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A year after Hurricane Helene hit western North Carolina — dumping as much as 30 inches of rain and felling thousands of trees — countless homes still suffer from leaky roofs, mold and mildew, and rotting floors.
All that damage doesn’t just threaten residents’ comfort, health, and safety. Unless it’s resolved, low-income households can’t access free energy-efficiency retrofits that could save them hundreds of dollars each year on their utility bills.
Now, North Carolina plans to solve that problem by allocating $10 million to urgent home repair in the region. Officials in the administration of Gov. Josh Stein, a Democrat, hope the funds will aid more than 575 households in the counties most devastated by Helene.
“This effort is going to increase western North Carolina’s sound and efficient housing stock, reduce energy costs for the most vulnerable families and individuals, and make homes safer and more comfortable,” Julie Woosley, director of the State Energy Office, said in a statement.
Drawing on a disaster-relief package passed by lawmakers in the early aftermath of Helene, the home-repair monies will be distributed to a regional government entity and nine community action agencies that implement the federal Weatherization Assistance Program.
Established nearly a half century ago, the weatherization initiative is aimed at families below certain annual income thresholds; for example, a family of four must earn about $60,000 or less to qualify. The program’s services — including sealing leaks around doors and windows, adding insulation, and improving appliance efficiency — benefit hundreds of North Carolina households each year, lowering their utility bills by up to $300.
But the Weatherization Assistance Program only scratches the surface of need for the energy burdened. Because its funds are restricted to minor repairs and mostly can’t be used for major ones such as roof replacement, about one in five families nationwide are deferred from receiving benefits, according to a survey by the nonprofit American Council for an Energy-Efficient Economy. Of those, 40% never get weatherized at all.
That’s why the newly announced money for western North Carolina households is so vital, said Claire Williamson, energy policy advocate at the North Carolina Justice Center: It will unlock assistance for households that have previously been unable to access weatherization aid.
“It’s not only helping families recovering from Hurricane Helene,” Williamson said, “but also helping these families not be burdened by rising energy costs.”
To be sure, there are several existing efforts to bridge the gap for households that need energy-efficiency retrofits as well as major repairs. Some municipalities have their own fix-it programs, Williamson said, as does the North Carolina Housing Finance Agency.
For Duke Energy customers, Williamson’s group helped win $16 million for urgent home fixes financed by shareholders. But the predominant utility doesn’t serve the state’s farthest-flung counties, including some heavily hit by Helene.
“It’s fantastic that pre-weatherization dollars can be used for people who are members of electric cooperatives,” she said. “Otherwise, these households are getting left behind.”
The $10 million announcement from the State Energy Office comes at a crucial time for weatherization efforts statewide. In 2021, the program got a $90 million boost from the federal bipartisan infrastructure law — funding not yet swept up in the Trump administration’s assault on clean energy and energy efficiency.
After months of planning, the Stein administration says those funds will be deployed starting in January and spent by the end of the decade, with hopes of serving around 2,000 households annually. The plan includes up to $12.6 million for major health and safety repairs.
“It’s such a great sign that the state is dedicating funds to this issue,” Williamson said. “When homes are more efficient, it helps benefit the rest of North Carolina,” she added. “They’re lowering energy use and lowering their impact on the grid.”
Microsoft says it will get green steel from a first-of-a-kind facility in northern Sweden as the tech giant looks to curb the climate impact of its data center build-out.
This week, Microsoft announced a two-part deal with Stegra (formerly H2 Green Steel), which is building a multibillion-dollar plant set to be completed in late 2026. Instead of relying on traditional coal-based methods, the Swedish project will produce steel using green hydrogen — made from renewable energy sources — and clean electricity.
The first part of Microsoft’s agreement involves actual coils of steel. Because the company doesn’t directly buy construction materials itself, Microsoft has agreed to work with its equipment suppliers to ensure that Stegra’s green steel is used in some of its data center projects in Europe.
The second part of the deal enables Microsoft to claim green credentials for the infrastructure it builds outside of Europe, where Stegra isn’t planning to operate. Under this scheme, Stegra will sell its “near-zero emission” steel into the European market — except that the metal will be sold as if it had an industry-average carbon footprint and without a price premium. Microsoft will then buy “environmental attribute certificates” that represent the emissions reductions provided by Stegra’s product, helping to cover the extra cost of making green steel.
With the certificates, “We aim to signal demand, enable project financing, and accelerate global production,” Melanie Nakagawa, Microsoft’s chief sustainability officer, said in a Sept. 23 press release. Ultimately, she said, “The end game is to source physical materials with the lowest possible CO₂ footprint. Achieving this requires greater volumes of low-carbon steel available in more regions.”
The world produces roughly 2 billion metric tons of steel every year, most of which is made using dirty coal-fueled furnaces. As a result, the industry is responsible for between 7% and 9% of total global carbon emissions.
Microsoft and Stegra didn’t provide details about the financial value or volumes of steel tied to their deal. Johan M. Reunanen, who leads Stegra’s climate impact work, said only that its contract with Microsoft is neither the biggest nor the smallest offtake agreement that the steelmaker has signed since launching in 2021.
“But it’s very strategic for us,” Reunanen told Canary Media during a visit to New York for Climate Week NYC. “It gives Stegra access to a customer that is in data centers, which is a market that we’ll be developing.”
Stegra isn’t the only Swedish steelmaker chasing Big Tech. Last year, the manufacturer SSAB signed an agreement with Amazon Web Services to supply hydrogen-based steel for one of Amazon’s three new data centers in Sweden. SSAB operates the Hybrit pilot plant in Luleå — the world’s first steelmaking facility to use hydrogen at any meaningful scale, though the Stegra project will be the first large-scale plant to use this approach once completed.
Microsoft’s agreement with Stegra arrives at a tenuous time for developers of green hydrogen.
More than a dozen hydrogen projects have been canceled, postponed, or scaled back in recent months owing to soaring production costs and waning demand for the low-carbon and highly expensive fuel, Reuters reported in late July. That includes ArcelorMittal’s hydrogen-based steelmaking initiative in Germany, which the company shelved in June, as well as U.S. green steel projects formerly planned in Ohio and Mississippi.
Stegra, for its part, is seeking to raise additional cash to complete its flagship project in Boden, Sweden, after a government agency denied the company 165 million euros ($193 million) in previously approved grant funding. The Swedish Environmental Protection Agency reportedly objected to the fact that the steel mill will use some fossil gas during a heat-treatment process — though Stegra claims the project could still cut emissions by up to 95% compared to coal-based steelmaking.
Stegra has already secured 6.5 billion euros ($7.6 billion) from private investors for the project, which broke ground in 2022. The company is installing 740 megawatts’ worth of electrolyzers to convert electricity from the region’s hydropower plants and wind farms into hydrogen gas. The hydrogen will be used in the “direct reduction” process to convert iron ore into iron, which will then be transformed into steel using electric arc furnaces.
The sprawling facility, located just south of the Arctic Circle, is expected to produce 2.5 million metric tons of steel by 2028, before ramping up to make 5 million metric tons by 2030. Reunanen said that more than half of the steel produced during the first phase is already covered by offtake contracts with automakers like Mercedes-Benz, Porsche, and Scania, as well major companies including Cargill, Ikea, and now Microsoft.
The tech firm — which previously invested in Stegra through its $1 billion Climate Innovation Fund — is the first company to commit to buying environmental attribute certificates from a steel facility. Microsoft has struck similar deals to help drum up demand for lower-carbon versions of other industrial materials, including with cement startup Fortera and alternative-jet-fuel producers like World Energy.
RMI, a think tank focused on clean energy, said it helped advise Stegra and Microsoft on their deal, and both companies are part of an RMI initiative that’s working to design tools that track, validate, and account for certificates.
“Agreements like this one signal a wider demand pool for lower-carbon steel, expanding the offtake beyond conventional direct steel purchasers and into sectors where steel is a critical yet buried part of the supply chain,” said Claire Dougherty, a senior associate at RMI. She added that the deal “serves as a proof-of-concept for the role that [certificates] can play in getting first-of-a-kind, near-zero steel projects off the ground.”
01 Electricity demand saw the third-largest absolute increase ever in 2024
02 China’s per capita electricity use overtook France’s for the first time in 2024, and was five times that of India’s
03 A fifth of the demand increase in 2024 was due to the impacts of hotter temperatures compared to 2023
Global electricity demand increased by 4% (+1,172 TWh) in 2024. This was the third-largest absolute increase in electricity demand ever, only surpassed by rebounds in demand in 2010 from the global recession and in 2021 from the Covid-19 pandemic. This increase is significantly above the average annual demand growth of 2.5% in the previous ten years (2014-2023).
Global electricity demand rose to 30,856 TWh, crossing 30,000 TWh for the first time. Since the turn of the century, electricity demand has doubled.
Some of the exceptional growth in 2024 was due to weather conditions. As explored in chapter 1, we calculate that hotter temperatures added 0.7% to global demand in 2024. Nonetheless, emerging drivers of electricity demand such as electric vehicles (EVs), data centres and heat pumps also added 0.7% to global demand growth in 2024 (+195 TWh), a slight step up from the 0.6% they added in 2023 (+174 TWh). See more in chapter 2.2.
China recorded the largest increase in electricity demand, adding 623 TWh (+6.6%), which accounted for more than half of the global increase. The US saw a rise of 128 TWh (+3%). India’s demand increased by 98 TWh (+5%). As recent Ember analysis shows, all three countries experienced heatwaves that drove up electricity demand beyond increases due to economic activity.
Other countries with substantial increases were Brazil (+35 TWh, +4.9%), Russia (+32 TWh, +2.8%), Viet Nam (+26 TWh, +9.5%) and Türkiye (+18 TWh, +5.6%).
China’s share of global electricity demand has increased due to its continued demand growth above the world average. With 10,066 TWh, China’s electricity demand contributed roughly a third (32.6%) of the global total, up from 28% five years ago.
China’s global share of demand was more than double that of the US at 4,401 TWh (14.3% of the global total). The EU made up 8.8% (2,727 TWh) of global electricity demand. India’s electricity demand reached 2,054 TWh (6.7% of global demand).
26% of global electricity demand comes from economies that each contribute less than 2%.
Among the top ten electricity consumers, the difference in per capita consumption remained vast. Canada had the highest per capita demand for electricity at 15.5 megawatt hours (MWh). This was more than 10 times higher than India, which places last among this group at 1.4 MWh.
China’s per capita demand (7.1 MWh) was almost double the world average of 3.8 MWh, overtaking France in 2024 and Germany in 2023.
Asia’s electricity demand has grown fourfold since the turn of the century from 4,199 TWh in 2000 to 16,153 TWh in 2024 (+285%), driven by demand increases in China, and increasingly India, Indonesia, Viet Nam and other fast-growing economies.
This trend was not replicated elsewhere. Demand outside Asia grew by just 3,624 TWh (+33%) over the same period, from 11,079 TWh to 14,703 TWh.
Despite moderate increases in the past decade, the entire continent of Africa accounted for just 3.1% of total global electricity demand in 2024, less than Japan.
01 Low-carbon sources surpassed 40% of global electricity generation, driven by record renewables growth
02 Global solar generation has doubled in three years, continuing its pattern of exponential growth
03 Wind and solar have met more than half of global growth in electricity demand since 2015
In 2024, low-carbon power sources rose to 40.9% of global electricity generation, the highest level since the 1940s when hydro generation alone met over 40%.
Solar and wind power are the fastest-growing sources of electricity. Combined, they accounted for 15% of global electricity in 2024, with solar contributing 6.9% and wind 8.1%. The two sources combined now produce more electricity than hydropower at 14.3%. They already surpassed nuclear generation in 2021, which continues to reduce in share (9% in 2024). The rise in wind and solar power over recent years has been remarkable, with solar in particular maintaining rapid growth rates despite reaching high levels of absolute generation. Solar power has doubled in the three years since 2021, continuing its pattern of exponential growth.
The share of fossil sources declined to 59.1% in 2024, despite increases in absolute generation. It has declined substantially since the peak of 68.3% in 2007 and is set to fall further in the coming years as renewable generation growth continues to accelerate. The share of coal generation has fallen significantly, from 40.8% in 2007 to 34.4% in 2024, with more consistent falls in the last 10 years. The share of gas generation has fallen for four consecutive years since it peaked in 2020 at 23.9%, reaching 22% in 2024.
Clean generation met 79% of the increase in global electricity demand in 2024. Electricity generation from clean sources grew by 927 TWh (+7.9%), the largest increase ever recorded. The clean generation increase in 2024 would have been large enough to meet the rise in electricity demand in all but three years in the last two decades.
However, heatwaves in 2024 elevated cooling demand, which was the main driver of a small 1.4% increase in fossil generation (+245 TWh), similar to the rise in the previous two years. Without the impact of hotter temperatures, fossil generation would have remained flat.
Renewables growth alone met 73% of the increase in electricity demand. In total, renewable power sources added a record 858 TWh of generation in 2024, 49% more than the previous record set in 2022 of 577 TWh.
Solar dominated the growth in electricity generation as it was the largest source of new electricity for the third year in a row. Solar added 474 TWh (+29%) in 2024. Solar’s increase alone met 40% of global electricity demand growth in 2024. Wind growth remained more moderate (+182 TWh, +7.9%), with lower wind speeds in some geographies leading to the lowest increase in wind generation in four years despite continued capacity additions. Hydro generation rebounded in 2024 (+182 TWh) as drought conditions in 2023 eased, particularly in China.
Nuclear generation increased by 69 TWh (+2.5%), mostly as a result of less downtime for reactors in France as well as small increases from new reactors in China.
The global increase in fossil generation came mostly from coal which rose by 149 TWh (+1.4%). Gas generation increased by 103 TWh (+1.6%). Other fossil fuels saw a minor fall of 7.7 TWh (-0.9%).
China and India saw the largest increases in coal generation in 2024, together totalling more than the global net increase. The gas generation growth in the US alone (+59 TWh, +3.3%) was equivalent to 57% of the global increase. Gas generation in the US is rising mainly as a result of coal-to-gas switching. Ember’s analysis shows that heatwaves also played a role in raising fossil generation in China, India and the US in 2024.
Since 2015, solar and wind have been the two largest-growing sources of electricity, meeting more than half (52%) of global demand growth. Solar generation has grown eightfold since 2015, from 256 TWh in 2015 to 2,131 TWh in 2024. Wind generation tripled from 830 TWh in 2015 to 2,494 TWh in 2024.
China has dominated changes in the global electricity system since 2015, recording the largest increases of any country for solar, wind, hydro, nuclear and coal. China accounts for 45% of global growth in wind and solar generation since 2015. At the same time, global coal generation would have fallen since 2015 without the increase in China.
India saw the second-largest increase in coal generation behind China. India’s rise in coal generation was equivalent to 40% of the global increase in coal since 2015.
The US was responsible for 43% of the global increase in gas generation since 2015. Its gas generation increased by 40% (+531 TWh) over the same period.
01 Power sector emissions hit a new record high as heatwaves drove a small rise in fossil generation
02 Carbon intensity fell by 15% since its peak in 2007, driven by clean generation growing faster than fossil generation
03 Africa and Latin America each make up less than 4% of global power sector emissions, despite representing 19% and 8% of the global population respectively
Global power sector emissions reached a new record high in 2024, rising by 1.6% or 223 million tonnes of CO2 (MtCO2), compared to 2023. This increase was similar to 2023 (+1.5%) and 2022 (+1.3%) and was driven by an increase in fossil generation, predominantly from coal. However, without the impact of 2024’s heatwaves, fossil generation would only have risen by 0.2% from 2023, and power sector emissions would have remained almost unchanged (see Chapter 1).
Despite the overall increase in power sector emissions, the emissions intensity (emissions per unit of electricity produced) of global power generation continued to decrease. Emissions intensity dropped by 2.3% to 473 grams of CO2 per kilowatt hour (gCO2/kWh), down from 484 gCO2/kWh in 2023. Emissions intensity has now fallen in nine of the last ten years, with the only increase occurring in 2021 as fossil generation rebounded following large falls in demand during the Covid-19 pandemic.
The decline in emissions intensity is driven by the growing share of clean power in the mix, which reached 40.9% in 2024. As of 2024, the emissions intensity of the global power sector has fallen by 15% since the peak of 555 gCO2/kWh in 2007.
China’s size and reliance on coal generation kept it as the world’s highest power sector emitter in 2024, with emissions reaching 5,640 MtCO2, four times those of the US and India.
Emissions from power generation in the US amounted to 1,683 MtCO2, accounting for 11.5% of the global total. India’s power sector emissions reached 1,457 MtCO2, now close to matching the US and reaching 10% of global power sector emissions for the first time.
China accounted for 38.6% of global power sector emissions – more than the US, India, the EU, Russia and Japan combined. Countries individually producing less than 2% of global power sector emissions made up the remaining 28.8% of the global total.
India and China had the highest emissions intensity of electricity production among the top ten electricity consumers. India’s emissions intensity remained particularly high at 708 gCO2/kWh, compared to the global average of 473 gCO2/kWh. However, India’s emissions intensity has been falling as clean generation has been growing faster than coal.
Canada, Brazil and France had the lowest emissions intensity due to their high shares of low-carbon generation from hydro and nuclear, along with a growing share of wind and solar.
Despite this, Canada’s emissions per capita (2.8 tCO2) were nearly three times larger than India’s (1 tCO2), driven by substantially higher per capita demand for electricity.
South Korea (5 tCO2) and the US (4.9 tCO2) had the highest power sector emissions per capita among the ten biggest electricity consumers due to a combination of high per capita electricity demand and a high share of fossil generation in the mix. China’s emissions per capita have risen to match Japan’s at 4 tCO2.
Driven by rapidly growing electricity demand in Asian economies, Asia’s share of global power sector emissions has surged over the last two decades. In 2000, Asia made up a third (33%) of global power sector emissions. In 2024, this had risen to nearly two-thirds (63%).
Power sector emissions in North America and Europe have both fallen by a third since peaking in 2007. Within Europe, EU power sector emissions have halved (-52%) since 2007, whilst emissions in Russia and Türkiye have risen. In the Middle East, emissions have risen more sharply, driven by growing electricity demand in large markets such as Saudi Arabia and Iran, where fossil fuels dominate the electricity mix.
In 2024, African countries still only made up 3.6% of global power sector emissions, despite accounting for 19% of the world’s population. Similarly, Latin America and the Caribbean contributed just 3.2% of global power sector emissions while representing 8% of the global population.
August 28, 2025 – Today, Climate TRACE reported that total global emissions in the first half of 2025 are 30.99 billion tonnes CO₂e. This is 0.13% higher than emissions were in the first half of 2024. Global greenhouse gas emissions for the month of June 2025 totaled 5.12 billion tonnes CO₂e. This represents an increase of 0.29% vs. June 2024. Global methane emissions in June 2025 were 34.82 million tonnes CH₄, an increase of 0.49% vs. June 2024.
Data tables summarizing emissions totals for June 2025 by sector, country, and top 100 urban areas are available for download here.
Lookback: Global Greenhouse Gas Emissions for the First Half of 2025
In the first half of 2025, the sector driving the most growth in emissions was fossil fuel operations, where emissions rose by 1.5% (an increase of 77.65 million tonnes of CO₂e). The United States accounted for more than half of that increase. Manufacturing emissions also rose in the first half of 2025, growing by 0.3% (an increase of 18.75 million tonnes of CO₂e), led by increases in India, Vietnam, Indonesia, and Brazil.
Meanwhile, global power sector emissions saw the biggest decline in the first half of 2025, falling by 0.8% (a decrease of 60.27 million tonnes of CO₂e), driven almost entirely by declines in China and India, where power emissions were 1.7% lower and 0.8% lower than their totals in the first half of 2024, respectively.
The first half of 2025 shows small but positive progress on decarbonization in China, Mexico, and Australia. China’s emissions decreased 45.37 million tonnes CO₂e, or 0.51% compared to the first half of 2024. Mexico’s emissions decreased 7.78 million tonnes CO₂e, or 1.71% compared to the first half of 2024. Australia’s emissions decreased 6.56 million tonnes CO₂e, or 1.51% compared to the first half of 2024. However, some of the world’s other major emitting economies, including the United States, India, the EU, Indonesia, and Brazil, saw emissions rise in the first half of 2025.
– United States emissions increased by 48.57 million tonnes CO₂e, or 1.43% compared to the first half of 2024;
– India emissions increased by 4.44 million tonnes CO₂e, or 0.21% compared to the first half of 2024;
– European Union emissions increased by 2.90 million tonnes CO₂e, or 0.15% compared to the first half of 2024.
– Indonesia emissions increased by 3.06 million tonnes CO₂e, or 0.39% compared to the first half of 2024;
– Brazil emissions increased by 9.84 million tonnes CO₂e, or 1.24% compared to the first half of 2024.
Greenhouse Gas Emissions by Country: June 2025
Climate TRACE’s preliminary estimate of June 2025 emissions in China, the world’s top emitting country, is 1.46 billion tonnes CO₂e — an increase of 0.92 million tonnes of CO₂e or 0.06% vs. June 2024.
Of the other top five emitting countries:
– United States emissions increased by 4.89 million tonnes CO₂e, or 0.86% year over year;
– India emissions declined by 0.11 million tonnes CO₂e, or 0.03% year over year;
– Russia emissions increased by 0.95 million tonnes CO₂e, or 0.38% year over year;
– Indonesia emissions increased by 0.43 million tonnes CO₂e, or 0.33% year over year.
In the EU, which as a bloc would be the fourth largest source of emissions in June 2025, emissions declined by 1.80 million tonnes CO₂e compared to June 2024, or 0.58%.
Greenhouse Gas Emissions by Sector: June 2025
Greenhouse gas emissions increased in June 2025 vs. June 2024 in fossil fuel operations, manufacturing, transportation, and waste, and decreased in power. Fossil fuel operations saw the greatest change in emissions year over year, with emissions increasing by 1.85% as compared to June 2024.
– Agriculture emissions were 641.40 million tonnes CO₂e, unchanged vs. June 2024;
– Buildings emissions were 285.59 million tonnes CO₂e, unchanged vs. June 2024;
– Fluorinated gases emissions were 137.71 million tonnes CO₂e, unchanged vs. June 2024;
– Fossil fuel operations emissions were 846.19 million tonnes CO₂e, a 1.85% increase vs. June 2024;
– Manufacturing emissions were 929.05 million tonnes CO₂e, a 0.02% increase vs. June 2024;
– Mineral extraction emissions were 23.22 million tonnes CO₂e, unchanged vs. June 2024;
– Power emissions were 1,297.34 million tonnes CO₂e, a 0.56% decrease vs. June 2024;
– Transportation emissions were 759.10 million tonnes CO₂e, a 0.77% increase vs. June 2024;
– Waste emissions were 197.77 million tonnes CO₂e, a 0.26% increase vs. June 2024.
Greenhouse Gas Emissions by City: June 2025
The urban areas with the highest total greenhouse gas emissions in June 2025 were Shanghai, China; Tokyo, Japan; New York, United States; Houston, United States; and Los Angeles, United States.
The urban areas with the greatest increase in absolute emissions in June 2025 as compared to June 2024 were Pittsburgh, United States; Xinyu, China; Tokyo, Japan; Baotou, China; and Algeciras, Spain. Those with the largest absolute emissions decline between this June and last June were Leipzig, Germany; Anqing, China; Duren, Germany; Houston, United States; and Anchorage, United States.
The urban areas with the greatest increase in emissions as a percentage of their total emissions were Kombissiri, Burkina Faso; Gambat, Pakistan; Bitilta Zebraro, Ethiopia; UNNAMED, Sudan; and Oviedo, Spain. Those with the greatest decrease by percentage were Leipzig, Germany; Duren, Germany; Wolfsburg, Germany; Atebubu, Ghana; and Evansville, United States.
RELEASE NOTES
Revisions to existing Climate TRACE data are common and expected. They allow us to take the most up-to-date and accurate information into account. As new information becomes available, Climate TRACE will update its emissions totals (potentially including historical estimates) to reflect new data inputs, methodologies, and revisions.
With the addition of June 2025 data, the Climate TRACE database is now updated to version V4.6.0. This release incorporates the most recent FAOSTAT and CEDS data in applicable sectors. The release also reflects updated methodology for non-GHG emissions from glass, cement, and lime production; the addition of N2O emissions across agriculture subsectors and additional refinements to agriculture emissions factors; updated North America and Europe data for Q4 2024 in petrochemicals and oil and gas refining; updated methodology and data for cement and steel production to reflect updated emissions factors; and the addition of 56 steel plants to our database.
A detailed description of data updates is available in our changelog here.
To learn more about what is included in our monthly data releases and for frequently asked questions, click here. All methodologies for Climate TRACE data estimates are available to view and download here. For any further technical questions about data updates, please contact: coalition@ClimateTRACE.org.
To sign up for monthly updates from Climate TRACE, click here.
Emissions data for July 2025 are scheduled for release on September 25, 2025.
About Climate TRACE
The Climate TRACE coalition was formed by a group of AI specialists, data scientists, researchers, and nongovernmental organizations. Current members include Carbon Yield; CTrees; Duke University’s Nicholas Institute for Energy, Environment & Sustainability; Earth Genome; Former Vice President Al Gore; Global Energy Monitor; Hypervine.io; Johns Hopkins University Applied Physics Lab; OceanMind; RMI; TransitionZero; and WattTime. Climate TRACE is also supported by more than 100 other contributing organizations and researchers, including key data and analysis contributors: Arboretica, Carnegie Mellon University’s CREATE Lab, Global Fishing Watch/emLab, Michigan State University, Open Supply Hub, and University of Malaysia Terengganu. For more information about the coalition and a list of contributors, click here.
Media Contacts
Fae Jencks and Nikki Arnone for Climate TRACE
Glassmaking has dramatically evolved in the thousands of years since ancient artisans crafted their first decorative beads and perfume bottles. But the underlying recipe remains virtually the same: Combine sand, sodium carbonate, and limestone, then blast the ingredients with scorching heat in a kiln or furnace.
Today, the vast majority of that heat is supplied by burning fossil fuels. Whether manufacturers are turning glass into windows, beverage bottles, smartphone screens, or coatings for solar panels, their methods require lots of energy to reach superhigh temperatures and, as a result, can be very carbon-intensive.
Global glassmakers in recent years have begun working to curb their emissions, spurred by environmental laws and the growing demand for low-carbon products. Companies are testing and deploying new furnace technologies that get their heat from electricity — not fossil gas or heating oil — or from alternative fuels such as hydrogen and biogas.
The latest of these emerging efforts comes from Bavaria, Germany, where the multinational firm Schott recently began building a large-scale electric melting tank inside its existing plant in Mitterteich. The tank is the first of its kind for the type and amount of glass it’s making, and it will run primarily on renewable energy sourced from the grid to turn materials into molten glass.
Schott says its electric tank could slash greenhouse gas emissions from the melting process alone by 80% owing to the reduction in fossil gas use. The 40-million-euro ($47 million) pilot tank is expected to fire up in early 2027 and will produce specially engineered glass tubing for syringes, vials, and other pharmaceutical products.
Jonas Spitra, Schott’s head of sustainability communications, said that replacing fossil fuels with electrified technology — while still meeting strict quality requirements for specialty glass — marks “one of the most challenging yet decisive steps on the industry’s path to decarbonization.”
Schott, which operates in over 30 countries, will use the experiences from its all-electric tank initiative “as a foundation for expanding electrification to other sites, wherever technically and economically feasible,” he told Canary Media.
The German pilot project is moving forward just as a few ambitious low-carbon glass initiatives in the United States have fallen into limbo. In May, the Trump administration’s Department of Energy canceled awards worth roughly $177 million for projects aiming to demonstrate cleaner glassmaking methods in California and Ohio, forcing manufacturers to reevaluate their plans.
“Domestic glass manufacturers across the country are advancing energy-efficient technologies, reducing emissions, and working to try and keep jobs onshore,” Scott DeFife, president of the Glass Packaging Institute, said in a June 6 statement in response to the DOE’s decision. “The Department should lean into glass, not ignore it.”
Worldwide, manufacturers made more than 150 million metric tons of glass in total in 2022. Although glass is used across many sectors, it is produced on a smaller scale than other carbon-intensive materials. Cement production, for instance, surpassed 4 billion metric tons in 2023, while steel production reached nearly 2 billion metric tons that year.
Still, glassmaking remains a significant source of planet-warming gases and local air pollutants like nitrogen oxides. And the challenge of slashing those emissions is essentially the same one vexing other heavy industries: figuring out how to reach hot enough temperatures to make materials without cooking the planet in the process.
Chemical producers are pilot-testing their own electric furnaces to make important compounds like ethylene, which is the building block of many plastic products. Cement startups are developing electricity-driven processes and thermal storage systems to replace traditional kilns. Global steelmakers, meanwhile, are investing in technologies that sidestep the need to use coal, such as hydrogen-based ironmaking facilities and electric arc furnaces.
For glass, the biggest hurdle to decarbonization lies in the melting process, Schott’s Spitra explained.
Glass furnaces require temperatures of between 1,200 and 1,700 degrees Celsius (2,192 and 3,092 degrees Fahrenheit) — hotter than lava — to liquefy the raw materials and mix in recycled glass. The process is responsible for about two-thirds of total carbon dioxide emissions from glass production. Most of that CO2 comes from burning fossil fuels, though some emissions result from the chemical reactions that happen when heating up sodium carbonate (soda ash) and limestone.
In a conventional furnace, gas is injected into a combustion chamber to melt the ingredients into a glowing orange liquid. In an electric version, electrodes pass currents through a conductor to generate heat. Today, the industry mostly uses electric equipment only for smaller-scale furnaces or to supplement the fossil-fuel-based heat inside larger furnaces — a step known as “electric boosting.”
Facilities that make high-volume products like container glass and windows are trickier to fully electrify. Existing electric designs have struggled to operate with the same consistency and flexibility as gas furnaces, and they can’t incorporate as much recycled material into the glass mix. Electric furnaces also tend to wear down and need replacing about twice as fast as their gas-burning counterparts, according to glass industry experts.
In Germany, Schott is aiming to address those problems with its new industrial-scale melting tank, which must also meet the exacting standards for bubble-free, high-quality pharmaceutical glass. The initiative, which Schott began developing in 2021, is partly funded by the German government and a European Union–backed program to decarbonize energy-intensive industries in Germany.
The company is investing in electrification in part to meet European climate regulations, including a CO2 emissions cap for heavy industrial sectors. But it’s also responding to the demand from pharmaceutical customers that are working to reduce their supply-chain emissions. Schott views decarbonization as a “strategic opportunity to strengthen its competitiveness,” Spitra said.
Beyond the technical issues, a few other barriers stand in the way of electrifying glassmaking at a wider scale.
In some locations, the local grid may be unable to support a major increase in electricity use, requiring companies and utilities to upgrade that infrastructure or build more wind, solar, and other electricity resources. For producers of mass-market packaging like soda bottles, it can be harder to convince beverage companies to pay more for low-carbon glass if it means raising the sticker price of the final product, especially if the competition is cheap plastic containers.
Another challenge for U.S. glassmakers in particular is that switching to electricity very likely means paying higher utility bills, making it harder to justify ditching fossil gas.
Sonya Pump, the global sustainability director for Ohio-based O-I Glass, said that gas pricing is one of the key factors the company weighs when evaluating low-carbon furnace technologies — along with potential technical constraints or risks to its manufacturing capabilities. O-I Glass makes billions of glass containers every year in facilities in nearly 20 countries, and the criteria it considers vary by market, as well as the type and quantity of glass it’s producing.
For that reason, in the U.S., “a fully electric melter is not currently the best solution for our business,” she said. “Though, in other geographies — areas in Europe, for example — energy pricing, carbon costs, and intense interest from our customers in emerging sustainability solutions make for analyses that look very different.”
In central France, O-I Glass is investing $65 million to build a hybrid-electric melter that can use up to 70% electricity and is set to come online in 2026. Pump said her team is also learning from its participation in electrification projects conducted through the nonprofit consortium Glass Futures and from other industry efforts. At the same time, O-I Glass is replacing some of its older furnaces in the U.S. and globally with modern systems that use oxygen and waste heat to reduce facilities’ total fossil-fuel use.
The manufacturer recently set a goal of slashing its overall greenhouse gas emissions by 47% by 2030, relative to 2019 levels, in addition to boosting its use of electricity from renewables and increasing the use of recycled glass.
O-I Glass had planned to rebuild an aging furnace in Zanesville, Ohio, and combine five cutting-edge technologies — including for electric boosting, preheating materials, and recovering waste heat — to see how much they could offset gas consumption when working together. The project was slated to receive up to $57.3 million from the DOE. Now that the federal funding has been canceled, the company is considering its next steps, Pump said.
Other initiatives to electrify glassmaking or test replacing gas with hydrogen are also now “slightly paused” under the Trump administration, said Matthew Kirian, director and technical program manager of the Northwest Ohio Innovation Consortium. The nonprofit works with O-I Glass and other manufacturers such as solar-panel-maker First Solar to advance innovation within the region’s long-standing glass industry.
“On the energy and fuel side of things, it’s hard to set a firm strategy, especially for the next two to three years, because of federal policy that is so clear … that combustion is king,” Kirian said.
For now, he added, glass manufacturers are largely focusing on other strategies to lessen their environmental impact, including improving the energy efficiency and operating performance of existing facilities and working to increase recycling rates for glass containers — only about 30% of which get recycled nationwide — so that less material winds up in landfills and more is melted into fresh glass.
“Their sustainability goals aren’t going away,” Kirian said of the glassmakers. “We’re hoping to really move the needle for generations to come.”
States are ramping up efforts to get residents to switch from fossil-fuel-fired heating systems to all-electric heat pumps. Now, they’ve got a big new tool kit to pull from.
Last week, the interagency nonprofit Northeast States for Coordinated Air Use Management, or NESCAUM, released an 80-page action plan laying out key strategies to turbocharge heat-pump deployment. Individual states are already putting many of these tactics to the test.
California, Colorado, Maine, Maryland, Massachusetts, New Jersey, New York, Oregon, Rhode Island, and the District of Columbia together committed to ambitious heat-pump adoption goals last year. Washington state joined the pact last week. Their targets: By 2030, heat pumps will make up 65% of the sales of residential heating, air conditioning, and water heating equipment. By 2040, that percentage is to climb to 90%.
The goals are essential for addressing climate change. Buildings are directly responsible for 13% of U.S. carbon emissions, in part due to the fossil fuels burned on-site to heat indoor air and water. All-electric heat pumps can do those jobs running on clean power.
The NESCAUM action plan comes as the Trump administration clings tenaciously to fossil fuels. In recent months, the federal government has rolled back energy-efficiency standards for appliances, imposed chaotic tariffs that are raising costs for consumers, and put an early expiration date on the $2,000 federal tax credit that helps homeowners afford heat pumps.
Despite these headwinds, the report shows that “states are still finding creative ways to move forward,” said Emily Levin, policy and program director for NESCAUM.
HVAC heat pumps are routinely two to four times as efficient as gas furnaces, capable of heating and cooling interiors using the same physics that refrigerators employ to chill your cucumbers. Heat-pump water heaters work the same way and are three to five times as efficient as gas water heaters. By eschewing fossil fuels, these technologies improve air quality and typically save people money over the long term, even if, on average, they cost significantly more up-front than conventional heating systems. (At least one startup, though, is trying to change that.)
Heat pumps are slowly catching on. In the U.S., the units outsold gas furnaces by their biggest-ever margin last year, but their share of the market is still modest. Citing data from the Air-Conditioning, Heating, and Refrigeration Institute, a trade association, Levin said that in 2021, heat pumps accounted for about 25% of the combined shipments of gas furnaces, heat pumps, and air conditioners, the three largest reported HVAC categories. In 2024, they’d risen to about 32%.
“No matter how you look at it, there are still a lot of gas furnaces being sold, there are still a lot of one-way central air-conditioners being sold — all of which could really become heat pumps,” Levin said.
Produced in consultation with state agencies, environmental justice organizations, and technical and policy experts, the NESCAUM report lays out a diverse set of more than 50 strategies — both carrots and sticks — covering equity and workforce investments, obligations to reduce carbon, building standards, and utility regulation. A wide range of decision-makers, often in collaboration, can pull these levers — from utility regulators to governor’s offices, state legislatures, and energy, environment, labor, and economic development agencies. Here are six recommendations from the report that stand out.
NESCAUM’s Levin stressed that the report is “a menu — not a recipe.” Each state will need to consider its own goals and constraints to pick the approaches that fit it best, she added.
Still, “I see [heat-pump electricity] rates as one of the areas that’s most promising,” Levin said. Massachusetts’ reforms “are really going to change their customer economics to make it more attractive to switch to a heat pump.”
When done right, rate design also avoids the need for states to find new funding. “You’re not raising costs on anybody, you’re only reducing costs,” Levin said. At a time when households are seeing energy prices rise faster than inflation, the tactic could have widespread political appeal, she noted.
NESCAUM plans to check back in with states and report out on their progress each year, Levin said. “The cool thing about our work is that we bring states together to learn from one another,” she added. “Part of making this transition happen more rapidly is lifting up the things that are really working well.”
After years of failed attempts, California lawmakers have cleared the way to create an electricity-trading market that would stretch across the U.S. West. Advocates say that could cut the region’s power costs by billions of dollars and support the growth of renewable energy. But opponents say it may make the state’s climate and clean-energy policies vulnerable to the Trump administration.
Those are the fault lines over AB 825, also known as the “Pathways Initiative” bill, which was signed into law by Democratic Gov. Gavin Newsom on Sept. 19 as part of a major climate-and-energy legislative package. The law will grant the California Independent System Operator (CAISO), which runs the transmission grid and energy markets in most of the state, the authority to collaborate with other states and utilities across the West to create a shared day-ahead energy-trading regime.
Passage of this bill won’t create that market overnight — that will take years of negotiations. CAISO’s board wouldn’t even be allowed to vote on creating the market until 2028.
But for advocates who’ve been working for more than a decade on plans for a West-wide regional energy market, it’s a momentous advance. “We’ve shot the starting gun,” said Brian Turner, a director at clean-energy trade group Advanced Energy United, which was outspoken in support of the legislation.
Today, utilities across the Western U.S. trade energy via bilateral arrangements — a clunky and inefficient way to take advantage of cheaper or cleaner power available across an interconnected transmission grid. An integrated day-ahead trading regime could drive major savings for all participants — nearly $1.2 billion per year, according to a 2022 study commissioned by CAISO.
That integrated market could create opportunities for solar power from California and the Southwest and wind power from the Rocky Mountains and Pacific Northwest to be shared more efficiently, driving down energy costs and increasing reliability during extreme weather.
Lower-cost power more readily deliverable to where it’s needed could also reduce consumers’ monthly utility bills — a welcome prospect at a time of soaring electricity rates.
The regional energy market plan is backed by a coalition that includes clean-energy trade groups such as Advanced Energy United and the American Clean Power Association; environmental groups including the Sierra Club, Union of Concerned Scientists, and the Natural Resources Defense Council; business groups including the California Chamber of Commerce and the Clean Energy Buyers Association; and the state’s major utilities. It also has the backing of U.S. senators representing California, Oregon, and Washington, all states with strong clean-energy goals.
Assemblymember Cottie Petrie-Norris, a Democrat who authored AB 825, said in a statement following its passage that it “will protect California’s energy independence while opening the door to new opportunities to build and share renewable power across the West.”
But consumer advocates, including The Utility Reform Network, Consumer Watchdog, and Public Citizen, say the bill as passed fails to protect that energy independence. The Center for Biological Diversity and the Environmental Working Group share their concerns. They fear a new trading market will allow fossil fuel–friendly states like Idaho, Utah, and Wyoming to push costly, dirty coal power into California — and give an opening to the Trump administration to use the federal government’s power over regional energy markets to undermine the state’s clean-energy agenda.
The arguments for a day-ahead energy-trading market can be boiled down to a simple concept, Turner said — bigger is better. Being able to obtain power from across the region could reduce the amount of generation capacity that individual utilities have to build. And tapping into energy supplies spanning from the Pacific Ocean to the Rocky Mountains would allow states undergoing heat waves and winter storms to draw on power from parts of the region that aren’t under the same grid stress, improving resiliency against extreme weather.
A Western trading market could also serve as a starting point for even more integrated activity between the dozens of utilities in the region that now plan and build power plants and transmission grids in an uncoordinated way. A 2022 study commissioned by Advanced Energy United found that a regional energy organization could yield $2 billion in annual energy savings, enable up to 4.4 gigawatts of additional clean power, and create hundreds of thousands of permanent jobs.
CAISO proposed this Extended Day-Ahead Market (EDAM) concept six years ago as an expansion of the real-time energy trading it already conducts with utilities across the West. CAISO’s EDAM scheme is competing with another prospective day-ahead market being promoted by the Southwest Power Pool, a regional grid operator based in Arkansas that serves 14 Midwest and Great Plains states.
For advocates of a Western market, the chief challenge has been to design a structure that doesn’t give up California’s control over its own energy and climate policies, but allows other states and their utilities a share of decision-making authority over how the market works. Taking a lead on that design work has been the West-Wide Governance Pathways Initiative, a group of utilities, state regulators, and environmental and consumer advocates.
Regional-market boosters tried and failed to pass enabling legislation in California in 2017 and 2018 in the face of opposition from environmental groups that feared the plan would clear the way for coal-fired power to come in from other states. Labor unions representing California utility workers also opposed those earlier bills on the grounds that cheaper out-of-state power could lead to less clean energy being built in California.
But many of these prior opponents, including the Sierra Club and key unions, came around to support the latest plan.
With the passage of AB 825, “we’re looking at a fairly rapid and clear rollout of the organization, so that Western states and utilities can begin to get engaged,” Turner said.
But by engaging in a regional energy market, California could risk losing some control over its climate and clean-energy progress, critics say. They argue that the final version of AB 825 doesn’t have enough protections against this outcome.
“We’re strongly opposed,” said Matthew Freedman, staff attorney at The Utility Reform Network (TURN). Previous versions of the bill “had a bunch of provisions we thought would have protected California’s sovereignty and prevented the federal government from weaponizing its authority. Most of those protections were stripped from the bill, inexplicably.”
In particular, in May, TURN and its allies pushed to add an amendment that would have created an oversight council including California lawmakers that would have had the authority to pull the state out of the market if they determined it would raise energy costs or work against the state’s carbon-emissions goals.
“It’s about retaining the state’s sovereignty,” said Jamie Court, president of Consumer Watchdog. “This is our last political check on when we get into the market and when we get out of the market.”
But the provisions in that amendment were “poison pills” for other states considering membership in the market, said Merrian Borgeson, California policy director for climate and energy for NRDC, which supported the legislation. “That would have made it far too unstable.”
The final version of AB 825 still gives California lawmakers the authority to pull the state out of the regional day-ahead market, said Turner of Advanced Energy United — just not via the hair-trigger structure that opponents had sought. “At any time, the Legislature could say, ‘This market is no longer in the interest of California. We’re going to order the Public Utilities Commission to order the utilities to stop participating in this market,’” he said.
The bill’s authors argue that they got the balance right. State Sen. Josh Becker, a Democrat whose bill initially contained the Pathways proposal before it was shifted into AB 825, said that the final structure “provides the accountability that some folks wanted but that’s also enticing to market participants.”
However, TURN and Consumer Watchdog say that the risks outweigh the benefits — particularly if an expanded market exposes the state to federal interference. The Trump administration has been using federal emergency powers to prevent regional grid operators from closing coal plants set for retirement, and it may seek to force the Federal Energy Regulatory Commission to abandon its historically apolitical approach to governing regional energy markets, which could “frustrate key state environmental, resource-planning, reliability, or other public-interest policies,” Freedman said.
“Why California should give up its governance over that regional market is a mystery to me,” he said. “We have no faith that federal agencies will act with good faith or common sense or the law.”
Turner at Advanced Energy United disagrees with that assessment. “CAISO is currently a FERC-regulated market, and this will not increase its exposure to FERC regulation,” he said.
In the end, AB 825 won the support of what Becker described as a “broad and unprecedented coalition spanning environmental organizations, labor, business, and consumer advocates.”
In fact, joining with other states might actually strengthen California’s position against Trump administration overreach, Turner argued. “We understand the federal government may try to distort the free market in ways that benefit their preferred technologies,” he said. “There is a very credible argument to be made that joining shoulder to shoulder with other states improves our ability to defend ourselves against those kinds of things.”
Small solar-panel kits that can be assembled as easily as an Ikea bookcase and plugged into a regular residential outlet could be coming soon to New Hampshire and Vermont. Lawmakers and advocates in both states are preparing legislation that would make these plug-in solar systems accessible to residents who don’t have the space, money, or inclination to install a larger, conventional rooftop array.
“It’s really about energy affordability,” said Kevin Chou, cofounder of Bright Saver, a nonprofit that advocates for the adoption of plug-in solar. “It’s about access for people who wanted solar but haven’t been able to get it.”
These systems — also called “portable” or “balcony” solar — generally come in kits that even a novice can put together at home. They plug into a standard outlet, sending the power they generate into a home’s wires, rather than drawing electricity out.
Unlike rooftop arrays, plug-in systems don’t generate enough power to meet all, or even most, of a household’s needs, but they offset enough consumption to pay for themselves within four or five years, even without incentives like tax credits or net metering, Chou said. Models now on the market start at about $2,000. If the equipment becomes more popular and prices come down, the payback period could get even shorter.
“You don’t need any subsidies to make this work,” Chou said. “The pure economics are so attractive, it’s one of the best investments you can make.”
These systems have taken off in Germany, where more than a million have been deployed, but have been much slower to catch on in the United States.
Recently, though, the idea has gained traction in the U.S. In March, Utah lawmakers, working with Bright Saver, unanimously passed a law authorizing and regulating the equipment, making it the first state to lay out the welcome mat for plug-in solar. Last month, a Pennsylvania state representative announced plans to introduce a similar law, and Bright Saver is having conversations with lawmakers in about a dozen additional states about possible legislation, Chou said.
All of the legislative proposals follow the same principles as Utah’s law: They would define a new class of small, portable solar systems, and establish the right of households to use the systems without submitting applications or paying fees to the state or utilities. They also define safety standards for the systems, including that they be certified by Underwriters Laboratories, or UL, a company that sets standards and provides safety certifications for a wide range of products.
At the moment, two manufacturers make plug-in solar systems with inverters that have been certified as complying with safety requirements, Chou said. Because the market for portable solar is so new, however, UL has not developed standards for entire systems. Bright Saver and other plug-in solar supporters have been working with the company on this issue and expect a standard to be released in the next month or two, Chou said.
Other startups are waiting in the wings, hoping to launch their own products next year, once the questions about UL standards are resolved, he added.
“Bottom line: Once Vermont’s legislation passes, there will be existing manufacturers ready to sell into the state immediately, along with new entrants waiting for additional UL clarity, who are also preparing to launch,” Chou said.
Supporters hope the benefits of plug-in solar — lowered electricity costs, freedom to make personal energy choices — will help the idea gain support even in states not known for their embrace of renewable energy, and despite federal efforts to slow or stop renewable energy progress. The early and robust acceptance of the technology in deep-red Utah has bolstered this vision.
“I am optimistic that, as in Utah, it’s going to be seen as a commonsense way to just get out of the way and let people do good things,” said Ben Edgerly Walsh, climate and energy program director at the Vermont Public Interest Research Group, an organization backing Vermont’s expected plug-in solar bill.
In New Hampshire, a swing state known for its “live free or die” libertarian streak, Democratic state Sen. David Watters also thinks this dynamic might work in the technology’s favor, despite the state’s historical lack of support for measures boosting solar use.
“We’re really kind of stuck in a rut with anti-renewable-energy sentiment in the House,” Watters said. “This seemed like something that would fit into the ethos of people being able to make individual choices.”
Watters, a member of the state Senate Energy and Natural Resources Committee, worked with local advocacy group Clean Energy New Hampshire to author a rough draft of a plug-in solar bill based on Utah’s new law. It will be refined in the coming months and formally introduced in the legislature in January.
Notably, Watters said, his proposal would not stop homeowners associations or landlords from imposing their own rules on members and tenants.
“Their authority is not taken away,” he said. “For this state, that’s crucial.”
In Vermont, two Democratic state legislators — Sen. Anne Watson, chair of the Senate Committee on Natural Resources and Energy, and Rep. Kathleen James, chair of the counterpart committee in the House — are championing a plug-in solar bill based on model legislation drafted by Bright Saver. Watson is particularly excited for the potential of plug-in solar to reach low-income residents and renters.
“This creates access for folks who might otherwise not have the authority to put something on their roof, or who might need something a little more flexible,” she said.
Vermont, a decidedly left-leaning state, has long welcomed renewables. The state’s governor, Phil Scott, however, is a Republican who has shown reluctance to spend public money on clean energy. Further, the legislature lost its veto-proof Democratic majorities during the last election, so prospects for forward movement on energy and climate issues have been dimmed this year.
However, Watson has already heard a lot of positive feedback from her fellow lawmakers, even though the bill won’t be taken up until the legislature reconvenes in January. Indeed, several colleagues came to her with similar proposals before learning she was already working on it. She has also had initial conversations with the Scott administration and found it willing to consider the idea, she said.
“While I can’t say they are necessarily for it, the reception I’ve received so far is that they are open and interested in learning more,” she said. “I am hoping for broad support.”
Revolution Wind can officially resume. But unlike the last time President Donald Trump ordered construction on an offshore wind project to pause, relief came through the courts rather than politicking.
A federal judge on Monday ruled in favor of the Danish energy giant Ørsted, whose $6.2 billion Rhode Island project was halted last month by the Interior Department without, as the judge put it, any “factual findings.” A similar stop-work order that froze construction on New York’s Empire Wind was lifted by Trump officials in May following one month of heavy lobbying — and reported backdoor deal-making — by lawmakers and diplomats.
Judge Royce Lamberth, a Reagan-era appointee serving the U.S. District Court for the District of Columbia, granted a motion for a preliminary injunction sought by Revolution Wind to resume turbine construction while its complaint against the Interior Department works its way through the courts, which could take years. The project is 80% complete, and Ørsted released a statement on Monday saying workers will restart “as soon as possible.”
Monday’s decision marked a victory for Revolution Wind and could have broader legal ramifications for Trump’s ongoing war against offshore wind energy, given that several projects are still tangled up in litigation. And, if the recent ruling is any indication, the Trump administration may have a hard time convincing judges that walking away from already-approved wind farms makes sense.
“The Trump Administration’s erratic action was the height of arbitrary and capricious, and failed to satisfy any statutory provisions needed to halt work on a fully approved and nearly complete project. It was not a close call,” Connecticut’s Attorney General William Tong, a Democrat, stated in response to Lamberth’s decision.
Twelve other high-profile lawsuits are actively challenging Biden-era approvals for eight U.S. wind farms, according to the research firm ClearView Energy Partners. Traditionally, the government defends projects it’s already greenlit. Legally, however, it can pick and choose which approvals to stand up for.
For example, three of those projects — New England Wind, SouthCoast Wind, and the Maryland Offshore Wind Project — could soon lose their federal approvals. None of the three have started construction yet, but in the past month, government officials have filed documents in court for each, trying to undo approvals granted by the Biden administration.
“These other cases are different procedurally, but [the Revolution Wind ruling] shows that the courts are taking this seriously and that the Trump administration took these actions without sufficient justification,” said Nick Krakoff, a senior attorney for the Conservation Law Foundation.
The latest blow came on Thursday, when government lawyers filed a motion to reverse its approval of SouthCoast Wind, a massive 141-turbine project slated for federal waters near Massachusetts’s coastline. Krakoff said that the legal argument is nearly identical to one filed in the U.S. District Court of Maryland the week prior seeking to take back approvals from the Maryland Offshore Wind Project.
Both filings invoke a new legal interpretation of the Outer Continental Shelf Lands Act that argues that the Interior Department must weigh other ocean activities — like commercial fishing and Coast Guard operations — in an “absolutist approach,” said Krakoff, to evaluate potential conflicts with wind farms.
The standard interpretation, employed for almost a decade by past administrations and already upheld in a 2024 court decision, instructs agencies to take a more balanced approach to evaluating multiple ocean users.
“It’s not unprecedented for a new administration to switch positions. But it is unprecedented to seek to remand a permit because of it,” said Krakoff, who called the Trump-era interpretation of the law a “coordinated attack” on thousands of clean energy jobs.
Oddly, the Trump administration appears to be defending some wind projects at the center of these legal challenges while trying to tank the three others.
For example, on Sept. 8, the Interior Department’s Bureau of Ocean Energy Management filed a letter signalling that it wants to dismiss a lawsuit brought by the anti-wind group Protect Our Coast NJ that challenges New York’s Empire Wind.
Then there is the exceptional case of Virginia. Earlier this month, E&E News reported that House Speaker Mike Johnson (R) publicly defended Coastal Virginia Offshore Wind, which is the only offshore wind farm currently being built in a Republican-led state. ClearView’s analysts believe this GOP support may explain why the Trump administration has not tried to remand approvals for the Virginia project in response to a lawsuit brought by the Heartland Institute and other right-leaning think tanks challenging its construction. Instead, on Friday, government lawyers asked the judge for a 90-day extension on filing a report on the Virginia project’s status.
Being inconsistent in when and how it deploys new legal interpretations could backfire for the Trump administration.
On Monday, Lamberth told government lawyers that “mandating the immediate pause to construction of a project whose approval the Bureau continues to defend in other cases is the height of arbitrary and capricious.”
Meanwhile, Democratic lawmakers are clearly frustrated that most of the offshore wind projects in Trump’s crosshairs are in solidly blue states at a moment when they have little power in Congress to fight back. Many Democrats see the courts as the best hope for surmounting the administration’s continued efforts to block the development of wind power, which they view as necessary for meeting growing electricity demand.
“One of our most important roles right now is to illustrate to people that the actions taken by this administration are creating shortages and … spikes in your [electricity] prices. Second is the litigation pathway,” Sen. Brian Schatz, a Democrat from Hawaii, said during a press call on Monday.
The longtime climate hawk discussed new data showing that electricity prices in the U.S. have risen by 10% since Trump took office. Lawmakers from both sides of the aisle have proposed legislation that would streamline energy project permitting, but that is not a near-term solution for wind developers, Schatz said, adding that litigation is the faster route towards “success.”
Revolution Wind’s stop-work order had been bleeding its developers of “more than $2 million per day,” according to court filings, and posing a risk to New England’s future grid reliability.
“The time frame to get a new law in place and enforce that new law is unlikely to match up with the time frame of a developer who is almost invariably working on borrowed money and can’t wait three and a half years while we sort ourselves,” said Schatz.
For Revolution Wind, Monday’s legal victory may only be temporary — federal officials could appeal the ruling. A spokesperson for the Justice Department declined to comment. A similar but separate lawsuit challenging Revolution Wind’s stop-work order, brought by the attorneys general of Rhode Island and Connecticut, is winding its way through the courts. Last week, the feds requested that this case be transferred to the U.S. District Court in D.C. so that it can be consolidated with the developers’ case.
If the 704-megawatt project reaches completion, its carbon-free electricity will feed into New England’s regional grid, serving utility customers who just endured a winter where power bills skyrocketed.
Funding for Rhode Island’s energy-efficiency programs could be cut by more than $42 million next year in an effort to rein in residents’ soaring power bills. That rollback would deprive the state of more than $90 million in benefits and potentially eliminate hundreds of jobs while creating only modest up-front savings, a new analysis finds.
Rhode Island Energy, the utility that administers the state’s energy-efficiency offerings, has proposed to slash spending on that front by 18% compared to last year and more than 30% compared to the budget originally projected in the nonbinding three-year plan introduced in 2023. If approved, the cuts will save the average household $1.87 per month, according to Rhode Island Energy.
The result of these changes, according to climate action nonprofit Acadia Center, would be more expensive electricity and more exposure to volatile natural gas prices in the long run.
“Energy efficiency is a tool for suppressing supply costs, for suppressing infrastructure costs in the long-term,” said Emily Koo, Acadia Center’s program director for Rhode Island and one of the authors of the group’s analysis. “I am not seeing our leaders think beyond the immediate.”
Rhode Island has traditionally been a leader in energy-efficiency programming. Over the past 15 years, the state has repeatedly placed among the top 10 states in the American Council for an Energy-Efficient Economy’s annual energy-efficiency scorecard. Since 2009, the state has spent more than $2 billion on efficiency incentives and services, yielding more than $6 billion in environmental and social benefits.
Now, however, the dynamics of energy markets are creating new obstacles. Nationwide, electricity costs have gone up at twice the rate of inflation over the past year, and gas prices have increased by more than four times the inflation rate. Rhode Island, like other New England states, has the added difficulty of already having some of the highest electricity rates in the country. Add in cold Northeastern winters, and the state is girding for an expensive season ahead.
As in neighboring states, regulators, elected officials, and utilities in Rhode Island are scrambling for ways to provide some relief for residents and businesses. These efforts have increasingly looked to the bill fees that fund renewable energy incentives and energy-efficiency programs as possible targets for quick, if small, bill reductions. In Maine, for example, leaders from both sides of the aisle have sought to lower incentives for customers and community solar developments that send power back to the grid, and in Massachusetts, utility regulators ordered energy-efficiency administrators to cut $500 million from a planned $5 billion three-year budget.
Now, Rhode Island Energy is proposing rollbacks of its own, saying that its latest plan prioritizes customer affordability. The company has the support of the Rhode Island Division of Public Utilities and Carriers, which points to the growth in accounts with overdue utility bills to bolster its argument that the changes will provide needed relief to consumers.
“There is simply a financial limit as to how much cost the ratepayers can bear,” the department wrote in its public comments on the proposal.
Advocates, however, say the approach is short-sighted.
“This is weaker. It’s a retreat,” said Larry Chretien, executive director of the nonprofit Green Energy Consumers Alliance, which opposes the proposed cuts. “It just feeds into the narrative — that we don’t accept — that ratepayers aren’t seeing benefits from energy efficiency.”
Rhode Island’s energy-efficiency offerings include home energy assessments, weatherization services, rebates on energy-saving appliances and heating and cooling systems, and contractor training. Residents and businesses that take advantage of these programs generally save money by reducing their energy use.
The programs also create savings for the average consumer, whether or not they participate. Because the improvements slow energy consumption, they allow utilities to build less pricey infrastructure, the cost of which is passed on to customers. Efficiency measures can also lower peak demand, reducing the need to buy costlier, dirtier power from peaker plants. In Rhode Island, efficiency programs lowered electricity use 5% between 2005 and 2024; without these interventions, use would have increased 15%, according to an annual state report.
Advocates, therefore, argue that Rhode Island Energy’s plan to shrink energy-efficiency spending won’t actually result in more affordable power in the long run.
“You spend money on energy efficiency or you’re going to spend even more money on power supply,” said Forest Bradley-Wright, state and utility director for the American Council for an Energy-Efficient Economy.
Acadia Center’s analysis also finds that more than 800 jobs in the energy-efficiency sector could be at risk if the cuts are adopted.
The draft plan has been through multiple iterations; the most recent version was released on Sept. 5. The state energy-efficiency council is expected to vote on the proposal at its Sept. 25 meeting. The plan will then go to utility regulators for final approval.
Advocates say they intend to keep pushing for high funding levels until the process concludes.
“The benefits we’re experiencing today are already translating into lower bills,” Bradley-Wright said. “There’s a track record of success, but let’s not take it for granted.”
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