Energy Directive (RED 3) imposes strict requirements on what qualifies as green hydrogen — requirements that many argue are too stringent. ​“EU needs to relax RED 3,” Niemeier said. ​“That would bring down the cost.”

“You can’t have a free market at the beginning of this,” said Ad van Wijk, professor of future energy systems at Delft University of Technology in the Netherlands. ​“There will be buildup to a market, but you need some organization at the beginning. Are we able in the EU to organize all this, with all the politics that are behind the different fuels?”

Falken-Großer has learned from experience that “‘quickly’ is not a word that is known in Brussels.”

Julia Metz of Agora Industry, a clean industry research institution, suggests public procurement requirements and state-funded infrastructure projects to provide the nascent industry with guaranteed offtake. ​“Lead markets [created] through binding requirements in public procurement” would build ​“secure demand for green steel,” she said in an interview with Clean Energy Wire. The European Commission’s proposed Industrial Accelerator Act, part of the Clean Industrial Deal, aims to support domestic clean industries through public procurement.

Even without these nudges, 510 green hydrogen projects have reached final investment decisions, including 83 since May 2024, and customer commitments for green steel are emerging. BloombergNEF in 2025 tallied up almost 200 supply agreements for low-carbon steel. SSAB has announced deals with Volvo for green steel sourced from Hybrit; Mercedes also has an offtake agreement. The automotive industry — which accounts for significant steel demand — increasingly wants to claim carbon neutrality, said Martin Gidlund, SSAB’s transformation communication manager. ​“For 2040, they want to be able to say ​‘made with green steel.’”

In Luleå, the scale of what’s being attempted becomes tangible. Within view of the current coking plant, SSAB broke ground in September 2025 on a building that is 1.5 kilometers (1 mile) long and about a half kilometer (quarter mile) wide and that will integrate two electric arc furnaces, continuous casting, hot rolling, and cold mill operations. The new plant will be able to run on either scrap steel or sponge iron from direct reduction using green hydrogen, or any mix of gas. Initially, the facility will use scrap, like SSAB’s existing U.S. electric arc furnace operations do in Montpelier, Iowa. At peak construction, up to 3,000 workers will be on-site. In a preview of Fleischanderl’s notion that ironmaking and steelmaking can be geographically separated, the iron ore will be reduced next to LKAB’s mining site and transported by rail to be turned into steel in Luleå. After some delays with the grid connection, startup is now targeted for late 2029. The environmental permit allows only two years of parallel production, so once the new facility starts, the blast furnace must shut down by 2032. Sweden’s single largest CO₂ emitter will be no more.

The business case rests on multiple factors. The existing blast furnace, built in 2000, will need relining soon — a significant investment. The coking plant, built in the 1970s and operating continuously since, is aging; renovation is not an option. ​“We cannot turn it off, because if we do, it will fall apart,” Gidlund said. The bricks inside the ovens will just shatter as they compress when the heat dies down.

Under the EU Emissions Trading System, continuing with coal-based production would cost SSAB more than 10 billion euros a year in carbon credits, the company has determined. ​“Either we invest a lot of money in old technology, or invest more money but in new technology,” Gidlund said. ​“We’re calculating that building the new one is using our capital more efficiently and also setting up for a system that will make us more competitive in the long run.”

It’s a dilemma that steelmakers worldwide need to face eventually — around 70% of blast furnaces need relining or other major maintenance by 2030. In the EU, over half will by 2035. If they’re relined — extending coal-based production — Europe will miss its climate targets and lock in 435 million metric tons of CO₂ over the next 20 years, according to industry estimates. China’s blast furnaces were installed more recently, so their owners can put off the decision for a few more years. But major steelworks in the U.S. are already investing in the past, opting for relining over going green. U.S. Steel is set to start relining its Gary Works blast furnace in Indiana this month; Cleveland-Cliffs plans to do the same at its Burns Harbor plant in Indiana next year.

Whether Europe’s bet on green steel succeeds depends less on technology than on coordination. Hybrit and Primetals Technologies have solved the technical issues. Quest One and other manufacturers can build electrolyzers at scale. Storengy understands how to bottle the hydrogen. Pipeline operators have the know-how to convert networks.

What’s missing is the choreography — getting all these pieces to develop simultaneously at the pace and scale required. ​“You have to build production and infrastructure and storage and the offtake side at the same time,” van Wijk said. ​“You have to replace blast furnaces with DRI, and that has to be done in the same volume by all kinds of different companies. If governments don’t have a certain commitment, it won’t happen.”

The pressure is building. The atmosphere doesn’t care who gets there first, but European steelmakers are facing overseas competition from China, which is curbing blast furnace approvals and scaling up hydrogen-fueled ironmaking output, and from the Middle East and North Africa, whose abundant cheap, renewable energy potential could position the regions as future suppliers of both green hydrogen and reduced iron (as long as, in the case of Qatar and United Arab Emirates, Iran keeps the Strait of Hormuz open). If European buyers who want green steel can’t get it in Europe, they will have other options.

“We’re in the lead on technology, and if we are too hesitant, China will drive by us,” warned Pegemanyfar at Quest One. ​“Already some German [electrolyzer] manufacturing is moving to China because there’s not enough demand here. If the price doesn’t come down, China will flood our market as it did with solar, and we’ll risk losing out on another key technology for the energy transition.”

Those that have opted to produce their own hydrogen, like Hybrit and Stegra, have a head start. Britain’s ITM Power sells a self-standing 50-MW hydrogen plant for the bargain price of 50 million euros. Thyssenkrupp, ArcelorMittal, and Salzgitter can turn to Primetals Technologies’ plants when its Hyfor tech is ready for market in 2028, but they may find that the hydrogen backbones and Ready4H2-promoted projects aren’t built up enough, or that the bottlenecks aren’t resolved soon enough, to prevent their drowning in red ink from the rapidly approaching carbon fees. ​“Very likely there will not be sufficient hydrogen in three years,” Fleischanderl said. ​“It takes plus or minus three years to build a hydrogen plant from commitment to production.”

Considering the widely distributed climate risks of business as usual, and the known health impacts to Europeans of burning coal, losing 20% of the continent’s jobs in steel — 300,000 total, or 0.1% of the jobs in Europe — would be a small price to pay for accelerating the transition to green steel. Germany already lost 115,000 jobs in photovoltaic manufacturing between 2011 and 2015 because of cheap imports from China and nobody blinked an eye. The question before Europe now is whether it will do what it takes to bring green steel to price parity with the dirty kind — either by subsidizing it or letting some production move overseas — or allow a tiny constituency to decide that no one must pay a few euros extra for a car and everyone will be forced to suffer the consequences of steel’s current 2.6 billion metric tons of annual emissions.

“Sometimes in Europe we can be too good,” Falken-Großer said.

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Thanks to state incentives, the long-range, lower-cost electric trucks are affordable. Widespread adoption could help California meet clean-trucking targets.

Back in 2017, Tesla promised to bring an all-electric semitruck to market that would have a longer range and lower cost than its competitors. Then, the trucking industry waited — and waited. The initial production target of 2019 came and went, as did each newly announced date over the next three years.

But in 2022, Tesla finally unveiled its Tesla Semi and started to get pilot versions on the road for testing. The Class 8 battery-electric truck hit performance targets well beyond what Daimler, Volvo, Kenworth, Peterbilt, and other companies were delivering with their all-electric models. As of April 29, Tesla says it has finally started high-volume Semi production at its factory in Sparks, Nevada.

Now, the Semi’s combination of mileage and price appears set to transform an industry hungry for an affordable way to move freight without burning diesel — especially in California, the country’s top market for electric trucks.

So says Ray Minjares, heavy-duty vehicles program director at the International Council on Clean Transportation. The nonprofit research group has been tracking applications from truck purchasers seeking vouchers under California’s Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project (HVIP), the country’s biggest state-administered program to incentivize the shift to heavy-duty clean vehicles.

Of the 1,067 requests for vouchers submitted during the latest application window, which launched in December 2025, 965 were for Tesla Semis, he said. That’s far more applications than for any other model of truck, he added — and more than the total number of HVIP applications for all heavy-duty trucks since 2021.

And if all those Tesla Semis are actually delivered by the end of this year, that could make up about a third of heavy-duty truck sales in the state, Minjares said. That’s far above the 10% target for zero-emissions Class 8 vehicles set under California’s Advanced Clean Trucks regulation, he noted.

This would be an important environmental accomplishment. Heavy-duty trucks emit more than half the transportation sector’s harmful air pollution, with disproportionate health impacts for lower-income areas and communities of color.

It would be even more striking given that the Republicans in Congress passed legislation last year nullifying California’s power to set its own emissions reduction standards for trucks and cars under the federal Clean Air Act, he said. The Trump administration has also moved to weaken national fuel economy standards and claw back federal funds for electric trucks and EV charging.

Considering the policy headwinds, ​“states that have severe air quality challenges and climate goals need to find alternative pathways to enable this transition,” Minjares said. And one of the most important ways to do that is ​“putting downward pressure on the price that fleets are paying for the vehicles.”

The median price for a Tesla Semi capable of driving about 500 miles on a single charge is just under $300,000, according to HVIP data. That’s about $138,000 to $224,000 less than competing Class 8 battery-electric vehicles with roughly half the range, he said.

And while Tesla has tested the patience of buyers with its delays, the early models it put on the road got high marks from trucking companies and drivers.

In 2023, during three weeks of test-drives hosted by the nonprofit research group North American Council for Freight Efficiency (NACFE), Tesla Semis that beverage giant PepsiCo tried out hit 384 miles on a single charge. One truck traveled 1,076 miles in a single 24-hour period with multiple partial recharges using Tesla’s 750-kilowatt Supercharger. In another NACFE test-drive in 2025, a Tesla Semi operated by freight company Saia consistently traveled 465 miles on a single charge while operating two shifts per day, said Mike Roeth, NACFE’s executive director.

As of today, Tesla has boosted the range of its Semi to up to 350 miles for the standard model and up to 500 miles for the long-range model. It has also launched its Megacharger, capable of delivering up to 1.2 megawatts of power — enough to replenish about 60% of a Semi battery in 30 minutes — available both for truck depots and at an expanding set of public charging sites.

“The Tesla Semi is twice the range, and half the charging time, of trucks from traditional manufacturers,” Roeth said. ​“And early data is showing it’s a third less expensive to purchase.”

What truckers want from their electric trucks

These are all appealing characteristics to Jennie Abarca, founder and CEO of King Fio Trucking in Long Beach, California. She already has 11 electric trucks in her 35-truck fleet serving the ports of Long Beach and Los Angeles, including models from Volvo, a major manufacturer, and Nikola, a startup that went bankrupt last year.

“Both trucks have been exceptional,” she said. ​“But now you have something like the Tesla coming in: 500-mile range, 30-minute recharge, and $150,000 less than the current option out there — wow.”

Abarca has applied to secure HVIP vouchers for 20 Tesla Semis, with each voucher providing a $120,000 discount to the up-front cost of a truck. Additional incentives available from the ports of Long Beach and Los Angeles and from utility Southern California Edison for drayage trucks, which carry cargo from ports to inland warehouses, can further reduce that cost by up to 90%.

Buyers must still pay sales and excise taxes on the full sticker price of the vehicle and cover registration fees. But with the full stack of incentives, the cost of a Tesla Semi ​“will look more like a really nice used diesel [truck], which is what I would normally buy,” Abarca said.

And once it’s on the road, an electric truck is less expensive to fuel and maintain, she said. These operating advantages, along with lowered electric drivetrain and battery costs, are expected to bring electric trucks into parity with diesel vehicles in terms of total cost of ownership within the next five to 10 years, according to research from the International Council on Clean Transportation, NACFE, and other groups.

To be clear, ​“I can’t buy these trucks without incentives,” Abarca said. ​“The trucking industry has been in a hole since the end of 2022” due to the supply chain disruptions and inflationary pressures of the Covid pandemic, she said. ​“And I don’t have investors. I only have the profits I make from my business.”

Rudy Diaz, owner of Long Beach–based trucking firm Hight Logistics, also said he wouldn’t have been able to buy the 25 electric trucks in his 75-vehicle fleet without incentives.

But he believes that electric vehicles are the future of the industry — if they can come down in price and weight and their range can be increased between charges. That’s why he’s applied for HVIP vouchers for 15 Tesla Semis and plans to install several Megachargers at his Long Beach depot.

The Volvo and BYD trucks he now operates are capable of making it from ports to the complex of distribution warehouses in the Inland Empire region of Southern California and back on a single charge, ​“and not necessarily run out of battery,” he said. ​“But to do that, you’re going to have to have downtime for charging.”

With the Tesla Semi’s 500 miles of range, he notes, ​“I can go to San Diego and back. I can be competitive with diesel in other areas where I couldn’t compete before.”

Such flexibility is what could make the Tesla Semi launch ​“the kind of thing that truly catalyzes change,” said John Verdon, co-founder and chief commercial officer of Nevoya, a startup that owns and deploys electric trucks carrying freight in California, Arizona, and Texas for large corporations and third-party logistics operators.

Nevoya has been operating five preproduction Tesla Semis in California as part of its fleet of about 50 electric trucks, Verdon said. Most of the company’s routes are between the ports of LA and Long Beach and the Inland Empire. But its Tesla trucks are able to make longer runs from Southern California to the Central Valley and San Francisco Bay Area, he said.

Extended range isn’t just about longer hauls, though, he said — it’s about getting the most value out of vehicles whose higher up-front costs can be more than counterbalanced by lower operating costs, as long as they’re being used as often as possible. ​“We’re no longer bound by the notion that we have a vehicle that’s superexpensive, has limited range, and inadequate spots for them to charge.”

A game changer for electric freight?

It’s too soon to tell how the Tesla Semi might push its competitors to improve the range or pricing of their electric trucks. But as Minjares noted, legacy truck manufacturers face a structural challenge in competing against their all-electric rival, with relatively low volumes of electric vehicles being built on production lines designed to support both internal combustion and battery-electric models.

“Legacy manufacturers are stuck between multiple technologies, weighing them down with development and production costs,” he said. ​“But Tesla has bet on one technology, giving the company greater focus and discipline.”

Whether the trucking industry has the buying appetite to make that bet pay off is another question. Roeth noted that Tesla has stated its Nevada factory is capable of producing about 50,000 Semis per year. For context, there are only about 2,000 electric heavy-duty trucks on U.S. roads today, according to International Council on Clean Transportation data. In fact, 50,000 vehicles would constitute roughly a quarter of the total annual U.S. market for heavy-duty diesel-fueled trucks.

“Tesla has two things it has to do: Convince customers to buy electric, and convince customers to buy its electric,” Roeth said.

While the Tesla Semi has already established its clear performance and price advantages, it has yet to demonstrate the ​“reliability and durability” of its technology ​“at 500,000 miles, at 750,000 miles, at 1 million miles,” he said.

Tesla won’t hit its full Semi production capacity right away, according to Minjares. It’s also likely to seek out markets outside the U.S. It will face tough competition from leading Chinese electric vehicle manufacturers that now dominate the industry, as well as new entrants like Windrose, which last month sold its first electric truck in the U.S. at a price comparable to the Tesla Semi’s.

But Minjares believes these kinds of competitive pressures are what’s needed to make other manufacturers stop fighting state clean-trucking policies and start embracing innovation.

“This transition was never going to be sustainable if the underlying economics were not favorable,” he said. ​“The challenge on the policy side has brought that into clearer focus.”

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After years of no new nuclear power construction in the U.S., both Kairos and TerraPower broke ground on reactors last month. Other projects are moving ahead too.

March 1, 2024, marked a bittersweet milestone in the American nuclear industry’s modern history.

Exactly 3,755 days after construction started on the second of two new state-of-the-art Westinghouse AP1000 reactors at Southern Company’s Alvin W. Vogtle Generating Station in eastern Georgia, the facility hooked up to the grid for the first time.

It marked the completion of the first truly new large-scale nuclear project in the U.S. since the 1990s — but it also left the country without a single commercial nuclear power plant under construction for the first time in decades.

The dry spell only lasted 777 days.

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Last month, Kairos Power broke ground on its Hermes 2 Demonstration Plant in Oak Ridge, Tennessee, where the developer plans to start fulfilling its contract to sell Google power for its data centers through the Tennessee Valley Authority by constructing a smaller 50-megawatt version of its molten salt reactor. While the U.S. Nuclear Regulatory Commission granted Kairos its construction license to start work in Tennessee, the company hasn’t yet submitted an application to certify its full-scale reactor.

Six days later, TerraPower — the Bill Gates–founded developer of liquid-sodium-cooled, 345-megawatt reactors — began construction on its first plant, located at the site of a retired coal station in Kemmerer, Wyoming.

The break in nuclear construction was even shorter if you count work to restart an idled plant. In Michigan, Holtec International is now nearly ready to switch back on the single reactor at the Palisades nuclear plant, which was the most recent one to shutter in the country. It would be the first instance of an atomic station coming back online after a permanent shutdown.

At least two more companies are now considering similar moves in Pennsylvania and Iowa, and momentum is building for Holtec to reopen its decommissioned Indian Point nuclear station north of New York City.

“The key metric for the arrival of the nuclear renaissance is shovels in the ground,” said Emmet Penney, a senior fellow who researches nuclear power at the Foundation for American Innovation. ​“If there are shovels in the ground for multiple projects, then it is here.”

What to watch now, he said, is the tier of upcoming projects, which he dubbed ​“shovels soon to meet dirt.”

In that category, he placed GE Vernova Hitachi Nuclear Energy​’s plan to build one of its 300-megawatt BWRX-300 boiling-water reactors at the TVA’s Clinch River site. The Department of Energy awarded the American-Japanese joint venture $400 million in funding last year. Another similar project is Holtec’s plan to expand Palisades with a pair of its proprietary SMR-300 pressurized water reactors, to which the agency awarded another $400 million as part of the same program.

The two reactors are considered the leading small modular designs using existing light-water-cooled technology, which currently powers the entire U.S. nuclear fleet of 94 commercial units. Neither has yet secured full approval from the Nuclear Regulatory Commission.

It’s not all full steam ahead

While these projects are making solid progress, many of the other nuclear ventures proposed in the U.S. are lagging.

The policy advocacy group Third Way recently analyzed 11 commercial projects to build new reactors and found that only five of them have so far lined up all three of the major contracts needed to move forward — for commercial offtake, project-specific financing, and construction. TerraPower’s Kemmerer project, GE Vernova Hitachi’s TVA reactor, and Holtec’s SMR buildout at Palisades have those contracts in place, as do two ventures proposed by Amazon-backed X-energy in Texas and Washington state.

But even Kairos hasn’t announced project-specific financing, Third Way noted. Its Hermes 2 project is designed to sell power to Google once complete, but it hasn’t raised specific funding and the tech giant’s deal didn’t include payment upfront.

Oklo, the stock market darling promising to build 1.2 gigawatts of its liquid-sodium-cooled small modular reactors in Ohio, hasn’t yet unveiled its construction partner for the site, which would supply power to Meta’s data centers in the state. Three of the commercial projects Third Way assessed have not achieved any of the milestones yet. That trio includes Fermi America, the data-center startup co-founded by former Texas Gov. Rick Perry that had promised to build a giant computing complex powered by AP1000s; the company is now imploding as it battles its ousted chief executive and the stock plunges.

“The bottom line is there’s so much activity in nuclear right now, but there is a clear set of leaders distinguishing themselves and pulling away from the rest of the group,” said Rowen Price, Third Way’s senior policy adviser for nuclear energy. ​“If we’re really thinking about getting the industry to a point where we’re producing new commercial power as soon as we can, you have to focus your resources on the ones that are getting there faster.”

The federal government has the biggest pool of resources for moving viable projects forward. TerraPower, Kairos, and X-energy all benefited from hundreds of millions of dollars each from the Energy Department’s advanced reactor demonstration program, starting back in 2020. That helped vault the three companies ahead, while firms that received federal funding later — such as GE Vernova Hitachi and Holtec — are unsurprisingly behind, said Brett Rampal, the senior director of nuclear and power strategy at the consultancy Veriten.

But federal funds don’t always go to the most commercially viable ventures. ​“Even though people are breaking ground and doing stuff, some of these projects are years away from completion and generation. That means some of these projects that might not have broken ground yet might hit the grid before TerraPower or Kairos,” he said. ​“I wouldn’t be confident that just because you’re the only ones breaking ground now you’ll be the first over the finish line of commerciality or energy generation.”

The dealmaking boom thunders on

More nuclear deals are expected in the coming weeks and months.

The Nuclear Company, a novel kind of developer that aims to construct fleets of proven designs for large-scale reactors, announced Monday a new joint venture with Brookfield Asset Management, majority owner of Westinghouse, to complete work on the aborted V.C. Summer nuclear plant in South Carolina. The abandoned AP1000 project left the utilities Santee Cooper and South Carolina Electric & Gas roughly $9 billion in the hole, much of which was foisted on ratepayers in the form of higher bills.

The NRC is also streamlining and speeding up its licensing processes for new plants, whether they’re using existing or novel designs, and for restarts and current plants applying for approval to keep running.

In February, the DOE’s Office of Energy Dominance Financing — the in-house lender formerly known as the Loan Programs Office — closed on the largest deal in its history, a $26.5 billion credit line to support Southern Company in (among other things) renovating the utility’s reactor fleet to get 6 gigawatts of additional power out of the existing units, a process known as ​“uprating.” The company hasn’t yet announced which plants it wants to beef up. Meanwhile, another nuclear startup called Alva Energy has pitched itself as a project developer that will focus in the near term on uprates.

“The work on these reactors is getting underway,” Penney said. ​“We should expect more.”

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To say something moves at a glacial pace is to imply sluggish, unhurried change. But what transpired over the course of 15 months at Antarctica’s Hektoria Glacier was uncharacteristically quick. Between January 2022 and March 2023, the glacier lost about 25 kilometers (15 miles) in length. That included a two-month period in which the terminus retreated more than 8 kilometers (5 miles)—the highest rate of grounded glacial ice loss observed in modern history.

A team of scientists published an analysis of Hektoria’s collapse based on a suite of remote-sensing data, finding that its particular geometry enabled the rapid change. Like many glaciers on the Antarctic Peninsula, Hektoria starts on land and extends to the sea, with the last section being a thick, floating plate of ice, or “ice tongue.” The researchers determined Hektoria lost both its ice tongue and an area of grounded ice spread over a flat plain—the latter directly contributing to sea level rise. Although Hektoria is relatively small as Antarctic glaciers go, scientists say that similar events at larger glaciers could be much more consequential.

The images above capture the scale of the loss of Hektoria’s grounded ice on the eastern Antarctic Peninsula. Note that the right image was acquired about one year after the remarkable loss of grounded ice; a cloud-free Landsat image showing the whole area was not available from the previous March. Hektoria’s terminus remained relatively stable after the sudden loss, the study reported, though the neighboring Green Glacier continued to retreat.

The chain of events culminating in Hektoria’s breakup goes back to early 2002. At that time, the Larsen B ice shelf, which served as a backstop for Hektoria and neighboring glaciers, splintered and collapsed in short order. The glaciers then thinned and retreated for several years. In 2011, landfast sea ice in the Larsen B embayment near Hektoria’s terminus filled in enough to allow the glacier to start advancing.

But after several years, the new support for the glacier front was suddenly removed. Landfast ice in the embayment broke up in January 2022, likely due to large, destabilizing ocean swells. From that point, rapid change at Hektoria was again underway. Throughout the rest of the austral summer, the floating ice tongue disaggregated in a series of calvings, resulting in a loss of 16 kilometers.

The glacier’s terminus stabilized during the 2022 austral winter. However, satellite-based laser altimetry data, including ice elevation measurements from NASA’s ICESat-2 (Ice, Cloud, and Land Elevation Satellite-2) mission, revealed that the ice continued to thin during that winter.

The thinner remaining ice was still grounded during the 2022 austral spring (left image, above), the study authors concluded, based on the detection of earthquakes occurring beneath the glacier. They determined the ice was spread out over a relatively flat area of bedrock, forming an ice plain. This geometry allows seawater to infiltrate the glacier’s bed during high tide and intermittently lift ice off the ground. When ice is thin enough, large areas can lift and break away at once. The process, called buoyancy-driven calving, is believed to have caused the second stage of Hektoria’s rapid retreat, resulting in an additional loss of 8 kilometers in length.

Naomi Ochwat, a glaciologist at the University of Innsbruck and the study’s lead author, is now looking into other glaciers that may be at risk of destabilizing in a similar way. As the Antarctic Peninsula responds to warming, more of its glaciers are losing their ice tongues, and their termini are now resting on the seabed, as Hektoria's does. (Called tidewater glaciers, this type is common in Alaska and Greenland.) New technologies developed by NASA and partners can aid in understanding rapid glacial retreat, said Ochwat and study co-author Ted Scambos, a senior research scientist at the University of Colorado Boulder.

The NISAR (NASA-ISRO Synthetic Aperture Radar) satellite, for example, can detect the movement of land and ice surfaces down to the centimeter. Its data will be “very useful for structural evaluations of Hektoria and other glaciers in the region,” Scambos said.

“In addition to NISAR,” Ochwat added, “I'm particularly interested in learning what SWOT can tell us about rapid glacier changes.” The SWOT (Surface Water and Ocean Topography) satellite’s primary mission is to observe the fine details of Earth’s surface water height. But scientists are also exploring its applications to the cryosphere, such as measuring surfaces of ice shelves and sea ice.

At Hektoria Glacier, the days of dramatic change are likely past, now to be replaced by slow retreat. Scambos said he would not be surprised to see the ice slowing down. “The glacier has lost so much elevation and mass that it simply can’t continue to maintain the same output,” he said. “It’s on its way to being a fjord, not a glacier.”

NASA Earth Observatory images by Lauren Dauphin, using Landsat data from the U.S. Geological Survey. Story by Lindsey Doermann.

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In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.

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Lightshift Energy is constructing a second battery project for the city of Danville, Virginia. (Sanjay Suchak)

In the face of soaring energy demand and electric rates, battery developers across the U.S. are stepping in with massive, multihundred-megawatt systems that can cheaply dispatch power when it’s needed most.

Virginia — the world’s data center capital — is starting to catch on to the big-battery trend. But a new project by local electric providers in the state underscores that much smaller storage projects have value, too: They’re designed to fill specific community needs and — due to their size — relatively quick and low-cost to build.

The Blue Ridge Power Agency, which serves a string of nonprofit utilities in central and western Virginia, is set to go live this summer with a collection of five batteries of about 5 megawatts each. The systems will help two rural electric co-ops and the city of Salem’s utility save money by storing power when it is cheap and abundant. They can then rely on that saved-up power when high demand on the grid spikes prices.

All in all, the projects are predicted to save the member utilities $100 million over the batteries’ 20-year lifespan, addressing long-held local concerns over rising costs.

Lightshift Energy, the storage developer building the five batteries, has formed a bit of a niche working with small, member-owned utilities, said Rob Greskowiak, the company’s chief commercial officer.

These nonprofit utilities are rooted in their communities and intimately familiar with their customers and grids, Greskowiak explained. ​“These municipalities are like, ​‘Listen, I know the 50,000 people that live here, and I know that this distribution circuit is not reliable and that our energy costs are going up,’” he said. At Lightshift, ​“we can find a very acute problem and solve it with 5- to 30-megawatt-sized batteries.”

Small cooperatives’ investment in storage extends well beyond Virginia. As of the first quarter of 2025, 136 battery storage projects sponsored by co-ops were underway or operational in 27 states, according to an analysis by the National Rural Electric Cooperative Association. It predicts that storage deployed by co-ops will more than triple, from 439 megawatts of capacity to 1.5 gigawatts, in the next three years.

The smaller batteries these co-ops tend to favor are cost-competitive because they avoid the need for expensive network upgrades, don’t require expensive long-lead equipment, and are sited on very small footprints, Greskowiak said.

Their minimal impact means they’re often quicker to permit and gain community acceptance than larger versions, he added. ​“If you’re putting in a battery that isn’t that big in a spot that already has that infrastructure, people aren’t really batting an eye on that.” The company can typically go from initial discussions with a utility to operations in 18 to 24 months, he said, significantly faster than transmission-scale assets.

The rapid setup is particularly meaningful in Virginia as data center plans flood the state and send power-demand forecasts ballooning, said Nikhil Kumar, program director at GridLab, a nonprofit that provides technical support on the clean energy transition in a range of settings. ​“Speed to power,” he said, ​“it’s in the zeitgeist right now.”

While reining in power prices is the main motivation behind the Blue Ridge Power Agency’s midsize-battery buildout, Greskowiak emphasized other advantages as well. ​“Battery storage is best when it acts like the Swiss army knife that everybody talks about,” he said.

A key benefit includes storing electrons from solar and wind and dispatching them when the sun fades or the breeze dies down, enabling even more renewable energy deployment. ​“Local homeowners, local businesses, local community solar gardens can add to that grid more sustainable energy,” he said, ​“because we’ve released and unlocked more capability at those substations to host more solar.”

Batteries are also getting cheaper and cheaper, with the average price of a lithium-ion battery pack dropping by nearly 80% over the last decade. And even though President Donald Trump and congressional Republicans slashed incentives for wind and solar last year, they retained the 30% credit for storage well into the next decade. ​“That’s another big advantage,” Kumar said.

Lightshift Energy’s Danville II project (Sanjay Suchak)

The Blue Ridge Power Agency project is just the latest example of a small Virginia utility quickly deploying batteries. Lightshift has partnered with the city of Danville on two systems that total over 20 megawatts and are expected to save customers $70 million; the first went online in 2022, and the second is under construction. Last year, developers announced two similar-sized projects for a co-op on the state’s Eastern Shore.

Co-ops’ increased interest in storage comes as the state directs its two investor-owned utilities to ramp up investments, too: A law recently enacted by Gov. Abigail Spanberger, a Democrat, requires Dominion Energy and Appalachian Power to build nearly 17 gigawatts of battery storage by 2045; their former target was 3 gigawatts by 2035.

All these planned storage investments will be necessary to ease grid strain and bring down costs, Kumar said. ​“Especially in Virginia, with the large loads and the data center growth, we’ll need a lot of these projects to help the grid.”

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The United States has taken one of its biggest steps yet to encourage the construction of commercial microreactors — the latest move in its broader push to overhaul the country’s nuclear regulatory processes.

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U.S. Nuclear Regulatory Commission Chair Ho Nieh speaks at the annual Regulatory Information Conference in March. (U.S. Nuclear Regulatory Commission)

The United States has taken one of its biggest steps yet to encourage the construction of commercial microreactors — the latest move in its broader push to overhaul the country’s nuclear regulatory processes.

In late April, the U.S. Nuclear Regulatory Commission released its draft rule for a proposed new licensing pathway for commercial reactors. Known as Part 57, the regulation tailors the application process to account for the fundamental differences between a so-called microreactor, designed to generate 20 megawatts of electricity or less, and a behemoth traditional reactor such as a Westinghouse AP1000, which pumps out 60 times as much power. The rule, which would allow eligible projects to obtain dual permits to both construct and operate a reactor, is meant to encourage fleet-scale deployment of the technology.

While no commercial microreactors are in operation anywhere in the world today, some corners of the U.S. industry see them as a way to slash the time and money it takes to build a nuclear plant by harnessing the benefits of assembly-line production.

The proposal comes after a string of actions by the NRC to speed up the regulatory process for nuclear reactors that use different designs or technology than the country’s existing fleet of 94 large-scale light-water reactors. The regulatory changes, spurred by a Biden-era law and encouraged by the Trump administration, have been widely celebrated by the industry — but they have rankled some who fear the NRC is jeopardizing safety by moving too fast.

In March, the NRC shook up its licensing pathways for the first time in decades. Dubbed Part 53, the final rule was the first new set of regulations to address initial reactor licensing since 1989 — and the first major update to reactor licensing standards since 1956.

Part 53 is an optional alternative to two existing frameworks, Part 50 and Part 52. The former has long been developers’ preferred pathway for new reactors, but it grants only construction permits — not operating licenses. Part 52 was created to speed things up by allowing a dual construction and operating license to be obtained in one shot, but that pathway carried risks if the developer deviated even slightly from the approved design.

Neither option made much sense for the wave of advanced nuclear reactor firms that have attracted enormous amounts of funding and industry hype over the last decade. Part 53 was specifically designed to accommodate these technologies, including small modular reactors, microreactors, and those that use coolants other than water.

“With all these new and advanced technologies coming, we needed something more flexible,” said Mike King, the NRC’s executive director of operations. ​“That’s what Part 53 does. It provides us a framework that’s not so focused on large light-water reactors.”

Last week’s proposed Part 57, he said, ​“takes what we’ve done with Part 53 and scopes it appropriately for these microreactors that have a much lower risk profile for the public and could be licensed in a more streamlined fashion.”

Part 57, set to be added in the coming days to the Federal Register, won’t be operational until the rule is finalized in the next few months. But already, several microreactor developers have put out statements indicating they plan to apply for NRC licenses through the new pathway.

Central to the rule is the ​“risk-informed” change that Part 53 pioneered.

Rather than require the same safety protocols and infrastructure that the NRC mandates for traditional light-water reactors, Part 57 sets a target that developers are free to meet in a variety of ways.

Like Part 53 before it, the rule also limits the radiation emitted from an accident to 1 rem — the same amount of radiation from a CT scan. But while Part 53 institutes those limits for 96 hours after an accident occurs, Part 57 mandates that operators stay under that limit only throughout the duration of the accident. For some companies, meeting that standard could mean building the concrete containment vessels that house traditional light-water reactors. While certain microreactor designs — either those that are extremely small or those made of or fueled with material that cannot melt down — might be able to avoid having to build such containment domes.

Traditional reactors regulated by Part 50 are required to keep radiation emitted from an accident to 25 rems — which is the maximum recommended lifetime dose of radiation.

In that way, Part 57 is narrower than the original pathway, said Adam Stein, the director of nuclear energy innovation at the Breakthrough Institute, because ​“to even get into Part 57, you’d have to stay under 1 rem for the entire duration of the accident, not just 96 hours. So it’s inherently more restrictive.”

Many of the changes now underway at the NRC stem from the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy (ADVANCE) Act, which President Joe Biden signed into law in 2024 after the Senate, in a rare show of bipartisan zeal, almost unanimously approved the bill. The statute overhauled the NRC’s mission statement for the first time, directing the agency to consider the threat of holding back nuclear power in the U.S. in addition to the risks associated with radiation. Work on Part 57 began under the previous administration.

Last May, President Donald Trump supercharged those efforts with a series of executive orders designed to defibrillate the flatlining nuclear sector as China’s industry runs laps around the U.S., and Russia dominates exports to newcomer countries seeking to build their first atomic power stations.

Among those orders was one to restructure the NRC, requiring the agency to do more, faster, with fewer staff and more direct oversight from the president. Presidents have always been able to appoint commissioners but have historically had little influence over the agency’s day-to-day workings. The White House directive raised alarms, particularly as Trump sought to bring previously independent agencies like the NRC and Federal Communications Commission under direct control. His decision to fire a Democratic NRC commissioner a month later only deepened fears.

Career staffers at the NRC have blown the whistle over concerns that the Department of Government Efficiency, which billionaire Elon Musk established shortly after Trump’s inauguration, was wielding too much internal influence and slashing necessary parts of the regulatory apparatus.

“It’s hard to know if they are getting rid of unnecessary processes or if it’s actually reducing public safety,” one official working on reactor licensing told ProPublica last month. ​“And that’s just the problem with going so fast — everything just kind of gets lost in a mush.”

But Caroline DeWitte, the co-founder of Oklo, a nuclear developer favored by Silicon Valley, said skeptics of overhauling the NRC fail to recognize the extent to which the agency in its previous form was ill suited to oversee construction of new types of reactors.

The NRC official who rejected Oklo’s application in 2022 told Bloomberg last year that the company’s submission was one of the worst ever reviewed. But DeWitte, who leads the company as chief operating officer alongside her chief executive officer husband, Jake DeWitte, said the NRC couldn’t understand that Oklo’s reactor and similar designs have ​“inherent safety features.”

“Literally, the physics of the metal made it safe,” Caroline DeWitte told Canary Media. ​“So, how do you account for that? Even with passively safe features, the NRC forces you to assume that it can fail. But, like, is it reasonable to assume metal is not metal anymore? Those are the types of questions we were asking — how do we put that in a risk analysis?”

Among the more controversial regulatory changes proposed at the NRC is the move to overhaul the way radiation safety is measured altogether.

For years, the dominant rule has been for any radiation exposure to be kept as low as reasonably achievable, called ALARA. It’s based on the assumption that the more exposure someone faces, the higher the risk of cancer or other disease.

That assumption stems from the highly contested ​“linear no-threshold model” from the 1950s, which assumes that exposure to radiation at any level causes harm. Still, no one has yet determined a better alternative on which the country — and, more broadly, the world, which has long followed the U.S. lead on nuclear regulation — can agree.

The NRC has been treading lightly so far: Its proposed rule has been pushed back seven times already and is now due out on June 24.

Paul Dickman, who served as chief of staff to the NRC’s chair from 2006 to 2010, said he is not concerned that his former agency will approve anything that doesn’t stand up to rigorous testing.

“The NRC staff is being creative, and that’s a good thing,” he said. ​“Some people may worry. But I have high confidence in them. At the end of the day, you still have to prove your point on safety. That’s the bottom line.”

The strategy appears to be bearing fruit. In what NRC Chair Ho Nieh called a ​“milestone” that ​“proves we can deliver results quickly without compromising safety,” the agency just approved Duke Energy’s application to run its Robinson nuclear plant in South Carolina for 80 years. It was the fastest license renewal in the NRC’s history.

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When it comes to electric vehicles, old is gold.

In the U.S., sales of new EVs are slumping — but more used EVs are being driven off the lot than ever, per Cox Automotive data. With hundreds of thousands of battery-powered vehicles coming off leases soon, the used EV market is set to accelerate even further in the years to come.

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Although Americans still buy a lot more new EVs than used ones, the Cox data shows the gap beginning to close: Used EV sales jumped by 34% in 2025, compared with the prior year, as new EV sales shrank a bit. Overall, electric models made up nearly a tenth of new vehicle sales in the U.S. in 2025, and about 2% of used car sales.

A combination of factors explains why used EVs are on the upswing while new ones are stagnant.

For one, a lot more used EVs are on the market these days than in the past. About 300,000 EVs will come off of leases this year, up from 123,000 last year, and Cox expects another 600,000 to do so in 2027. Not all of those will hit the used car market, but many will, providing a rush of inventory that helps drive down prices.

Speaking of prices, on average a used EV is now basically at price parity with a used gas car. That’s a big deal: Up-front cost is one of the main barriers preventing people from buying battery-powered vehicles, which are typically cheaper to drive and maintain but have long been more expensive than similar gas-fueled models.

A new EV is still about $6,500 more than a new gas car, on average. Consumers used to be able to shave $7,500 off the EV price with a federal tax credit, but the Trump administration did away with that incentive in September.

The rise of used EVs is a rare positive signal for the American vehicle-electrification effort.

While new EV sales hit record highs under the pro-EV Biden administration, adoption was slower than expected, causing some automakers to walk back commitments to churn out electric models. When President Donald Trump took office last year and tossed out the tax credit along with a bunch of other supportive regulations, it added fuel to the fire.

Some analysts expect EV sales to surge as fallout from the war in the Middle East spikes oil and gas prices worldwide. In the U.S., the average cost of a gallon of gas is now well over $4 a gallon — and climbing — and in some countries, fuel shortages have spurred driving bans and fuel rationing. So far, the early evidence suggests that those expecting an EV boom are on to something.

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America’s hydropower systems are in hot water — but the federal government may soon unclog a stream of funding to help them out.

We’ve been using water to generate electricity in the U.S. since the 1880s, expanding from projects harvesting Niagara Falls for power to a whole network of systems that span the rivers of the West. America’s dams have since become a reliable, round-the-clock source of clean energy, generating nearly 6% of the nation’s power in 2025 even as drought in the West limited many projects’ capacity.

That long history is exactly why hydroelectricity is now in trouble. Hundreds of dams across the U.S. representing nearly 16 GW of capacity will have to be relicensed by the federal government in the coming years, as Alexander C. Kaufman previously reported for Canary Media. But the average dam in the U.S. is 65 years old, and many were built without the infrastructure they’d need to be licensed today, like passages for fish and other wildlife. Many operators will have to choose between spending millions of dollars on infrastructure upgrades or simply shutting down — and some are already choosing the latter.

In September 2024, the Biden administration announced it would use $430 million from the 2021 bipartisan infrastructure law to address some dams’ dilemmas. The pool of funding was supposed to be distributed by the now-defunct Grid Deployment Office and go toward grid resiliency upgrades, safety improvements, and environmental retrofits like fish passages at 212 facilities across the U.S. At least 17 of those facilities are up for relicensing through 2036.

Like tons of other federal clean energy funding, this initiative stalled out under the Trump administration. But this week, it showed some promising signs of life: The DOE’s Hydropower and Hydrokinetic Office — formerly the Water Power Technologies Office — announced it’ll resume negotiations to issue that $430 million, which, when paired with private investments at each facility, could result in more than $2.8 billion in improvements.

That’s a noteworthy amount for the U.S. hydropower industry, which doesn’t have the deep pockets it did decades ago, back before cheaper power sources like solar, wind, and natural gas had reached their current dominance. Even so, the funding won’t resuscitate the industry on its own. Facilities will still have to cope with challenges like years of relicensing bureaucracy and the capacity-diminishing effects of drought, which will only worsen with climate change. But in a country that’s now scrambling for all the nonstop power it can get, solving hydropower’s hang-ups has a huge upside.

TWO MORE BIG THINGS/​More big energy stories

Wind power’s month of major wins and losses

Another two offshore wind projects are being cast out to sea. The Interior Department announced Monday that it had reached a deal with Bluepoint Wind, off New York, and Golden State Wind, off California, in which their developers would be refunded for abandoning the offshore wind leases and reinvesting the money in fossil fuel projects instead. It’s essentially the same agreement the agency worked out with TotalEnergies a few weeks ago — a deal that Democrats in Congress are moving to investigate.

But it’s not all bad news for offshore wind power. Vineyard Wind, a project the Trump administration unsuccessfully tried to halt, began selling power to Massachusetts this week under a contracted price that’s expected to save Bay Staters $1.4 billion on their power bills over the array’s lifetime.

Meanwhile, on dry land, the massive SunZia wind project recently started delivering electrons to California — and it’s already propelling the state’s grid to new wind power generation records.

These Republicans want to preserve clean energy tax credits

A small group of House Republicans has proposed something a little unexpected: restoring Biden-era clean energy tax credits.

The American Energy Dominance Act, introduced late last week, would erase the accelerated June 30, 2026 expiration date that President Donald Trump’s One Big Beautiful Bill Act set for many renewable energy incentives — a change that would once again let developers access investment and production tax credits into the 2030s. The proposal would also remove early expiration dates for incentives related to energy-efficient buildings and clean hydrogen.

The four Congress members sponsoring the bill include one who signed a letter urging the preservation of clean energy incentives in the OBBBA, and another who voted against the megabill — and remains vulnerable to a Democratic upset in his reelection fight this fall.

The new proposal follows an effort by more than half of House Democrats to reestablish clean energy tax credits gutted by OBBBA, though neither piece of legislation is likely to pass in the Republican-controlled House. But the chamber probably won’t remain in GOP hands after the midterm elections, and both of these bills suggest the incentives could be saved if Democrats regain congressional control.

WHAT TO KNOW THIS WEEK/​Clean energy news to know this week

Clean money: Reports find the U.S. renewable energy sector could install a record amount of new capacity in 2026 and attract $120 billion in investment as developers race to meet demand growth and claim expiring federal tax credits. (Latitude Media)

All gas bans, no brakes: Even though a court struck down Berkeley, California’s pioneering ban on gas hookups in new buildings three years ago, similar lawsuits against building electrification policies have fallen short. (Canary Media)

Scapegoating efficiency: Maryland, Massachusetts, and Rhode Island are looking to slash energy-efficiency funding to quickly lower power bills, but experts say the moves will cost residents in the long run. (Canary Media)

Sowing REAP’s revival: The Trump administration froze the federal Rural Energy for America Program, which helps farmers install bill-reducing clean energy projects, but supporters hope Congress can restore the popular, bipartisan initiative with this year’s Farm Bill. (Canary Media)

Data center ban deferred: Maine Gov. Janet Mills (D) vetoes what would have been the first statewide data center moratorium, saying it would have blocked a widely supported project already under development. (Maine Morning Star)

Lithium lode: A large swath of untapped lithium deposits along the East Coast could provide the U.S. with enough of the crucial battery metal for hundreds of years, a new federal report finds. (E&E News)

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Countries attending a first-of-its-kind summit have walked away with plans to develop national roadmaps away from fossil fuels, along with new tools to address harmful subsidies and carbon-intensive trade.

The first conference on “transitioning away” from fossil fuels held in Santa Marta, Colombia, from 24-29 April saw 57 countries – representing one-third of the world’s economy – debate practical ways to move away from coal, oil and gas.

Against a backdrop of war, a global oil crisis and worsening extreme weather events, ministers and envoys from across the world sat side-by-side in small meeting rooms to have open and frank conversations about the barriers they face in transitioning from fossil fuels to clean energy.

This new format – devised by co-hosts Colombia and the Netherlands – was described as “refreshing”, “highly successful” and “groundbreaking” by countries attending the talks.

The event also featured a “science pre-conference” attended by 400 global academics, which included the launch of a new science panel that will aim to provide agile and bespoke analysis to nations wanting to accelerate their transition away from fossil fuels.

At the summit’s conclusion, Tuvalu and Ireland were announced as the co-hosts of the second transitioning away from fossil fuels summit, which will take place in the Pacific island nation in 2027.

Below, Carbon Brief outlines all of the key takeaways from the talks.

• Colombia and Netherlands leadership
• High-level segment
  • National statements and pledges
  • Closed-door discussions
  • Final outcomes
• Academic meeting
  • Science panel for global energy transition
  • Action insights report
  • Colombia’s fossil-fuel roadmap
• Indigenous and civil society participation

Colombia and Netherlands leadership

The idea for a specific fossil-fuel transition conference hosted in Colombia first emerged during tense end-game negotiations at the COP30 climate summit in Belém, Brazil.

Amid a push by a group of around 80 nations to refer to a “roadmap” away from fossil fuels in the formal COP30 outcome text, Colombia and the Netherlands jointly announced that they would co-host a summit in Santa Marta in April.

The calls for a fossil-fuel “roadmap” to be mentioned in COP30’s outcome text ultimately failed. However, the Brazilian COP30 presidency promised to bring forward an “informal” fossil-fuel roadmap, drawing on the discussions and debates in Santa Marta.

The Santa Marta conference took place from 24-29 April. It included a “science pre-conference” from 24-25, a day for subnational governments, parliamentarians and other stakeholders and a “high-level segment” with ministers and climate envoys from 28-29.

Colombian environment minister Irene Vélez Torres – herself a former academic – was particularly keen to emphasise the importance of science to the conference, telling journalists: “We need to go back to science and base our decisions on science.” (See: Academic meeting)

From the outset, the hosts stressed that the high-level segment was not a space for negotiations, but rather a forum for countries and other stakeholders to discuss practical steps to move away from fossil fuels.

This format was widely praised by ministers and climate envoys, who described the conversational atmosphere in break-out sessions as “refreshing”, “highly successful” and “groundbreaking”. (See: Closed-door discussions.)

A total of 57 countries participated in the conference, according to the Colombian government.

These countries were: Angola, Antigua and Barbuda, Australia, Austria, Bangladesh, Belgium, Brazil, Cameroon, Canada, Chile, Colombia, Denmark, Dominican Republic, the EU, the Federated States of Micronesia, Finland, France, Germany, Ghana, Guatemala, Iceland, Ireland, Italy, Jamaica, Kenya, Luxembourg, Malawi, the Maldives, the Marshall Islands, México, Mongolia, the Netherlands, Nepal, Nigeria, Norway, New Zealand, Palau, Panama, Philippines, Portugal, Saint Lucia, Senegal, Singapore, Slovenia, the Solomon Islands, Spain, Sweden, Switzerland, Tanzania, Turkey, Tuvalu, Uganda, the UK, Uruguay, Vanuatu, the Vatican and Vietnam.

At the summit’s opening press conference on 24 April, Vélez Torres confirmed that Colombia and the Netherlands had decided to only invite a select group of countries to the conference.

Vélez Torres told journalists that countries including China, Russia and the US were not invited. She suggested that they had not shown the necessary spirit to be part of the “coalition of the willing” and that Colombia wanted to avoid a rehashing of the lengthy debates at COP30. (Carbon Brief understands that India was also not invited.)

In a later press huddle, Dutch climate minister Stientje van Veldhoven clarified that the two co-hosts had partially based their invitation criteria on who showed support for the fossil-fuel roadmap at COP30, saying:

“It was a combination of what happened in Belém and all the existing initiatives that have been driving this agenda for a long time already.”

However, it is worth noting that some countries that had opposed a formal reference to a fossil-fuel roadmap in the COP30 outcome were invited to Santa Marta, according to Carbon Brief’s analysis of the “informal list” of those against the idea in Belém.

For example, Tanzania was invited to take part in the Santa Marta talks, despite appearing on the list of countries opposed to the roadmap in Belém.

On the other hand, neither China nor India were invited, despite having rejected media coverage portraying them as the “blockers” of the fossil-fuel roadmap at COP30.

Country officials and observers expressed a range of views on whether excluding certain countries from the conference was the right approach.

Juan Carlos Monterrey Gómez, Panama’s special representative on climate change, told a small group of journalists that he thought it was the “right decision”, adding:

“This first meeting had to be done with those that wanted something to be done. Otherwise, it would have been a repeat of a UNFCCC meeting.”

UK special representative for climate, Rachel Kyte, told a press huddle that China should feel “welcome to be here”, adding:

“China has to be part of this equation for multiple reasons.”

One veteran observer told Carbon Brief that their impression was that Colombia and the Netherlands had been “overly cautious” about who would have caused disruption if invited to the conference, saying:

“Yes, maybe there is an argument for not inviting countries that have a long history of blocking progress, such as the Gulf states. But, if we look at what countries are really doing on the ground – including JETP [Just Energy Transition Partnerships] initiatives – then more countries should have been here, including Indonesia, for example.”

However, they also urged caution on reading too much into which countries were and were not present, adding that this could also partially be explained by “scheduling and countries’ availability”.

During the summit’s final plenary, van Veldhoven stated that, going forward, it was the Netherlands and Colombia’s wish to create an “open coalition”, including by extending an “invitation for others to join us”.

Dr Maina Talia, the climate minister of Tuvalu, who will co-host the second transitioning away from fossil fuels summit alongside Ireland, told journalists that the island nations would “revisit” and “improve” the criteria used for inviting countries to the conference.

National statements and pledges

The two-day high-level segment began with an opening plenary, which saw more than 20 countries put forward their views on the need to transition away from fossil fuels.

Developed and developing nations alike spoke of the need to transition away from fossil fuels not only to tackle worsening climate change, but also the high prices, insecurity and volatility associated with continued reliance on coal, oil and gas.

Opening the plenary alongside Colombia, Dutch climate minister Stientje van Veldhoven told countries:

“Price volatility and dependence on imports are structurally and unacceptably impacting our economies. We need to move away from fossil fuels not only because it is good for the climate, but because it strengthens our energy security. Investment in clean energy also lays the foundation for a more resilient and sustainable economy, capable of mitigating these shocks.”

First to speak in plenary was Nigerian minister, Abubakar Momoh, who said:

“Nigeria is actively diversifying its economy away from extracting oil, which accounts for around 80% of our exports. Nigeria strongly believes that it is not whether extraction should decline, but how to organise it so it is manageable, fair and politically viable across countries.”

Also speaking during the session, UK special representative for climate Rachel Kyte said it “would be irresponsible to ignore the second fossil-fuel crisis in five years”.

Several nations also used their interventions to lament a lack of progress in addressing fossil-fuel use during the last 30 years of annual UN climate negotiations.

Dr Maina Talia, climate minister for Tuvalu, said that “for years, international climate negotiations have circled around fossil fuels without directly confronting the core issues”.

Juan Carlos Monterrey Gómez, Panama’s special representative on climate change, told countries:

“For 34 years, we have negotiated the symptoms of the climate crisis and bulletproofed its cause. Thirty-four years of pledges. And where are we now?

“Economies built on fossil fuels are unravelling in real time. Fossil fuels are not just dirty. They are unreliable, they are dangerous and they must end.”

A small number of nations from the Pacific and Africa used their interventions to show their support for the Fossil Fuel Treaty initiative, an idea to negotiate a new legally binding agreement to control fossil-fuel use, currently supported by 18 countries. (The treaty did not feature in the summit’s final outcome.)

France’s special climate envoy, Benoît Faraco, used his intervention to announce that the nation has produced a new roadmap for transitioning away from fossil fuels.

Later on, on the first day, Colombian president Gustavo Petro also gave a speech at the summit, telling countries:

“What I see is resistance and inertia within the power structures and the economy of this archaic energy system. Today, fossil fuels bring death; undoubtedly, that form of capital could commit suicide, taking humanity and life itself. Humanity cannot allow that.”

Closed-door discussions

Following the opening plenary, ministers and climate envoys spent much of the two-day high-level segment in closed-door “breakout sessions”, discussing issues ranging from “planned phase down and closure of fossil-fuel extraction” to “closing gaps in financial and investment systems”.

Carbon Brief understands that each session featured 12 ministers and envoys representing different countries sitting in an inner circle, with an outer circle made up of civil society members and other stakeholders. Each session was led by a different minister, appointed by the co-hosts.

In a departure from UN climate negotiations, the conversations that took place were free-flowing, with ministers and stakeholders given equal opportunities to contribute, observers told Carbon Brief.

Many countries were highly complimentary of this informal format, describing it in the closing plenary as “refreshing”, “highly successful” and a “safe space for discussion”.

UK special representative on climate, Rachel Kyte, told a huddle of journalists that there was “real value” to having informal conversations with other country officials, saying:

“I have to say that it is really nice to sit in a small circle…In a negotiation, it’s very, very fast-moving and transactional. But now we have had two days to think about [fossil-fuel transition issues] and this only.”

Speaking to Carbon Brief, Panama’s special representative on climate change, Juan Carlos Monterrey Gómez, said the format was “groundbreaking”, adding:

“I’m going to be honest. [At] first I was like: ‘What the f*ck am I doing here? I don’t know where this is going’.

“But then, as the workshop started, I realised there were ministers, envoys, civil society leaders and Indigenous people. They put us in a format where we could not open our computers, so we had to speak from our minds and our hearts. That completely flipped my perception. That kind of space I haven’t seen in my 10-year history with the UNFCCC.”

All of the sessions were held under the Chatham House rule, meaning discussions were not attributable to individual speakers to encourage more open debate.

Co-host nations Colombia and the Netherlands gave a broad overview of the topics and themes discussed during the sessions in a takeaways report. (See: Final outcomes.)

Final outcomes

At the conference’s final plenary session on 29 April, co-host nations Colombia and the Netherlands presented a range of “key outcomes” from the summit.

The first outcome was confirmation of the news that Tuvalu and Ireland will co-host a second transitioning away from fossil fuels conference in the Pacific island nation in 2027.

The co-hosts also announced the establishment of three “workstreams” on issues to bring forward to the second summit.

The first of these workstreams will focus on developing national and regional roadmaps away from fossil fuels.

Speaking in plenary, Vélez Torres said that the roadmaps should be “connected” to countries’ UN climate plans, known as nationally determined contributions (NDCs). She added that it would be important for the roadmaps to be “very clear and honest” about “emissions exported from producing countries”.

The development of the roadmaps will be supported by the newly established science panel for global energy transition and the NDC Partnership, a global initiative helping nations prepare their NDCs, she added.

(At the final press conference, it was clarified that countries are not obligated to produce a new fossil-fuel roadmap and that participation in all of the work streams is voluntary.)

The second workstream will be focused on changing the financial system to better facilitate the transition away from fossil fuels.

This will include work to identify fossil-fuel subsidies and find solutions to “debt traps”. It will be supported by the International Institute for Sustainable Development thinktank, the co-hosts said.

Separately, Dutch climate minister van Veldhoven said that all countries would be invited via “email” to begin a process for identifying and reporting their fossil-fuel subsidies. (The Netherlands is the co-chair of COFFIS, a group of 17 nations that have pledged to remove fossil-fuel subsidies.)

The final workstream will address fossil-fuel-intensive trade, with the aim of “advancing progress towards a fossil fuel-free trade system”, Vélez Torres said. This workstream will be supported by the Organisation for Economic Co-operation and Development (OECD) group of wealthy nations.

A document summing up the co-chair’s takeaways from the summit says that other key outcomes include the establishment of a “coordination group [to] ensure continuity towards the second and subsequent conferences”, adding:

“It will consist of countries leading different alliances and initiatives that are implementing elements of the transition away from fossil fuels, and of the co-hosts of the first and second conferences, Colombia, the Netherlands, Tuvalu and Ireland.”

The document adds that a key task will be delivering the findings of this conference to the COP30 presidency, which is currently preparing a global fossil-fuel roadmap to present at COP31 in November.

Academic meeting

The summit kicked off with a “science pre-conference” attended by around 400 academics from across the globe from 24-25 April, held at the University of Magdalena in Santa Marta.

At the behest of the Colombian government, these scientists split into 11 different “workstreams” to debate a vast array of topics related to transitioning away from fossil fuels.

These ranged from “fossil-fuel phaseout policies” and the role of methane, to “just transitions and economic diversity” and the role of multilateralism.

Speaking on the summit’s first day, Colombian environment minister Irene Vélez Torres – herself a former academic – stressed the importance of science in political decision-making. She told a press conference:

“There has been a growing gap between science and governments, and governmental decisions, and it happens because there is a lot of denialism. There is a lot of economic and political lobbying as well. That is actually deviating [from] scientific rationale.

“The true belief of the countries that are here is that we need to go back to science and base our decisions on science, and back up our decision-making, processes and pathways with science.”

Science panel for global energy transition

The pre-conference saw the announcement of three new scientific initiatives.

The first was a new global science panel, calling itself the “science panel for global energy transition”, which was launched by Dr Johan Rockström, director of the Potsdam Institute for Climate Impact Research in Germany and Dr Carlos Nobre, an eminent researcher on the Amazon rainforest from the University of São Paulo in Brazil.

They announced at a public event in Santa Marta that the panel will involve “50-100 scientists” from around the world and will be based at the University of São Paulo.

The scientists on the panel will aim to provide rapid analysis on how to transition away from fossil fuels for countries and multilateral talks, including bespoke information for nations that request it, they said.

Speaking at its launch, Rockström said the panel will be split into four working groups, focusing on “transition pathways”, “technology solutions”, “policy design and evaluation” and “finance instruments and governments”.

It will have three co-chairs: Dr Vera Songwe, an economist and climate finance expert from Cameroon; Prof Ottmar Edenhofer, chief economist at the Potsdam Institute for Climate Impact Research; and Prof Gilberto M Jannuzzi, professor of energy systems at Universidade Estadual de Campinas in Brazil.

Speaking to Carbon Brief, Nobre said that he and Rockström were first approached with the idea for a new panel by Ana Toni, Brazilian economist and CEO of the COP30 climate summit, while the negotiations were taking place in Belém. He said:

“Johan and myself, we’re not energy transition scientists, but we were the creators of the planetary science pavilion at COP30, that’s why Ana Toni came to us. And we have already invited three top energy transition experts to join us.”

At the launch, Rockström said the panel would be different in several ways from the world’s existing global climate science panel, the Intergovernmental Panel on Climate Change (IPCC).

He said that, in comparison to the “seven-year cycle” for IPCC reports, this panel will “be able to come up with annual updates” and “be able to scale down to the national level”.

Nobre told Carbon Brief that he was among scientists who have grown “frustrated” with some aspects of the IPCC’s process, including the line-by-line approval of summaries for policymakers by all of the world’s governments. He said:

“A long time ago, when I was working as a scientist studying the Amazon, I wanted to include some information about the risks the Amazon faces in one of the summaries. But a representative from my own country [Brazil] said no.

“This panel is totally independent. There is no way for somebody to say ‘you can’t say that’ or ‘you can’t do that’.”

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Action insights report

The second new science initiative to emerge from the academic conference was a new “synthesis report”, offering “12 action insights” for how countries can transition away from fossil fuels.

First covered by Carbon Brief, the report contains some explicit “action recommendations” for countries, such as “halt all new fossil-fuel expansion” and “prohibit fossil fuel advertising…recognising fossil fuels as health-harming products”.

The report was first put together by an “ad-hoc” group of 24 scientists at the request of the Colombian government. It was then further debated and refined by many of the 400 scientists gathered at the academic pre-conference in Santa Marta.

A preliminary version of the report was circulated to governments attending the talks.

In addition, one of the report’s coordinating authors, Prof Andrea Cardoso Diaz, from the University of Magdalena, was given a two-minute slot in the opening plenary of the “high-level segment” to highlight its findings to gathered ministers.

Colombia’s fossil-fuel roadmap

The final scientific initiative unveiled at the academic segment was a new roadmap for how Colombia can transition away from fossil fuels. This was drafted by a team led by Prof Piers Forster, head of the Priestley Centre for Climate Futures at the University of Leeds.

The roadmap says that Colombia can cut its emissions from energy use to 90% below 2015 levels by 2050, through ambitious policies to move away from fossil fuels and electrify its transport sector.

This would require “considerable” upfront investment, with the roadmap estimating the cost to be an average annual investment of around $10bn above a business-as-usual scenario.

However, by the 2040s, Colombia could see net economy-wide savings from transitioning away from fossil fuels, says the analysis, which could reach $23bn annually by 2050.

Speaking to Carbon Brief, Forster said his experience as interim chair of the UK’s Climate Change Committee highlighted to him the importance of presenting national roadmaps in economic terms. He said:

“The biggest issues facing countries are economic and to do with the cost of living. To convince our own government back in the UK to sign up to our recommended carbon budget, we put a lot of work into the economic aspect. So that was also the focus of this work for Colombia.”

Indigenous and civil society participation

In addition to holding a dedicated meeting for scientists, the Colombian government also organised a “People’s Assembly”. This brought together hundreds of Indigenous peoples, Afro-descendent peoples, peasant farmers, trade representatives, women and children and other civil society members.

The goal was to gather the thoughts from these groups on the summit’s main “pillars” of addressing fossil-fuel production, economic constraints and global governance and multilateralism.

According to Climate Lens News, Óscar Daza, the secretary general of the Organisation of Indigenous Peoples of the Colombian Amazon, Karebaju people, told the gathering:

“The Indigenous peoples of the world have made historic demands, such as the non-extraction of natural resources from our territories, so that our resources that are there in the territory remain intact, remain still.

“As Indigenous peoples, we want those historic struggles to somehow be reflected and taken up here by the different states.”

Following on from the meetings, the Colombian government summarised the main talking points discussed by each of these groups in a series of “contributions” documents.

Indigenous peoples and civil society groups were also allocated opportunities to speak during the summit’s high-level segment.

In a departure from UN climate summits – where inputs from civil society are usually heard after countries have finished speaking – the Santa Marta summit invited a range of representatives to speak alongside ministers in the opening and closing plenary sessions.

This included an intervention in the opening plenary by Larissa Baldwin-Roberts, a climate leader from the Bundjalung Nations, who told countries:

“This is the last time we will be a token. You want our pictures, not our voices. You want our stories, not our struggles…True solidarity with each other is the prerequisite to a just transition.”

Indigenous peoples and civil society members were also free to speak in closed-door discussions with ministers, Carbon Brief understands.

Separately from the events organised by the Colombian government, civil society also organised its own “people’s summit”, involving 900 organisations and networks, held in the city of Santa Marta from 24-26 April.

This summit also organised sessions for representatives from different groups to offer their thoughts and insights into the transition away from fossil fuels, ending in a joint “declaration”.

In a statement, Tasneem Essop, the executive director of Climate Action International, said:

“Movements from across the globe and the region – Afro-descendants, feminists, youth, peasants and fisherfolk, social movements and Indigenous peoples converged in a three-day peoples summit in Santa Marta to build a collective consensus on our demands and solutions for the just transition away from fossil fuels.

“[We saw] the adoption of a powerful declaration that spells out our positions on ensuring that the transition has to be rights-based, funded and results in the dismantling of the systems that have caused harm and destruction driven by fossil fuel dependency.”

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