Back
See more from Canary Media’s “Chart of the week” column.
Wind and solar are on the rise worldwide — here are the 10 countries that rely on the clean-energy sources most for their electricity.
All of these countries used wind and solar to produce at least one-third of their electricity in 2024, according to a new report from the Energy Institute. For leading countries such as Denmark, Djibouti, and Lithuania, that figure was in the range of two-thirds or more.
Those numbers are much higher than the global average: Overall last year, wind and solar accounted for 15% of global power generation, up from 13% in 2023.
To be clear, China is still by far the largest producer of solar and wind energy in the world in terms of volume. The country generated 1,836 terawatt-hours of wind and solar last year. All of Europe, for comparison, generated 990 TWh over the same period. But despite that huge amount of renewable energy generation, China received a much lower share of its power from solar and wind in 2024 than the 10 countries on this list — just about 18%.
The list is mostly populated by smaller countries, but it does include some large economies like Germany and Spain. In Germany, wind and solar accounted for a combined 43% of power. In Spain, 42%. (Spain recently suffered a countrywide blackout for which its high share of renewables was blamed. The true culprit, according to a government report released last week, was poor grid planning.)
By the end of the decade, the International Energy Agency expects wind and solar together to account for nearly 30% of global electricity generation. So, while only a handful of countries boast high levels of renewable energy penetration today, many more will join their ranks in the coming years, as wind, and especially solar and batteries, get cheaper and harder to refuse.
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
Record-breaking heat swept across the eastern U.S. this week — and with millions of air conditioners whirring, power demand came close to breaking records too.
The ISO New England grid region, which covers most of New England, saw its second-highest power demand ever on Tuesday. In Maine, experts with the Governor’s Energy Office told the Portland Press Herald that New England would’ve beaten the record if it wasn’t for behind-the-meter solar power, like panels on rooftops and over parking lots that aren’t controlled by grid operators. But the region still had to activate fossil fuel-fired peaker plants — which worsen climate change and air quality — to meet demand in the evening.
The grid operated by PJM Interconnection, which includes New Jersey, Ohio, Pennsylvania, Virginia, and other mid-Atlantic states, also came close to breaking demand records both Monday and Tuesday. Power outages affecting thousands of homes were reported throughout the region, with utilities blaming many of them on the high temperatures.
One growing technology could’ve helped the grid manage the heat even better: battery storage. Take New England. Instead of switching on fossil-fuel peaker plants, batteries could’ve stored excess power generated during the day and discharged it when demand peaked — something numerous studies have suggested as a solution for the region. It’s a method that the grid operators for Texas and California rely on every day, as power generated when the sun is shining is stored for use when it sets.
But not every region is embracing the technology. PJM, in particular, has failed to take advantage of batteries in spite of its demand challenges, partly because it has one of the longest waits in the country to connect to the grid.
Battery storage is also threatened by the “Big, Beautiful Bill” currently making its way through Congress. While the Senate did extend a lifeline to the energy-storage industry in its version of the bill, a Wood Mackenzie/American Clean Power Association analysis out this week found that grid-battery installations could still dip as much as 29% next year if tax credit and tariff uncertainty continues.
New York envisions a nuclear future
New York Gov. Kathy Hochul (D) launched an ambitious quest this week, directing the state’s Power Authority to build a large nuclear reactor. The reason? Rising power demand.
“If we don’t increase our capacity over the next decade, we will see rolling blackouts,” Hochul warned at a press conference. “This is the best technology to meet this demand.”
New York is already home to three nuclear power plants, and until just a few years ago, it had four. The Indian Point power plant shut down in 2021 over environmental contamination concerns. But since then, New York has had trouble making up Indian Point’s lost generation capacity, leading the state to rely on more gas power — which has in turn raised greenhouse gas emissions.
In Texas, a company led by Rick Perry, former Republican governor and Trump administration energy secretary, is proposing a nuclear project of its own. Fermi America aims to build four 1-gigawatt nuclear reactors to power a massive data-center campus.
It’ll be years before either one of these proposed plants would come online. But at the very least, it’s yet more evidence of nuclear power’s rebounding popularity on both sides of the aisle.
Senate parliamentarian rescues some energy measures from the “Big, Beautiful Bill”
Some of the Senate’s efforts to roll back Biden-era energy and environmental measures were knocked down a peg this week, courtesy of the body’s parliamentarian. The nonpartisan adviser to the Senate ruled that many “Big, Beautiful Bill” provisions can’t be passed via the 50-vote budget reconciliation process, and instead will need 60 votes to pass. Senate Republicans have only 53 seats.
The parliamentarian’s critique includes a measure that would force the U.S. Postal Service to sell all 7,200 of its newly purchased EVs and scrap its charging infrastructure — a move the USPS said would cost it $1.5 billion. The parliamentarian also ruled against provisions to speed fossil-fuel project approvals, repeal the EPA’s tailpipe-emissions rules, and sell off public lands.
In response, Senate Republicans unveiled new language on Wednesday that omits the tailpipe-emissions rollback and makes other energy-related edits.
Also this week, several groups — including car dealers, energy investors, and even Georgia Republican state legislators — wrote to the Senate urging it to protect clean energy tax credits.
EV funds restored: A federal judge orders the Trump administration to release billions of dollars of frozen funding for 14 states to build a public EV charging network, but leaves out Minnesota, Vermont, and Washington, D.C., which had also sued to get funding restored. (Associated Press)
Building more batteries: LG Energy Solution cuts the ribbon on its expanded battery plant in Michigan, where it’ll now produce utility-scale battery cells that utilize lithium iron phosphate chemistry. (Canary Media)
Coal’s deadly impact: The “old man’s disease” of black lung has been affecting younger coal miners at rates not seen since the 1970s, and advocates worry cuts to federal health and mining safety offices Trump’s attempt to revitalize the mining industry could exacerbate the problem. (New York Times)
Green lawns, greener mowers: Colorado landscapers are making the transition to electric lawn equipment after new state regulations went into effect this month to help curb noxious fumes that contribute to poor air quality. (Canary Media)
Fishing for electrification: Electric boats and solar-powered processing equipment are starting to create environmental and financial benefits for Maine’s growing shellfish industry, but uncertainties around federal funding could slow progress. (Maine Monitor)
A geothermal community: A suburb of Austin, Texas, aims to power 7,500 planned homes and commercial buildings with a sprawling geothermal energy project. (Texas Tribune/Floodlight)
Weatherization paradox: Many low-income households can’t access the free, energy-saving Weatherization Assistance Program because they can’t afford to make basic but expensive repairs required for qualification. (Grist)
Steel’s cleaner future: Steelmakers planning new facilities in the U.S. are embracing a cleaner technology for purifying iron ore, which can then be used in electric furnaces to finish the steelmaking process. (Canary Media)
Massachusetts last week enacted a revamped version of its solar incentive program that developers and advocates say should keep the state’s solar industry moving forward even as the Trump administration pushes to undermine federal support for clean energy.
“In short, the program makes Massachusetts a very healthy market for solar,” said Nick d’Arbeloff, president of the Solar Energy Business Association of New England. “We’ll still be able to present a compelling case to an investor.”
The newest iteration of the Solar Massachusetts Renewable Target program — generally called SMART — makes fundamental changes to the structure of the incentives to be more responsive to market conditions. Other provisions aim to make the benefits of solar available to more low-income residents, protect valuable open space from development, and encourage placement of panels on rooftops and in parking lots.
The state filed the new rules as emergency regulations, allowing them to go into effect immediately.
The move comes just in time, according to solar developers. The previous version of SMART hasn’t been effective in quite some time, they say. While draft regulations for this newest version of SMART were first released nearly a year ago, and a final revision was expected in fall 2024, months went by without new rules.
“The uncertainty we were facing was confusing inventors, was killing projects, and could have done even more damage,” d’Arbeloff said.
In the meantime, President Donald Trump took office and Republican legislators have been working on a budget bill that seems likely to accelerate the elimination of federal renewable energy tax credits. Massachusetts solar developers became increasingly worried they would find themselves in a “valley of death,” with neither state nor federal support, at least for a time, said Ben Underwood, co-CEO of Resonant Energy, a Boston-based solar company that specializes in projects serving environmental justice communities.
Developers, therefore, heaved a sigh of relief when the new state regulations were filed. The reimagined program will start accepting applications on October 15, which will give developers a chance to get projects in place and investors lined up, even with the threat of disruption at the federal level, Underwood said.
“Now we and other members of the industry can start to plan for the incentives,” he said. “It gives us a much easier transition in case federal incentives are taken away.”
Launched in 2018, SMART pays the owners of solar systems a set rate per kilowatt of energy generated by their panels. The base rate depends on project type, location, and size. Projects advancing goals the state supports — serving low-income communities, for example, or building on a closed landfill — receive a boost, known as an “adder,” to their base rate.
The program was initially designed to lower its rates as more solar installations were built. The thinking was that, as the solar industry became more established, the cost of developing projects would go down and developers would need less financial support to be viable.
For years, SMART helped drive solar growth in the state: From 2019 to 2021, annual solar installations more than doubled. Then the Covid-19 pandemic intervened, upending supply chains and sparking inflation. At the same time, SMART compensation rates had fallen, as intended. Suddenly, the incentive payments weren’t enough to cover growing costs, and the industry took a hit. In 2024, less than half as much solar capacity was installed than in 2021.
“You were finding that the incentive level for many projects was, in fact, zero,” d’Arbeloff said.
The new rules jettison the old system of declining rates, replacing it with one that resets the compensation and program size each year, allowing the program to adjust to future unexpected market changes. Annually, the state will conduct an economic analysis that considers progress toward emissions reduction goals, regional and national solar costs, current and historic program participation rates, and land-use and protection goals, and will use the results to set compensation for the coming year. Adders will still be part of the system, and will also be adjusted annually, as needed.
“We can understand the costs, we can understand the size of the program, and we can make adjustments with ratepayers in mind,” said Elizabeth Mahony, commissioner of the Massachusetts Department of Energy Resources. “That’s really important for ratepayers and the development community — we’re going to be so nimble.”
For 2025, the program will be open to up to 450 megawatts of capacity. The base compensation rates will be set after the state completes a new economic analysis in the next few months, Mahony said.
The revised regulations also aim to increase the amount of money flowing to solar projects serving low-income residents. For a development to receive an adder as a community shared solar project, it must allocate at least 40% of the bill credits it generates to low-income households and guarantee these customers a savings of at least 20%, compared with the basic retail price.
“It represents a substantial move toward having greater value for low-income community shared solar participants,” Underwood said. “It’s really good to see that.”
The new regulations also target ongoing tensions about how best to site solar projects while still protecting wildlife habitats and agricultural land.
“We hope the way this works is it pushes folks to do more on rooftops, to do more on canopies, and to do more on previously developed land,” said Michelle Manion, vice president of policy and advocacy for the Massachusetts Audubon Society. “When it comes down to the actual numbers, then we’ll see how well it actually works.”
Certain categories of land with particular environmental value have been declared ineligible for solar development going forward. Projects built on other open spaces will have to pay a mitigation fee that will be determined by a list of factors, including the land’s carbon storage and agricultural potential, the parcel’s ecological integrity, the cumulative impact of the proposed development and others in the area, and location of the planned project relative to grid infrastructure.
“It’s a good way to be a little more strategic about siting solar,” said Erin Smith, clean grid director for the Environmental League of Massachusetts.
These measures are combined with provisions that encourage more development on the built environment. The regulations expand the definition of a solar canopy that qualifies for an adder — which was limited to projects over parking lots, canals, and pedestrian walkways — to include any array raised high enough off the ground to allow the use of the area beneath for another function. The rules also create a new category of adder for panels mounted above other equipment atop buildings, allowing more efficient use of rooftop space.
Though the emergency regulations process put the new rules into effect immediately, the state must still hold three hearings within 90 days to gather public feedback and get final approval from utility regulators. Some tweaks to the program could be coming, but state officials are confident they’ve got the basics right.
“There are quite a few projects that have been waiting for this to come out,” Mahony said. “We believe this is one of the best ways we have to build energy generation in the next few years.”
This article originally appeared on Inside Climate News, a nonprofit, non-partisan news organization that covers climate, energy, and the environment. Sign up for their newsletter here.
In Richmond, California, Zenaida Gomez is ready to say goodbye to the gas stove in the apartment she has rented for over a decade. She has a hunch that the pollution it emits is exacerbating her 10-year-old son’s asthma attacks, and she has heard from public health experts and doctors who’ve said it probably is.
“I’ve learned that not only do we have contaminated air when we are outside in Richmond, but there’s contamination and toxins within our homes,” Gomez said in a recent phone call.
She started attending City Council meetings and organizing with her neighbors as a member of the Alliance of Californians for Community Empowerment (ACCE) Action, because, she said, “I wanted something different. I wanted something better.”
But ACCE Action’s goal isn’t simply to get rid of gas stoves. In a city where about one in four people — nearly double the national average — suffer from asthma due in large part to pollution from heavy industry, the group wants to shut off or “prune” the lines that send natural gas into homes in some neighborhoods. The phenomenon is called “neighborhood-scale decarbonization,” and it’s just getting off the ground in California.
Pacific Gas & Electric, the utility in the area, is on board with the idea. It has expressed a willingness to spend a portion of the money it would otherwise use to maintain gas lines to help electrify the homes in the neighborhood that will no longer use the gas.
David Sharples, county director at ACCE Action, says the group is looking at different neighborhoods that PG&E has identified as likely candidates. Once the group chooses an area, it plans to run a pilot project with the goal of electrifying all the appliances and adding solar panels and batteries for up to 80 homes.
“We’re looking at the Coronado, Iron Triangle, and Santa Fe neighborhoods, which are working-class, Black and brown neighborhoods where ACCE has been organizing for years,” Sharples said. “They all have old gas lines that need to be replaced, so it represents an opportunity to electrify.”
To understand the appeal of neighborhood-scale decarbonization, which is also sometimes called “zonal decarbonization,” it helps to be able to envision the vast network of gas pipelines that exist under most cities in the Western U.S. That network holds a potentially explosive gas, and it requires constant, expensive upkeep.
California has pledged to install 6 million heat pumps by 2030 as part of its larger effort to reach net-zero by 2045. And while a rule will begin going into effect in the Bay Area in 2027 requiring that broken water heaters and furnaces be replaced by electric appliances, a similar rule was just rejected in Southern California.
Experts say a large-scale effort just makes more sense than a piecemeal approach in many parts of the state. And as dramatic as it might sound to transition a whole block or neighborhood off gas at once, the approach may also cost less overall and make it easier to employ people fairly.
Neighborhood-scale decarbonization has also been popular with lawmakers. Last fall, the California Legislature voted to adopt SB 1221, a bill that will enable up to 30 neighborhood-scale projects of this type over the next five years.
The catch is that most residents in the neighborhoods must agree to the change. While the state’s obligation to serve currently requires 100% approval, SB 1221 will lower the threshold to 67% as the pilot projects start rolling out. Several groups have begun the work of educating communities about the benefits of the switch.
In Albany, a city of about 20,000 people north of Berkeley, Michelle Plouse, the city’s community development analyst, has spent the last few years working with PG&E to pilot one of the first neighborhood-scale projects in the state. Using the gas line mapping tool developed by the utility, Plouse and other city staff worked with the Albany City Council to identify 12 potential blocks. This spring, they narrowed it down to three.
The goal, Plouse said, is to find blocks that are easier to electrify while also focusing on lower-income parts of the city, where residents are less likely to be able to afford to electrify.
“What will happen if we don’t decommission the gas line is that the cost of maintaining it will continue to increase over time, and the user base will drop as people electrify,” said Plouse. “The folks who don’t have the money to electrify will be stuck on gas that will get more expensive every year.”
The City of Albany received a grant from the U.S. Department of Energy for the project, and they’ve used the funds to support an outreach plan that involves a block party, a focus group, and a team that goes door-to-door in hopes of talking to everyone on the three blocks. “It’s going to be a lot of listening and a lot of connecting with different people,” said Plouse.
Rachel Wittman, a senior strategic analyst at PG&E, said the utility provided a letter of commitment in support of Albany’s DOE grant, but it won’t be providing financial support for the project.
Although the California Public Utilities Commission is soliciting interest from communities that want to take part in the SB 1221 pilot program, a spokesperson for the commission said it won’t have a list of potential sites until the second half of 2026, at the soonest.
The Albany project will begin before then, so it won’t likely be considered one of the 30 pilots, and Plouse said they’re hoping to get 100% of the residents to sign on. “What’s most likely is that we continue serving as a kind of first test run that can provide information for those pilots,” she said. If that doesn’t work, they may decide to wait until they only need 67% resident approval.
“Albany’s learnings from their efforts in community outreach and advocacy during this project will provide valuable insights that can inform zonal electrification outreach strategy,” said Wittman. “This applies not just for SB 1221 and PG&E, but for any utility or community.” She said over three dozen cities, counties, and other energy providers have reached out to the utility with interest in zonal decarbonization.
ACCE Action and others in Richmond hope its neighborhood-scale project — dubbed Clean Energy and Healthy Homes — will be included in the list of pilot projects, and it appears to have a good chance at making the list. If they’re able to decommission a gas line there, Sharples estimates that it could cost as much as $15 million to upgrade and electrify homes spanning a few different neighborhoods and provide them with solar power. He hopes PG&E will cover around 10% of that cost.
The Richmond City Council approved the effort in early 2024, but the remaining funding is still in question. Chevron, whose local refinery has been a major polluter for more than a century, entered into a settlement with the city for $550 million over the next 10 years to avoid paying a per-barrel tax on the oil it produces. ACCE Action wants to see a portion of that money spent on the neighborhood-scale project. The group has been hosting community events and engaging community members like Gomez.
Tim Frank, a representative of the Building and Construction Trades Council in the county, wants to see the project move forward because it could also create a model for so-called high-road work in the home-electrification space. Currently, unionized workers tend to do larger electrification projects, while one-off residential projects are done by smaller companies not affiliated with unions. While some pay their workers well, many hire temporary laborers and keep wages low.
Electrifying all the homes on one block allows for the efficiency and stability associated with larger projects while benefiting individual families. It’s also more cost-efficient because it allows for bulk purchases of supplies.
It’s a worthwhile experiment, Frank said. “We’re engaged, partly because we see the huge promise of this strategy and we want to help prove out the model and scale it up,” he added.
For Gomez, who has been talking to her neighbors about the possibility that all their homes could be upgraded and electrified at once, the biggest barrier is convincing them that it’s not a scam. Richmond’s low-income communities have seen their share of companies that go door-to-door trying to extract money from people who are stretched thin and working multiple jobs. Some clean energy providers have turned out to be imposters.
“It’s something they’ve never heard of before. So, people ask: Is this a real thing? Can it actually happen?” And she tells them that yes, if the plan goes as a growing number of people hope it will, it just might.
This story was produced with support from the Climate Equity Reporting Project at Berkeley Journalism.
The U.S. battery supply chain just got a little stronger.
LG Energy Solution, a division of the major Korean battery manufacturer, is now producing battery cells for grid-scale energy storage at a site in Holland, Michigan. The company spent $1.4 billion to expand the factory, which previously made electric vehicle batteries. At full capacity, the new lines will produce 16.5 gigawatt-hours of lithium iron phosphate cells per year.
“That’s a sizable portion of annual domestic demand for energy storage battery cells,” said Noah Roberts, vice president for energy storage at the American Clean Power Association trade group, who toured the LG factory Tuesday. “It’s a testament and demonstration of the industry’s commitment to onshoring manufacturing and ramping it up in short order.”
The lithium iron phosphate chemistry, often abbreviated as LFP, has grown increasingly popular for stationary storage and EVs; it offers fire-safety benefits, durability, and lower costs compared to the typical electric vehicle chemistries, at the expense of some energy density. Until now, American battery customers had to turn to China for any LFP supplies. LG’s facility appears to be the largest giga-scale LFP production in the U.S. Japan’s AESC recently launched LFP production at its factory in Smyrna, Tennessee, and Tesla is working to onshore LFP production as well.
As such, LG’s investment is strengthening the U.S. clean energy supply chain at a time of great precariousness, when several other would-be battery manufacturers have failed to deliver.
The plan originated as a way to bolster local supply chains, before Congress passed concerted battery manufacturing incentives, said Jaehong Park, CEO and president of LG Energy Solution Vertech, which focuses on stationary grid storage. But when the Inflation Reduction Act of 2022 created incentives for manufacturing and grid storage deployment, LG upped its planned capacity from 4 gigawatt-hours to the eventual 16.5.
The company initially intended to install these manufacturing lines in Arizona, but relocated them to a portion of its Holland facility that had been developed to expand EV battery production, which LG has done there since 2012. By shifting the LFP equipment to the space in Holland, LG could open commercial production a full year earlier than originally planned, noted Tristan Doherty, chief product officer at the storage division.
Now the Holland manufacturing space covers the area of 42 football fields, and will employ 1,700 people when fully staffed.
“It is very clearly a state-of-the-art facility with the most advanced manufacturing that you can have in the United States,” Roberts said.
The LFP products are booked up six months out, and LG is already looking at doubling the production capacity next year, Park said.
Manufacturers took a gamble in betting that the U.S. could reshore the battery production that China has cornered with dedicated industrial policy over the last decade or more. Companies need to build new industrial hubs and train American workers, and then try to match the quality and consistency of the incumbent industry in China.
The Biden administration passed several incentives to reduce the cost premium for “Made in the USA” batteries, including tax credits for purchasing electric vehicles with domestic batteries, and bonus credits for grid storage developers who buy domestic content.
But the current Republican majority in Congress is working to eliminate those policies, to save money for much more costly deficit spending in President Donald Trump’s signature policy bill. Companies like LG that greenlit multibillion-dollar factory investments under one tax credit regime no longer know which rules will apply when they start production.
Doherty acknowledged there’s a great deal of uncertainty at the moment, but said he’s confident in the long-term bet on U.S. battery production.
“It’s clear that the industry is here and it’s here to stay — the question is just what it looks like and what are the nuances to make it work,” he said. “There’s a lot of very big deals that are in the works. Everyone understands, you need to get U.S. battery supply in your supply chain as quickly as possible.”
Trump’s massive tariffs on China could in theory support domestic producers. But the president has changed his tariff plans from week to week, denying would-be manufacturers the stable business environment they like to see before committing billions of dollars to a yearslong endeavor. Blanket tariffs on China also inflate the cost of battery materials, which are almost entirely processed in that country, as well as the cost of battery manufacturing equipment, which also largely originates there.
LG, as a South Korea-based conglomerate, has been able to avoid the negative scrutiny that American politicians have increasingly leveled at Chinese clean energy manufacturers. LG now sources its battery materials for Holland from outside China, and its manufacturing equipment came from Korea and Japan, Park said.
When Trump came into office, the U.S. was on track to achieve self-sufficiency in battery cell production, per a 2024 analysis by Argonne National Laboratory. The U.S. could make 74 gigawatt-hours of lithium-ion battery cells in 2023, but was set to grow that to 1,133 gigawatt-hours by 2030, comfortably more than expected demand.
During Trump’s tenure, though, new manufacturing investments have plummeted compared to the Biden years, and project cancellations surged to nearly $8 billion in the first quarter of 2025. In that time, for instance, Freyr Battery canceled a planned battery factory in Georgia (and later rebranded itself as T1 Energy), and Kore Power axed a lithium-ion factory slated for Arizona.
Elsewhere in Michigan, startup Our Next Energy has been laboring to build the first large LFP factory in the U.S. But it has yet to secure the funding necessary to fill out the cavernous building it acquired west of Detroit, and the company is struggling to stay afloat.
T1 Energy, Kore Power, and Our Next Energy share something in common: They are venture capital-backed startups attempting to compete with the incumbents of the global battery industry. That model hasn’t produced a standout success yet — even Tesla initially tapped an incumbent, Panasonic, to make EV batteries at its Nevada Gigafactory.
The achievement at Holland looks rather modest compared to LG Energy Solution’s global portfolio, which Doherty said has reached around 500 gigawatt-hours of annual battery production.
“As a big company with a big balance sheet, we can have the confidence to say we’ll weather this storm,” Doherty said. “We’ll make it to the other end because we see where this is going.”
LG’s customers may have more difficulty riding out the turbulence of constantly changing tariffs and tax policy.
“This is a market that is growing, and any disruption that causes it to contract is something that will harm manufacturing,” Roberts said of the grid storage construction sector.
Global demand for steel is rising, and with it, emissions from the coal-fired blast furnaces that churn out around 70% of the world’s supply. American steelmakers are less reliant on blast furnaces than other countries, but they are doubling down on plans to extend the lives of the handful still operating in the U.S.
As those same steelmakers plan new facilities, though, they are embracing a cleaner technology called direct reduced iron, or DRI, to purify iron ore, the first step in the production of primary steel.
The DRI process uses a high-temperature gas to remove oxygen from the ore. The remaining iron can then be added to a traditional basic oxygen furnace or, more commonly in modern systems equipped with DRI, to an electric arc furnace that can be powered by carbon-free electricity.
Most DRI plants operating today use natural gas, a fossil fuel primarily made up of planet-warming methane. But even those can produce 50% less carbon emissions than coal-fired blast furnaces — and if the technology can be paired with carbon capture or fueled instead by green hydrogen, carbon-free steel becomes a possibility.
While DRI facilities account for just 9% of global ironmaking capacity today, they comprise nearly 40% of what’s under development. The U.S., for its part, has only three DRI plants up and running — but every new ironmaking facility slated to be built in the country will use DRI. That includes South Korean automaker Hyundai’s planned DRI plant in Louisiana, which the company announced in March.
The technology for DRI has existed for more than half a century, but it’s made exclusively by two firms that few outside the industry have ever heard of: Midrex Technologies and Tenova. Now, as some countries seek to build steel plants that don’t burn coal, these two firms are poised to reap the benefits.
Midrex Technologies dominates the DRI market. The North Carolina-based company built the first U.S. plant using the technology in Portland, Oregon, in 1969.
“DRI has a bigger and bigger role to play in the energy transition. The long-term view for DRI is positive. Demand for DRI keeps increasing,” said Vincent Chevrier, Midrex’s general manager of technical sales and marketing. “It’s probably going to double, then triple, in the next 20 years.”
The other major manufacturer, Tenova — owned by the Buenos Aires-based Techint, with technology jointly developed with Italy’s steel giant Danieli — started making DRI technology at the turn of this century. With just a fraction of the market, the firm may be the underdog, but CEO Francesco Memoli sees an advantage.
Tenova’s technology can swap out natural gas for hydrogen without any modifications. While Midrex says its equipment needs only minor upgrades to optimize for hydrogen, Tenova said the innate flexibility of its system allows it to ride out whichever way the political tides turn in the U.S.
Lately those tides have been turning against green steel.
In January, just before President Donald Trump’s inauguration, the Swedish steelmaker SSAB bowed out of negotiations for $500 million in federal funding the Biden administration had put up to support a DRI plant powered entirely with green hydrogen in Mississippi.
Cleveland-Cliffs — considered the more progressive of the American steelmakers — has suggested it would abandon its plans to build a DRI facility and use hydrogen to produce steel at its Middletown, Ohio, plant as it renegotiates the $500 million grant it had been awarded with the Trump administration.
Weeks after Cleveland-Cliffs started backing away from the project, Nippon Steel secured Trump’s approval to take over American rival U.S. Steel. The Japanese behemoth, the world’s fourth-largest steel producer, lags so far behind other companies in developing a decarbonization plan that the watchdog group SteelWatch recently described Nippon as “a coal company that also makes steel.” While Nippon has pledged to build a new electric arc furnace, a machine that uses electricity to turn scrap metal into fresh steel, the company has also staked out plans to extend the operations of U.S. Steel’s existing blast furnaces.
Meanwhile, Republicans in Congress have proposed eliminating the federal tax credit meant to spur green hydrogen production, which would create yet another setback.
In the near term, most of the new DRI plants in the U.S. will likely run on gas, Memoli said.
“Natural gas is very accessible in the U.S.,” he said.
Already, Tenova can capture some of the emissions from the gas it uses. Steelmaker Nucor deploys Tenova equipment at its plant in Louisiana, which last year set a world record for DRI production. In 2023, Nucor inked a deal with Exxon Mobil Corp. to capture and store the carbon from the steelmaker’s DRI process.
In Mexico, the Latin American steelmaker Ternium funnels CO2 captured from Tenova’s DRI equipment to Coca-Cola, Memoli said. Tenova puts the gas through two rounds of cleaning until it’s safe for use in beverages, and sells it to another company that in turn supplies the CO2 to Coca-Cola.
“All of the soda produced in Mexico by Coca-Cola is using CO2 recycled from an ironmaking plant,” Memoli said. “The joke is that Mexican Coke tastes better because of that.”
While the CO2 emitted by the DRI process is captured in the Tenova system, Memoli said the carbon produced from heating the gas to 1,000 degrees Celsius remains a source of pollution. The company is planning to roll out new features in the next few years to capture even that “residual” CO2.
Elsewhere, the company’s equipment is already running on hydrogen, or will be soon.
Last year, a major Swedish green metal project selected Tenova’s technology to generate iron with 100% hydrogen for the steelmaking giant SSAB. The fuel is gaining ground in China, too, which lacks domestic gas resources. Tenova-equipped plants in the world’s second-largest economy are already churning out 700,000 tons of iron per year using anywhere from 30% to 70% hydrogen, Memoli said, though only some of that hydrogen is green. The world produces about 2.5 billion tons of iron each year, for context.
Despite the headwinds for hydrogen-based steelmaking in the U.S., the industry could still move away from traditional steel plants (also called integrated plants because of their use of blast furnaces and basic oxygen furnaces) in the coming years. Industry analysts say DRI is the technology that will enable this shift — one that some say is critical both economically and for the climate.
“Blast furnace technology is outdated — full stop. It’s too dirty, it’s too energy intensive, and it’s too inefficient,” said Elizabeth Boatman, a lead consultant at 5 Lakes Energy, a Michigan-based research firm. “Overhauling our integrated mill fleet will be expensive, but it’s an investment that will pay off in the long term.”
Already, mini mills across the U.S. make use of the large volumes of scrap metal in the U.S. to produce lower-carbon steel than what coal-fired plants in China make fresh.
“What we are seeing, because of the switch of energy from coal, is that it offers the possibility of decoupling ironmaking from steelmaking,” said Midrex’s Chevrier. “You can place your ironmaking facility where the energy is cheap, and maintain your steelmaking facility at the location where your customers are and your scrap is.”
That could also create an opening for some of the startups looking to popularize next-generation ironmaking techniques. The Colorado-based company Electra, which aims to use a process called “electrowinning” to purify iron without a blast furnace, raised $186 million in April to support its scale-up. The Massachusetts Institute of Technology green steel spin-off Boston Metal, meanwhile, is inching toward its first commercial revenue.
Memoli said Tenova’s own research and development teams are working on similar technology. But he warned that it’s unlikely to be able to scale up fast enough in the near term to compete with DRI or blast furnaces.
A medium-sized blast furnace can churn out enough iron for 3 million tons of steel per year. A DRI plant can reach about 2.5 million tons. It’ll be decades before any of these newer electricity-based technologies reach that scale, Memoli said.
“The level of development of those technologies is still at a very early stage,” he said.
“We’re still talking about 20 years, 30 years from now. We need to be conscious of what are the targets and what are the deadlines today,” he added. “If we wait for something like that, the target of cleaning the planet will be pushed down and the cost of cleaning the planet will be much higher.”
Memoli said he wants to see more competition in the DRI space.
“Today there are only two companies – us and Midrex. Two is not enough,” Memoli said. “Not even four would be enough to develop all the projects that potentially could happen. Anybody with a green solution is welcome.”
Canary Media’s “Electrified Life” column shares real-world tales, tips, and insights to demystify what individuals and business owners can do to shift to clean electric power.
CENTENNIAL, Colo. — At a grassy city park this spring, professional landscapers sauntered between vendor booths, asking questions about the shiny new wares laid out before them: battery-powered push mowers, leaf blowers, string trimmers, chainsaws, and more. Some hopped on new standing and riding mowers to give them a spin.
Noticeably absent throughout it all was the scent and the roar of gas-guzzling equipment; the tools were all electric.
At the event hosted by the nonprofits Regional Air Quality Council and the Colorado Public Interest Research Group Foundation, landscapers were scoping out battery-powered tools to prepare for statewide regulations that kicked in this month. The first-of-their-kind rules, adopted in 2024, restrict the use of landscaping equipment with small gasoline-powered engines on public property during the summer — the state’s high-ozone season.
As you might guess from just a whiff of the noxious fumes, gas-fueled lawn and garden equipment are extremely polluting. Their combustion engines are a hazard not only to a stable climate, but also human health.
In 2020, nationwide, these machines belched over 68,000 tons of nitrogen oxides (NOx) and 350,000 tons of volatile organic compounds, according to the U.S. Public Interest Research Group Education Fund, referencing data from the U.S. Environmental Protection Agency. Together, the chemicals form lung-searing ozone, a key component of smog linked to respiratory problems and even premature death. The amount of NOx emitted by fossil-fueled lawn equipment is equivalent to the annual emissions from about 30 million cars, or more than a tenth of those registered in the country.
After personal vehicles and oil and gas operations, the third-largest source of ozone-causing pollutants in Colorado’s Front Range region is lawn and garden equipment, said David Sabados, spokesperson for the Denver-based Regional Air Quality Council, the lead air-quality planning agency for the area. These machines don’t have catalytic converters, he pointed out, so “they have an oversized footprint on our air-pollution problem.”
The Front Range, which includes Denver and Boulder, frequently exceeds federal air-quality standards for ozone — but it’s not alone.
Cities, counties, and states around the country are also pursuing cleaner air and quieter neighborhoods by limiting the use of gas-fired landscaping equipment, incentivizing electric options, or both. California has had a zero-emissions (i.e., electric) standard for newly manufactured leaf blowers, lawn mowers, and other small off-road engines sold in the state since 2024. Montgomery County, Maryland, banned the use of gas-powered leaf vacuums and blowers, effective July 1. And New York is considering a bill to deliver a financial boost to commercial landscapers who switch to electric tools.
Colorado’s new rules, called Regulation 29, don’t affect individual homeowners, but instead require landscapers who work on federal, state, municipal, and public school properties to use zero-emissions handheld tools and push mowers from June 1 through Aug. 31.
To keep grooming these grounds, contracted companies are replacing their gas gear with electric options as it wears out, which can happen in as little as three years.
Some landscapers say the switch has broad customer appeal. Certain clients prefer electric tools because they work from home and don’t want combustion equipment disrupting their calls. Others prize the environmental benefits.
“The community we serve is very Earth-conscious,” said Ed Johnson, division manager for landscape company Outdoor Craftsmen, which has transitioned two of its six maintenance crews to predominantly electric models. “There’s definitely been a desire” among customers, many in Boulder County, for landscapers to act as good stewards, he said.
Johnson added that it’s strategic to ease into electrification now rather than scramble to overhaul operations when stricter regulations come down in the future. This winter, the Colorado Air Quality Control Commission will weigh tighter restrictions on commercial landscapers working on private properties, The Denver Gazette recently reported.
Making the switch to electric equipment isn’t easy, though. Cost can be a barrier, a concern the industry raised when Regulation 29 passed last year.
“It’s a big investment for all the batteries,” said Brian Levins, manager at Designscapes Colorado, a landscape design, construction, and maintenance firm. “When you’re buying a battery, you’re basically prepaying gas for two years.” The company, which earned $45 million in revenue last year, has spent about $36,000 (after incentives) on handheld electric tools and charging gear for six of its 20 crews, he said.
Designscapes was able to take advantage of the 30% discount on electric lawn equipment that Colorado offers through participating retailers. Other landscaping firms have defrayed costs with grants from state and local agencies, such as Boulder County’s Partners for a Clean Environment program.
Another hurdle is figuring out how to keep the equipment charged.
Johnson has rigged up an equipment trailer with a portable power station from manufacturer Kress that can recharge batteries in as little as eight minutes. And Aurora, Colorado, landscaper Singing Hills has beefed up the electrical infrastructure at its home base to handle the added load from electrifying some of its equipment. That upgrade cost about $15,000, said Jake Leman, CEO of the 30-year-old company.
An added challenge to going electric is that gas versions are still more powerful for a couple types of equipment, like leaf blowers, Johnson of Outdoor Craftsmen said. But the electric tech “is coming along,” he noted. “It’s getting really, really close.”
Plus, electric landscaping equipment boasts a bevy of benefits. It’s safer for operators, who no longer have to breathe their tools’ fumes or go home with the stench clinging to their clothes. Leman has heard from some crew members that they enjoy being able to talk while operating an electric machine — uncomfortable to do over a firing engine — and they’ve praised the faster start up of electric tools compared with gas-powered options that require pulling a cord, he said.
The electric machines also require much less maintenance, Leman noted: “There’s not the filters and the belts and the fluids to change.” With savings on fuel and upkeep costs, Johnson estimated some of his larger equipment would pay back after 27 months of operation.
Some companies don’t have to deal with the challenging economics of replacing equipment. Jordan Champalou started his business, Electric Lawn Care, with primarily electric machines four years ago, when he was 19. “I enjoy not breathing in fumes all day,” he said.
He’s also able to save on energy costs and charge in between job sites using cheap renewable power from two solar panels he installed on the roof of the trailer in which he hauls his Stihl mowers, blowers, trimmers, and chainsaw. His leaf blowers are indeed less powerful than gas-fired versions, he said, but he’s found a solution: He slings two at once.
About a third of Champalou’s clients hire him because he uses electric tools, he said. “This year has been more than ever.”
Some commercial customers are now also breathing easier on landscaping days, says Levins of Designscapes. A few client buildings have ventilation systems that inhale air from close to the ground. With gas equipment, “we need to notify them before we go out there, because otherwise those fumes will get sucked into the air-intake [system] and distributed through the building,” he said.
Battery-powered zero-emissions tools don’t have that issue, Levins noted. “And those customers love that aspect of the electric equipment.”
As some state legislatures try to roll back clean energy measures, a successful policy for community solar in Minnesota has survived a political fight to end it.
Earlier this month, lawmakers ditched language from the state’s energy omnibus bill that would have terminated a successful state community-solar program in three years — and quashed the build-out of 500 megawatts of planned projects, according to advocates.
“I am absolutely thrilled that the community solar program will continue, [particularly] for the communities and individuals that will benefit from it,” said Keiko Miller, director of the community solar program at advocacy group Minneapolis Climate Action. “This really is a way of reducing household energy burden for those who have been left out [of the energy transition] traditionally, as well as increasing the availability of renewable energy resources.”
Minnesota’s Community Solar Garden program is crucial as the state aims to decarbonize its power system by 2040, Miller said. “There is absolutely no way we can get there without community solar being part of the portfolio.”
Community solar projects, which are typically up to 5 megawatts, make it easier for households to tap into the value of solar. Customers who might not be able to install photovoltaic panels on their own roofs, including renters and low-income families, can sign up for a shared solar project sited elsewhere, like on a community center’s roof or in a farmer’s field. Also known as community solar gardens or farms, they can guarantee subscribers a discount on electricity costs.
Minnesota was an early leader in the shared-solar approach, having started the state program in 2013. Last year, the North Star State ranked fourth in the nation for installed capacity with 939 megawatts, according to the National Renewable Energy Laboratory. That’s almost one-third of the state’s total solar capacity of 2.9 gigawatts.
The state revamped its solar garden initiative in 2023 to ensure that more households and lower-income customers would benefit from community solar projects. Lawmakers didn’t assign the initiative an expiration date at the time.
In late March, two Democrats and one Republican introduced Senate File 2855, a bill that would’ve sunset the community solar program in 2028. Senators then rolled the plan into their version of the energy bill.
Minnesota-based utility Xcel Energy supported terminating the program; in a March 26 hearing, a company representative criticized community solar as a costly way to deploy clean energy compared to utility-scale installations. Notably, companies other than utilities can develop community solar projects, and Xcel Energy doesn’t earn a profit on energy infrastructure it doesn’t own.
But the utility and other opponents aren’t accounting for community solar’s wide-ranging benefits, such as avoided transmission costs, the reduction in peak demand on the grid, and resilience, said Patty O’Keefe, Midwest regional director of national nonprofit Vote Solar.
In 2024, the Minnesota Department of Commerce, which oversees the state program, found that it’s expected to deliver $2.9 billion in net benefits over the next four decades. While the initiative is projected to increase bills by 2% to 3% for non-subscribers who aren’t considered low to moderate income, community solar is expected to lower energy bills for participating households by 3% to 8%.
Ultimately, lawmakers stripped the repeal language from the energy bill following pushback from community solar champions in the Legislature, including Democrats Rep. Patty Acomb, Senate Majority Leader Erin Murphy, and Rep. Melissa Hortman, O’Keefe said. (On June 14, Hortman and her husband were assassinated at their home in an act of politically motivated violence.)
Droves of supporters also helped save the state solar-garden program; they testified at hearings, marched, and protested, O’Keefe said. By her count, roughly 100 Minnesotans, including community solar subscribers, farmers, and clean energy advocates, called on legislators to reject the repeal.
The win for community solar in Minnesota comes as the broader solar industry — and the already-struggling rooftop solar sector in particular — faces serious federal headwinds. The Trump administration’s rapidly fluctuating tariffs and the looming repeal of solar and wind energy tax credits in the budget bill threaten to make solar more expensive to build. That could throw cold water on the record-breaking pace of solar deployment the U.S. has experienced in recent years.
But in Minnesota, at least, a major source of clean energy endures.
“This is a victory for the community solar movement,” O’Keefe said. “It just shows that even with a … forceful effort to try and repeal the entire program, we had enough power between the public and clean-energy champions to fight it back — and really send a message that Minnesota benefits from community solar.”
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
The Senate Finance Committee released its portion of the “Big, Beautiful Bill” on Monday, including highly anticipated plans for clean energy tax credits that the House’s version sought to repeal. Here’s what’s better off in the Senate text — which still could change — and what’s not looking so hot.
Solar and wind — sort of
The House version would require clean power projects to start construction within 60 days of the bill’s passage to access production and investment tax credits introduced under the Inflation Reduction Act. The Senate proposes a more gradual phaseout of credits for solar and wind projects before they terminate entirely at the end of 2027. Certain wind and solar projects would be able to access the tax credits beyond that point, as long as they are at least 1 gigawatt, are on federal land, and have already earned right-of-way approval from the Bureau of Land Management. But as Heatmap notes, those exceptions are unlikely to help any projects already in development.
Utility-scale battery storage
Incentives for energy storage projects would’ve ended just like those for wind and solar under the House bill, but that’s changed in this version. The Senate specifically says battery storage projects can access those production and investment tax credits until 2036, though the value of the incentives will taper over the years.
Geothermal, hydropower, and nuclear
Nuclear power was notably spared in the House’s gutting of clean energy incentives, but it got a few new friends in the Senate iteration. Like battery storage and advanced nuclear, geothermal and hydropower projects will be able to tap 45Y production tax credits until 2036.
EVs
The $7,500 tax credit for new EV purchases would end about six months after the legislation is signed, while the $4,000 incentive for used EV purchases would end in three. The House extended that rebate for new EVs through 2026 for some emerging automakers, but the Senate didn’t carry over that same exemption.
Home energy improvements
Homeowners would only be able to get tax credits for rooftop solar installations for 180 days after the bill’s passage. Rebates for home energy upgrades, including to help homeowners buy electric heat pumps and other efficient appliances, will also be phased out in 180 days.
Hydrogen
The IRA’s green hydrogen production credit will only be available to projects that start construction this year, and after that, would end immediately. That cut would be brutal for the already-struggling industry, Canary Media’s Julian Spector reports.
While the Senate’s proposal steps back some from the House version, tax credits that directly benefit consumers remain the most at risk. And as many experts have warned, those slashed tax credits will put jobs, energy bill savings, and major clean power projects at risk.
Still, these changes aren’t set in stone. Once the whole bill is drafted, the Senate will have to actually pass it, and then reconcile its differences with the House, with an ultimate goal of getting the package on President Donald Trump’s desk by July 4. His signature would start the clock ticking on all those tax credit phaseouts.
A wave of community solar wins
The skies are cloudy for clean energy, but community solar is still providing some bright spots.
In Delaware, power will soon begin flowing from a 4.7-megawatt array that will help power as many as 750 homes and small businesses. It’s the first of six projects planned across the state to help locals — especially renters and low-income residents — tap into cleaner power, WHYY reports.
More community solar is on the way in the Northeast. A developer broke ground this week on a 3-MW array in Glastonbury, Connecticut, that’s part of a raft of projects across the region. And in New Jersey, lawmakers advanced a bill that would expand the state’s community solar capacity by 50% in an attempt to help curb power bills.
Meanwhile in Minnesota, the preservation of a community solar program will stand as a piece of state Rep. Melissa Hortman’s lasting legacy on clean energy. Hortman, a Democrat who was assassinated in her home last weekend, played a pivotal role in passing the state’s clean electricity standard and updating a community solar program in 2023. More recently, she pushed to keep the repeal of that program out of the state’s energy omnibus bill passed earlier this month.
Renewables still win: Renewable electricity is cheaper than power produced by fossil fuels, even without government subsidies, though low gas costs and rising prices for renewables threaten the clean energy buildout, an investment bank’s annual report finds. (E&E News)
Energy research deep freeze: Federal employees say Trump administration funding cuts and freezes are making it impossible for EPA scientists to publish research, for Energy Department employees to visit the agency’s labs, and for other energy and environmental staffers to conduct critical work. (Politico)
Fossil fuels financed: The world’s largest banks increased financing for fossil fuel projects between 2023 and 2024 despite their climate commitments, reversing several years of shrinking financial support for coal, gas, and oil projects. (The Guardian)
Another blow to wind: Anti-wind activists say they’re looking to build on the implosion of a Maine floating offshore wind project as they push the Trump administration to revoke a grant for a similar project in Northern California. (Canary Media)
Pricing out gas: Maryland residents who want new gas service will now have to pay for the connection, as public utilities regulators decide the old system of free or reduced-price hookups is at odds with the state’s climate goals. (Baltimore Sun)
Nuclear goes nationwide: State lawmakers across the U.S. have filed more than 200 bills related to nuclear energy this year, with dozens going into law as states look to meet rising power demand. (E&E News)
Senate Republicans released a draft budget on Monday that presents a slightly less draconian prescription for clean energy tax credits than what the House had put forth.
In May, House Republicans voted to slash all the clean power credits, with some favorable treatment for nuclear plants. The Senate took a more nuanced approach, doing away with credits for cheap but intermittent resources, while continuing to incentivize projects that can generate power on demand.
The Senate version would crank down investment and production tax credits for wind and solar power starting in 2026, reducing them to zero by 2028. But the Senate Finance Committee threw a lifeline to other zero-carbon power plants, allowing hydropower, geothermal, and nuclear to keep their full credits until 2033. Crucially, energy storage was included in that group, which could help grid batteries keep their meteoric growth streak going.
This effort to continue supporting “firm” power sources, which provide energy even when the sun isn’t shining and the wind isn’t blowing, could be hugely consequential for America’s ability to meet spiking demand for electricity. Companies are racing to build new power plants to serve AI computing and domestic manufacturing (two avowed priorities of the Trump administration), not to mention the widespread electrification needed to address climate change.
The problem is, nuclear construction has stagnated since the woefully delayed and over-budget Vogtle expansion; hydropower has been essentially frozen for decades; and geothermal is just starting to gain traction thanks to a handful of startups developing new technologies.
Of the Senate’s chosen few, batteries are the only contender showing real dynamism in energy markets: In just a few years, they’ve jumped from the margins to become the second-biggest source of new power capacity added to the U.S. grid each year, after solar. Energy storage dominates the queues of projects waiting to hook up to the grid in the next few years in places like California and Texas.
The Senate still needs to debate this proposal and see if it rallies enough votes to pass. Then the Senate and House will have to reconcile their differences. There’s no way to know if the current Senate language will become the law of the land.
Nonetheless, this proposal changes the political landscape for clean energy advocates, by splitting clean energy into winners and losers. It also tacks on requirements around foreign influence that seem conceptually more workable than the House’s “poison pill” approach, but that could still thwart actual construction.
The idea of excluding wind and solar from receiving credits has been percolating over the last few months, though it was easy to miss in a generally turbulent news cycle. In April, U.S. Rep. Julie Fedorchak, a Republican from North Dakota, introduced a bill that she dubbed the “Ending Intermittent Energy Subsidies Act.”
“Wind and solar are no longer emerging technologies—they’re mature, market-proven, and widely deployed,” Fedorchak said in a statement at the time. “As all the grid operators are saying, we need more dispatchable resources. We must stop providing generous incentives that run contrary to that.”
The legislation didn’t get much attention at the time, and Fedorchak’s House colleagues yanked support from several of the dispatchable options anyway. But she had some historical facts on her side: Wind and solar have enjoyed federal tax structures since the George W. Bush era (incentives for wind actually go back further), when they emerged as a broadly supported Republican energy policy. Storage didn’t get its own tax credit until the Inflation Reduction Act kicked in for 2023. The technology is clearly the newest of the major power-sector players (excluding the nonexistent nuclear fusion and small modular reactor projects).
On June 3, a cohort of clean, dispatchable power providers chimed in on the debate with a letter noting that they can offer exactly the kind of on-demand power Republican senators seem to appreciate.
“Nuclear energy, geothermal, hydropower, and energy storage stand ready to deliver that reliable power,” said the group, which included novel storage startups Form Energy and Hydrostor, along with geothermal, nuclear, and hydro firms. “We believe it is possible to advance genuine deficit reduction without sacrificing the reliable, innovative power that American households, businesses, and national security require.”
They never said to throw wind and solar under the bus, but emphasized the particular value in keeping credits for dispatchable resources as senators decided where to cut spending.
The House, besides greatly shrinking the timeline for clean energy tax credits, tacked on new requirements that industry insiders decried as impossible to fulfill. The language would block incentives for projects that include any components from a “prohibited foreign entity,” legislative jargon which basically means companies in China. The state of globalized supply chains makes it effectively impossible to build a power plant with that constraint.
The Senate shares the concern about tax credits accruing to Chinese companies, but handled it differently. In its version, the company filing for tax credits cannot be literally or effectively controlled by prohibited foreign entities — that’s a test that U.S.-based developers should, in theory, have no trouble passing. But the text gets very specific on what kinds of arrangements could constitute “effective control” of a project, and calls for the Treasury secretary to issue guidance on how to qualify. That creates ample opportunities for U.S.-controlled storage companies that fulfill the spirit of the law to run afoul of certain sub-clauses.
Additionally, developers must spend a certain amount of the total project cost on products that are not from “foreign entities of concern.” The ratio starts at 40% in 2026, and increases annually from there. Lithium-ion batteries still largely come from China; if a project has to buy those, but can secure the remaining equipment for the power plant from the U.S., they may be able to hit the right ratio. On paper, this rule seems more achievable than the House version, which would penalize firms that use even small, low-value pieces like bolts or cables that originate from China, rather than focusing on critical, high-value components.
Of course, tax credit compliance is the province of well-paid lawyers, who would need to translate the details of the Senate language into actionable legal guidance for companies. The clean energy industry is still reeling from yearslong rulemakings at the Internal Revenue Service that held back many of the investments championed by the Biden administration. Today, the Trump administration has winnowed civil service staff and actively opposed clean energy; it’s hard to imagine IRS rulemaking moving more swiftly under those circumstances.
Storage developers are frantically running the numbers on whether their power plant designs can stay within the guidelines for foreign components, so that they’ll qualify for the tax credits. They also need their financiers to feel confident that they will. Highly prescriptive legislative interference in a high-tech business landscape complicates that process, and could cause investors to pull back until the dust clears.
That’s not to say battery construction will come to a halt without workable incentives. It’s arguably the only dispatchable technology that can be built quickly in the next few years. But saddling the credits with additional bureaucratic requirements would inject extra costs and delays into the industry, at a time when the U.S. desperately needs all the on-demand power it can get.
.svg)
