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Since 2021, the Sierra Club has been grading U.S. utilities on their commitment to a clean-energy transition. While most utilities have not earned high marks on the group’s annual scorecards, as a whole they had been showing some progress.
That’s over now. The latest edition of the Sierra Club’s “The Dirty Truth” report finds that the country’s biggest electric utilities are collectively doing worse on climate goals than when the organization started tracking their progress five years ago. This year they earned an aggregate grade of “F” for the first time.
With only a handful of rare exceptions, U.S. utilities have shed the gains they made during the Biden administration. Almost none are on track to switch from fossil fuels to carbon-free energy at the speed and scale needed to combat the worst harms of climate change.
“It’s very disappointing to find we’re at a lower score than in the first year,” said Cara Fogler, managing senior analyst at the Sierra Club, who coauthored the report. But it’s not entirely unexpected.
Utilities had already begun slipping on their carbon commitments last year, in the face of soaring demand for electricity, according to the 2024 “Dirty Truth” report, largely in response to the boom in data centers being used to power tech giants’ AI goals. But the anti-renewables, pro–fossil fuels agenda of the Trump administration and Republicans in Congress has pushed that reversal into overdrive.
“We have a new federal administration that’s doing everything in their power to send utilities in a direction away from cleaner power,” Fogler said. “They’re doing away with everything in the Inflation Reduction Act that supported clean energy. They’re straight-up challenging clean energy, as we’ve seen with Revolution Wind,” the New England offshore wind farm that’s now under a stop-work order. “And they’re doing everything in their power to keep fossil fuels online” — for example, through Department of Energy actions that force coal, oil, and gas plants to keep running even after their owners and regulators had agreed on retirement dates.
But utilities also bear responsibility for not doing more to embrace technologies that offer both cleaner and cheaper power, Fogler said. “From a cost perspective, from a health perspective, from a pollution perspective, there are so many reasons to build more clean energy and fewer fossil fuels. Unfortunately, we’re seeing that utilities are much less concerned about doing the right thing for the climate and their customers.”
For its new “The Dirty Truth” report, the Sierra Club analyzed 75 of the nation’s largest utilities, which together own more than half the country’s coal and fossil-gas generation capacity. The report measures utilities’ plans against three benchmarks: whether they intend to close all remaining coal-fired power plants by 2030, whether they intend to build new gas plants, and how much clean-energy capacity they intend to build by 2035.
As of mid-2025, the utilities had plans to build only enough solar and wind capacity to cover 32% of what’s forecast to be needed by 2035 to replace fossil-fuel generation and satisfy new demand. While 65% of the utilities have increased their clean-energy deployment plans since 2021, 31% have reduced them.
Meanwhile, commitments to reduce reliance on fossil fuels have taken a big step backward as utilities have turned to keeping old coal plants running and are planning to build more gas plants to meet growing demand. As of mid-2025, the utilities had plans to close only 29% of coal generation capacity by 2030, down from 30% last year and 35% in 2023.
And the amount of gas-fired generation capacity the utilities plan to build by 2035 spiked to 118 gigawatts as of mid-2025. That’s up from 93 gigawatts in 2024, and more than twice the 51 gigawatts planned in 2021.
That expanding appetite for new gas-fired power has been supercharged by the surge in forecasted electricity demand across much of the country — data centers are the primary driver of that growth. But much of that expected data-center demand is speculative. And the lion’s share of it is premised on the idea that the hundreds of billions of dollars in AI investments from tech giants like Amazon, Google, Meta, and Microsoft as well as AI leaders like OpenAI and Anthropic will end up earning those companies enough money to pay off their costs — a risky bet.
The Sierra Club is among a growing number of groups demanding that utilities and regulators proceed with caution in building power plants to serve data centers that may never materialize. Forecasted data-center power demand is already driving up utility rates for everyday customers in some parts of the country, and the new gas power plants now in utility plans aren’t even built yet.
“There is some load we’re naturally going to see — there’s population growth, lots of beneficial electrification we want to see happen,” said Noah Ver Beek, senior energy campaigns analyst at the Sierra Club and another coauthor of the report. “But we also want utilities to be realistic about load-growth projections.”
Unfortunately, booming demand growth gives utilities “more cover” to invest in polluting assets, Fogler said. Utilities earn guaranteed profits on the money they spend building power plants and grid infrastructure, which gives them an incentive to avoid questioning high-growth forecasts or seeking out lower-cost or less-polluting alternatives.
Some of the most aggressive fossil fuel expansions are planned for the Midwest and Southeast, including by Dominion Energy in Virginia, Duke Energy in North Carolina, and Georgia Power.
Even the handful of utilities that have previously earned high marks for clean-energy and coal-closure commitments in past “Dirty Truth” reports have slipped. Fogler highlighted the example of Indiana utility NIPSCO, which earned an “A” in the past four reports but only a “B” in the latest, largely due to its plan to rely on gas power plants to meet expected data-center demand.
NIPSCO has “no plans to pursue the high-load-growth scenario until they see contracts signed and progress made,” Fogler said — a prudent approach that avoids burdening customers with the costs of new power plants built for data centers that may never come online, she said. “The problem? Their high-load-growth scenario calls for all new gas. There should be more clean options.”
Most utilities are not capitalizing on the solar and wind tax credits that are set to disappear in mid-2026 under the megalaw passed by Republicans in Congress this summer, she said. Only a handful of utilities, such as Xcel Energy in Colorado and Minnesota, are accelerating their clean-energy deployments to take advantage of those tax credits. “We want more utilities to take that period of certainty and speed up what they’ve already planned.”
Going big on clean energy is also the only way to quickly add enough generation capacity to meet growing demand forecasts and contain rising utility costs, Ver Beek noted. Utilities and major tech companies are pinning their near-term capacity expansion plans on new gas plants, despite the yearslong manufacturing backlogs for the turbines that power those plants and rapidly rising turbine costs.
“From a cost perspective, from a climate perspective, we want to see utilities advocating for getting as much clean energy online as they can,” he said.
Across California, hundreds of homes and businesses have signed up their solar panels, batteries, EVs, and appliances to be part of “virtual power plants” — networks of scattered energy resources that utilities can control to stave off blackouts and cut electricity prices.
Now, utilities are exploring another way to leverage VPPs: Strategically concentrating the systems in certain areas could let the companies defer expensive upgrades to nearby poles, wires, and other infrastructure. But first, utilities need to be 100% sure they can count on customer-owned assets without risking the grid’s reliability.
That’s the challenge that Northern California utility Pacific Gas & Electric is taking on with a pilot program it is running this summer and fall. PG&E has years of experience operating virtual power plants to reduce stress across the statewide grid. But the new Seasonal Aggregation of Versatile Energy (SAVE) program is testing how customers’ batteries and home energy controls can meet grid needs more precisely, down to the neighborhood level.
PG&E hasn’t said how many households it enlisted for the pilot, but in a March press release, the utility said it aimed to enroll up to 1,500 residential customers with solar-charged batteries from companies including Sunrun and up to 400 customers with smart electrical panels from startup Span.
The local “distribution” grids that serve those customers operate under a variety of conditions, including moments of peak demand that push some of the systems to their limits. Using home batteries and energy controls to delay upgrading those grids could make a big dent in the high and rising costs of electricity in California. In fact, a recent analysis indicates tapping the state’s nation-leading fleet of rooftop solar, backup batteries, and EVs for this task could save billions of dollars in grid upgrade costs.
PG&E isn’t delaying upgrades on the parts of the grid it’s testing just yet, said Trevor Udwin, the utility’s VPP and grid optimization manager. But the SAVE project will inform next steps to start doing this kind of proactive, VPP-integrated grid planning at a larger scale.
“At some point, we need to build trust,” Udwin said. “That means someone’s signing something” — a commitment to deliver the grid relief needed during specific times — ”and that a distribution planner is changing their operations based on that commitment.”
Distribution networks are distinct from the huge transmission lines that move the energy produced by power plants over long distances. Local distribution infrastructure instead carries power from substations — the big, fenced-in collections of equipment that lower the voltage of transmission-fed power — along main feeder lines, and eventually to the wires that connect to neighborhoods, homes, and businesses.
Until recently, utilities lacked technologies like smart meters and grid sensors to let them see what’s actually going on on those parts of their grids. That visibility is important, because these distribution networks have unique and fluctuating needs and characteristics — or load shapes, in industry parlance —that determine where and when they may be experiencing problems.
Without that transparency, the traditional utility fix has been to overbuild the system to reduce risks of overloads. But that’s getting expensive as demand for electricity rises. U.S. utilities invest more capital in their distribution grids than in any other part of their business, and those costs are increasing rapidly.
It could be much cheaper to instead get a cluster of customers to use less energy or send solar or battery power back to the grid during the handful of hours a particular distribution system is overloaded.
To test that capability, PG&E and its SAVE partners are using Sunrun’s batteries and Span’s smart electrical panels to modify how homes participating in the pilot consume and provide electricity to match the hour-by-hour constraints of the grid they’re connected to.
That’s an inherently time- and location-specific challenge, since different grid substations and circuits “may have very different load shapes, and they may peak differently at different hours,” Udwin said. And right now, very few utilities have deployed the data-collecting technology needed to reliably coordinate those interactions across their low-voltage distribution networks.
That technology, referred to as a distributed energy resource management system, or DERMS, does exist. California’s big utilities have run multiple DERMS pilot projects over the years, and PG&E has built a DERMS system that it’s using to manage a handful of EV charging hubs and utility-scale batteries participating in “load flexibility” pilots.
But PG&E hasn’t yet integrated that DERMS platform with the communications and controls technology it’s deploying with its SAVE partners, Udwin said. Instead, for this summer’s tests, PG&E is “building communications with the aggregators,” he said, interfacing with software from Lunar Energy and Tesla to control the batteries, and with Span’s software that keeps whole-home energy use below certain thresholds.
All of that software will be tasked with making sure homes with batteries, panels, and other equipment work together to add power or reduce draws at moments when that section of the grid is expected to experience excessive loads. But it also has to make sure it doesn’t leave customers unable to use their batteries and appliances when they need to, Udwin noted.
PG&E and its SAVE partners want to make sure they’re “serving their customers best, and that the load-shaping won’t negatively impact them,” Udwin said. To make that easier, PG&E is delivering its partners week-ahead and day-ahead load shape requests, he said. That gives Sunrun and Span an opportunity to prepare their customers for lengthy demands on their resources.
“They’re taking a really big risk with us,” he said. “I’m thrilled our partners are taking this leap.”
California was one of the first states to push utilities to integrate customer-owned solar, batteries, and flexible EV chargers and appliances into grid planning. Colorado, Hawaii, Illinois, Massachusetts, Minnesota, New York, and others have enacted similar policies over the past decade. The idea is to capture the grid value of distributed energy resources — solar, batteries, EVs, and smart thermostats, water heaters, and appliances that can shift when they use electricity — that homes and businesses are already buying.
Lots of utilities are already using these technologies to reduce system-wide electricity peaks. In fact, demand-response programs have existed for decades. But beyond a handful of projects, utilities have yet to leverage VPPs as a way to defer investments in their distribution grids.
Utilities don’t have much time to act on this opportunity for savings, said Aram Shumavon, CEO of grid analytics company Kevala. Even with these kinds of targeted VPPs in place, overloaded grid circuits will need to be upgraded sooner or later, he said. And once they are, VPPs can no longer defer those costs, evaporating the potential savings.
Missing out on those savings could hurt. A 2023 study by Kevala found that upgrading California’s distribution grids without deploying tech and programs to prevent EV charging from overloading local circuits could cost the state’s three big investor-owned utilities around $50 billion by 2035. Managing EVs to avoid those overloads, by contrast, could cut that price tag roughly in half, according to more recent studies.
Those savings should more than cover whatever utilities need to pay EV owners to commit to those managed charging constraints, Shumavon said. Eventually, the rising electricity demand from all those new EV-owning customers will increase utility revenues enough to cover those new grid costs, lowering rates for customers at large, he added.
To be clear, the lack of uniformity across different parts of the grid makes it hard to pinpoint the precise value of the VPPs the SAVE program is testing. Assessing that value is exceedingly complicated, given the enormous number of variables involved.
VPP advocates argue that utilities and regulators should avoid getting bogged down in those calculations and err in favor of encouraging customers to lend their spare power to help the grid. A new report from Kevala and think tank GridLab found that California could cut energy costs for consumers by up to $13.7 billion by 2030 by fully utilizing distributed resources like EVs and solar panels to defer grid upgrades.
However, utilities need to be able to prove out that a VPP’s benefits outweigh the expense of paying customers for access to their energy resources, Udwin said. “We want to find ways to shape for everything we can shape for — and do so cost-effectively. That’s the rub.”
PG&E is targeting low-income and disadvantaged communities for at least 60% of its SAVE test cases, Udwin said. There’s a sound rationale for that: Data shows that utilities have underinvested in the distribution infrastructure that serves these communities, which has restricted their ability to access rooftop solar and EV charging.
At the same time, PG&E is focusing on parts of the grid where its SAVE partners already have a concentration of customers. California has more rooftop solar, behind-the-meter batteries, and EVs than any other state, which provides a fertile field of latent resources to tap into, said Yang Yu, Sunrun’s director of business development for distributed power plants (another term for VPPs).
“Deploying assets in a small territory can make it difficult [for VPP programs] to reach scale, even with strong customer incentives like a free battery,” he said. But Sunrun has “a ton of assets already deployed,” he said. “That means that, within a specific region — say a substation or even specific feeders — we may have enough penetration at some point to do a local-level peak-load management.”
That’s not just more cost-effective than upgrading utility grids — it’s also faster. “We can stand up a [distributed power plant] in six months,” he said, which is what Sunrun has done for PG&E’s SAVE program.
We’re in the midst of a global solar revolution. Don’t believe it? Just look at the latest numbers.
In the first six months of this year, the world built 64% more new solar energy capacity than it did in the first half of 2024, according to think tank Ember. The 380 gigawatts’ worth of solar installed through June of this year is roughly equal to the amount of solar installed in all of 2021 and 2022 combined.
The story of this global solar boom is, really, the story of solar growth in China.
The country, which is the world’s largest producer of solar equipment and most other clean-energy technologies, on its own deployed 256 GW of new solar over the first half of this year — more than two-thirds of the global total. That’s double the amount it installed during the same period last year.
China’s rapid buildout of solar is welcome news. The country emits more planet-warming greenhouse gases than any other, in large part because it burns prodigious amounts of coal to produce electricity for its 1.4 billion citizens. But solar and other renewables are now putting enough of a dent in the country’s coal use that some analysts expect China’s overall emissions to decline this year.
Outside of China, the rest of the world installed just 15% more solar capacity in the first half of this year than it did in the first half of last year.
The two next-biggest solar installers over this time period were India, at 24 GW, and the U.S., at 21 GW. The U.S. is still managing to push solar to new heights despite the Trump administration’s attacks on clean energy.
Overall, solar provided just 7% of electricity generated around the globe last year. That percentage needs to increase — fast — so the world can ditch fossil fuels and bend the emissions curve downward. Luckily, solar has so far proven up to the challenge of growing at an astonishing rate.
Solar generated more power than it ever has before on Texas’ grid earlier this month.
That’s impressive, but even more so when you consider that it was the 17th record the power source set in the state this year, according to a new report from the Institute for Energy Economics and Financial Analysis.
The record setting started bright and early on Jan. 24, when solar generated 22.1 gigawatts of power. That figure has since steadily risen, and on Sept. 9, solar produced a huge 29.9 GW. Also that day, solar provided more than 40% of the state’s power from 9 a.m. to 4 p.m., per data from the Electric Reliability Council of Texas, the state’s grid operator.
That early September day capped a groundbreaking summer for solar in Texas. From June 1 through Aug. 31, solar met 15.2% of all demand in the ERCOT system. Coal provided for 12.5% of demand during that time.
And solar wasn’t the only top performer this year. Battery storage has already set four discharge records in Texas this month, often charging up on solar power that floods the grid in the mornings and putting it back into the system when the sun sets, per the Institute for Energy Economics and Financial Analysis.
Texas’ extreme summer temperatures have frequently driven ERCOT to ask people to conserve power, warning that increased air-conditioning use could overwhelm the grid’s energy supplies. But this year, ERCOT didn’t ask customers to conserve power at all, and credited its summertime stability to Texas’ nation-leading deployment of solar and batteries.
This all reveals solar’s growing ability to replace fossil fuels and meet power demand in Texas, especially when the clean energy source is paired with batteries. And it couldn’t be more necessary: The U.S. Energy Information Administration anticipates demand in ERCOT will surge as much as 23% from 2024 to 2026.
Meanwhile, natural gas is failing to meet the moment. Texas developers have proposed building more than 100 new gas power plants in the next few years to meet rising demand from data centers and other heavy industry. The state created a $7.2 billion loan program to incentivize gas plant construction, but more than two years after that fund was launched, just two facilities have been approved for only $321 million in loans. Developers pulled another seven projects from consideration, citing high costs and supply chain challenges.
Solar and batteries, meanwhile, remain among the cheapest and quickest ways to add power generation to the grid — though the Trump administration isn’t making it any easier for communities to yield the benefits of these technologies as it rolls back federal clean energy tax credits and solar-boosting programs.
Even polluters are wary of EPA’s rollback of greenhouse gas reporting
The U.S. EPA proposed late last week to kill its Greenhouse Gas Reporting Program, which has required top polluters to disclose their planet-warming emissions for around 15 years. The rule change would end the collection of data from 46 sources, including power plants, and pause data collection from several petroleum and natural gas industry sources until 2034.
The EPA, as well as states and cities, have used Greenhouse Gas Reporting Program data to create emissions-reduction targets and regulations. Still, one oil and gas lobbyist told E&E News that the industry actually pushed for modifications to the program rather than a full repeal, which could complicate trade with the European Union.
A carbon-capture industry coalition is also opposing the program’s end, saying the reporting rules are “inextricably” tied to federal carbon-capture incentives and the repeal would hurt the industry’s growth.
Trump admin targets two more offshore wind projects
A new wave of federal attacks on offshore wind started last Friday as the U.S. Department of the Interior asked a judge to cancel approval of the Maryland Offshore Wind Project, Canary Media’s Clare Fieseler reports. Republicans in Congress had already saddled the project with potentially insurmountable financial challenges by mandating an early end to federal tax credits, and this potential permit dismissal leaves it in even more trouble.
Just yesterday, Interior asked another court to revoke the same approval for SouthCoast Wind, a 141-turbine project off the coast of Massachusetts. The planned project had similarly been facing financial difficulties.
Meanwhile, the fight to continue building the Revolution Wind project carries on. The Democratic attorneys general of Connecticut and Rhode Island, which would receive power from the nearly complete offshore array halted by the Trump administration, are now seeking a court order to let construction resume.
Surprise, surprise: The National Academies of Sciences, Engineering, and Medicine reaffirms that burning fossil fuels is warming the planet, despite the Trump administration’s moves to downplay and even disavow that finding. (E&E News)
DOE’s new energy philosophy: An Energy Department official touts a “best of the above” approach to power generation in a congressional hearing, as an alternative to the “all of the above” energy philosophy. (E&E News)
States’ new climate fight: Four states team up to battle the Trump administration’s attacks on the endangerment finding, which determined that greenhouse gases are a hazard to public health and underpins many federal climate regulations. (CT Mirror)
Rivian presses on: Rivian broke ground on its $5 billion factory in Georgia this week after long delays, and even though federal EV tax credits are set to expire at the end of this month. (Associated Press)
Affordability in focus: California legislators pass a slate of legislation to lower energy bills, including measures to curb utility profits from grid upkeep and to accelerate transmission development via public financing. (Canary Media)
Electrifying your seafood tower: In the coastal waters of rural Maine, some early adopters of electric boats are proving they’re a quieter, cleaner alternative to petroleum-powered vessels that dominate oyster farming and other aquaculture industries. (Canary Media)
Art Deco decarbonization: A former terminal at Newark Liberty International Airport that’s now an administrative building got an all-electric renovation, and could be a blueprint for other historic buildings looking to decarbonize. (Canary Media)
Cooking up contradiction: Top appliance companies have quietly removed comparisons of gas and induction stoves’ air quality impacts from their websites as the industry fights a Colorado law mandating warning labels on gas stoves. (Grist)
That used-car smell: Used EV sales have risen 40% over the last year as buyers find they’re often cheaper than comparable gas-powered cars. (New York Times)
India’s carbon dioxide (CO2) emissions from its power sector fell by 1% year-on-year in the first half of 2025 and by 0.2% over the past 12 months, only the second drop in almost half a century.
As a result, India’s CO2 emissions from fossil fuels and cement grew at their slowest rate in the first half of the year since 2001 – excluding Covid – according to new analysis for Carbon Brief.
The analysis is the first of a regular new series covering India’s CO2 emissions, based on monthly data for fuel use, industrial production and power output, compiled from numerous official sources.
(See the regular series on China’s CO2 emissions, which began in 2019.)
Other key findings on India for the first six months of 2025 include:
The analysis also shows that emissions from India’s power sector could peak before 2030, if clean-energy capacity and electricity demand grow as expected.
The future of CO2 emissions in India is a key indicator for the world, with the country – the world’s most populous – having contributed nearly two-fifths of the rise in global energy-sector emissions growth since 2019.
In 2024, India was responsible for 8% of global energy-sector CO2 emissions, despite being home to 18% of the world’s population, as its per-capita output is far below the world average.
However, emissions have been growing rapidly, as shown in the figure below.
The country contributed 31% of global energy-sector emissions growth in the decade to 2024, rising to 37% in the past five years, due to a surge in the three-year period from 2021-23.
More than half of India’s CO2 output comes from coal used for electricity and heat generation, making this sector the most important by far for the country’s emissions.
The second-largest sector is fossil fuel use in industry, which accounts for another quarter of the total, while oil use for transport makes up a further eighth of India’s emissions.
India’s CO2 emissions from fossil fuels and cement grew by 8% per year from 2019 to 2023, quickly rebounding from a 7% drop in 2020 due to Covid.
Before the Covid pandemic, emissions growth had averaged 4% per year from 2010 to 2019, but emissions in 2023 and 2024 rose above the pre-pandemic trendline.
This was despite a slower average GDP growth rate from 2019 to 2024 than in the preceding decade, indicating that the economy became more energy- and carbon-intensive. (For example, growth in steel and cement outpaced the overall rate of economic growth.)
A turnaround came in the second half of 2024, when emissions only increased by 2% year-on-year, slowing down to 1% in the first half of 2025, as seen in the figure below.
The largest contributor to the slowdown was the power sector, which was responsible for 60% of the drop in emissions growth rates, when comparing the first half of 2025 with the years 2021-23.
Oil demand growth slowed sharply as well, contributing 20% of the slowdown. The only sectors to keep growing their emissions in the first half of 2025 were steel and cement production.
Another 20% of the slowdown was due to a reduction in coal and gas use outside the power, steel and cement sectors. This comprises construction, industries such as paper, fertilisers, chemicals, brick kilns and textiles, as well as residential and commercial cooking, heating and hot water.
This is all shown in the figure below, which compares year-on-year changes in emissions during the second half of 2024 and the first half of 2025, with the average for 2021-23.
Power sector emissions fell by 1% in the first half of 2025, after growing 10% per year during 2021-23 and adding more than 50m tonnes of CO2 (MtCO2) to India’s total every six months.
Oil product use saw zero growth in the first half of 2025, after rising 6% per year in 2021-23.
In contrast, emissions from coal burning for cement and steel production rose by 10% and 7%, respectively, while coal use outside of these sectors fell 2%.
Gas consumption fell 7% year-on-year, with reductions across the power and industrial sectors as well as other users. This was a sharp reversal of the 5% average annual growth in 2021-23.
The most striking shift in India’s sectoral emissions trends has come in the power sector, where coal consumption and CO2 emissions fell 0.2% in the 12 months to June and 1% in the first half of 2025, marking just the second drop in half a century, as shown in the figure below.
The reduction in coal use comes after more than a decade of break-neck growth, starting in the early 2010s and only interrupted by Covid in 2020. It also comes even as the country plans large amounts of new coal-fired generating capacity.
In the first half of 2025, total power generation increased by 9 terawatt hours (TWh) year-on-year, but fossil power generation fell by 29TWh, as output from solar grew 17TWh, from wind 9TWh, from hydropower by 9TWh and from nuclear by 3TWh.
Analysis of government data shows that 65% of the fall in fossil-fuel generation can be attributed to lower electricity demand growth, 20% to faster growth in non-hydro clean power and the remaining 15% to higher output at existing hydropower plants.
Slower growth in electricity usage was largely due to relatively mild temperatures and high rainfall, in contrast to the heatwaves of 2024. A slowdown in industrial sectors in the second quarter of the year also contributed.
In addition, increased rainfall drove the jump in hydropower generation. India received 42% above-normal rainfall from March to May 2025. (In early 2024, India’s hydro output had fallen steeply as a result of “erratic rainfall”.)
Lower temperatures and this abundant rainfall reduced the need for air conditioning, which is responsible for around 10% of the country’s total power demand. In the same period in 2024, demand surged due to record heatwaves and higher temperatures across the country.
The growth in clean-power generation was buoyed by the addition of a record 25.1GW of non-fossil capacity in the first half of 2025. This was a 69% increase compared with the previous period in 2024, which had also set a record.
Solar continues to dominate new installations, with 14.3GW of capacity added in the first half of the year coming from large scale solar projects and 3.2GW from solar rooftops.
Solar is also adding the majority of new clean-power output. Taking into account the average capacity factor of each technology, solar power delivered 62% of the additional annual generation, hydropower 16%, wind 13% and nuclear power 8%.
The new clean-energy capacity added in the first half of 2025 will generate record amounts of clean power. As shown in the figure below, the 50TWh per year from this new clean capacity is approaching the average growth of total power generation.
(When clean-energy growth exceeds total demand growth, generation from fossil fuels declines.)
India is expected to add another 16-17GW of solar and wind in the second half of 2025. Beyond this year, strong continued clean-energy growth is expected, towards India’s target for 500GW of non-fossil fuel capacity by 2030 (see below).
The first half of 2025 also saw a significant slowdown in India’s oil demand growth. After rising by 6% a year in the three years to 2023, it slowed to 4% in 2024 and zero in the first half of 2025.
The slowdown in oil consumption overall was predominantly due to slower growth in demand for diesel and “other oil products”, which includes bitumen.
In the first quarter of 2025, diesel demand actually fell, due to a decline in industrial activity, limited weather-related mobility and – reportedly – higher uptake of vehicles that run on compressed natural gas (CNG), as well as electricity (EVs).
Diesel demand growth increased in March to May, but again declined in June because of early and unusually severe monsoon rains in India, leading to a slowdown in industrial and mining activities, disrupted supply-chains and transport of raw material, goods and services.
The severe rains also slowed down road construction activity, which in turn curtailed demand for transportation, construction equipment and bitumen.
Weaker diesel demand growth in 2024 had reflected slower growth in economic activity, as growth rates in the industrial and agricultural sectors contracted compared to previous years.
Another important trend is that EVs are also cutting into diesel demand in the commercial vehicles segment, although this is not yet a significant factor in the overall picture.
EV adoption is particularly notable in major metropolitan cities and other rapidly emerging urban centres and in the logistics sector, where they are being preferred for short haul rides over diesel vans or light commercial vehicles.
EVs accounted for only 7.6% of total vehicle sales in the financial year 2024-25, up 22.5% year-on-year, but still far from the target of 30% by 2030.
However, any significant drop in diesel demand will be a function of adoption of EV for long-haul trucks, which account for 32% of the total CO2 emissions from the transport sector. Only 280 electric trucks were sold in 2024, reported NITI Aayog.
Trucks remain the largest diesel consumers. Moreover, truck sales grew 9.2% year-on-year in the second quarter of 2025, driven in part by India’s target of 75% farm mechanisation by 2047. This sales growth may outweigh the reduction in diesel demand due to EVs. Subsidies for electric tractors have seen some pilots, but demand is yet to take off.
Apart from diesel, petrol demand growth continued in the first half of 2025 at the same rate as in earlier years. Modest year-on-year growth of 1.3% in passenger vehicle sales could temper future increases in petrol demand, however. This is a sharp decline from 7.5% and 10% growth rates in sales in the same period in 2024 and 2023.
Furthermore, EVs are proving to be cheaper to run than petrol for two- and three-wheelers, which may reduce the sale of petrol vehicles in cities that show policy support for EV adoption.
As already noted, steel and cement were the only major sectors of India’s economy to see an increase in emissions growth in the first half of 2025.
While they were only responsible for around 12% of India’s total CO2 emissions from fossil fuels and cement in 2024, they have been growing quickly, averaging 6% a year for the past five years.
The growth in emissions accelerated in the first half of 2025, as cement output rose 10% and steel output 7%, far in excess of the growth in economic output overall.
Steel and cement growth accelerated further in July. A key demand driver is government infrastructure spending, which tripled from 2019 to 2024.
In the second quarter of 2025, the government’s capital expenditure increased 52% year-on-year. albeit from a low base during last year’s elections. This signals strong growth in infrastructure.
The government is targeting domestic steel manufacturing capacity of 300m tonnes (Mt) per year by 2030, from 200Mt currently, under the National Steel Policy 2017, supported by financial incentives for firms that meet production targets for high quality steel.
The government also imposed tariffs on steel imports in April and stricter quality standards for imports in June, in order to boost domestic production.
Government policies such as Pradhan Mantri Awas Yojna – a “housing for all” initiative under which 30m houses are to be built by FY30 – is further expected to lift demand for steel and cement.
The automotive sector in India is expected to grow at a fast pace, with sales expected to reach 7.5m units for passenger vehicle and commercial vehicle segments from 5.1m units in 2023, in addition to rapid growth in electric vehicles. This can be expected to be another key driver for growth of the steel sector, as 900 kg of steel is used per vehicle.
Without stringent energy efficiency measures and the adoption of cleaner fuel, the expected growth in steel and cement production could drive significant emissions growth from the sector.
Looking beyond this year, the analysis shows that CO2 from India’s power sector could peak before 2030, having previously been the main driver of emissions growth.
To date, India’s clean-energy additions have been lagging behind the growth in total electricity demand, meaning fossil-fuel demand and emissions from the sector have continued to rise.
However, this dynamic looks likely to change. In 2021, India set a target of having 500GW of non-fossil power generation capacity in place by 2030. Progress was slow at first, so meeting the target implies a substantial acceleration in clean-energy additions.
The country has been laying the groundwork for such an acceleration.
There was 234GW of renewable capacity in the pipeline as of April 2025, according to the Ministry of New and Renewable Energy. This includes 169GW already awarded contracts, of which 145GW is under construction, and an additional 65GW put out to tender. There is also 5.2GW of new nuclear capacity under construction.
If all of this is commissioned by 2030, then total non-fossil capacity would increase to 482GW, from 243GW at the end of June 2025, leaving a gap of just 18GW to be filled with new projects.
When the non-fossil capacity target was set in 2021, CREA assessed that the target would suffice to peak demand for coal in power generation before 2030. This assessment remains valid and is reinforced by the latest Central Electricity Authority (CEA) projection for the country’s “optimal power mix” in 2030, shown in the figure below.
In the CEA’s projection, the share of non-fossil power generation rises to 44% in the 2029-30 fiscal year, up from 25% in 2024-25. From 2025 to 2030, power demand growth, averaging 6% per year, is entirely covered from clean sources.
To accomplish this, the growth in non-fossil power generation would need to accelerate over time, meaning that towards the end of the decade, the growth in clean power supply would clearly outstrip demand growth overall – and so power generation from fossil fuels would fall.
While coal-power generation is expected to flatline, large amounts of new coal-power capacity is still being planned, because of the expected growth in peak electricity demand.
The post-Covid increase in electricity demand has given rise to a wave of new coal power plant proposals. Recent plans from the government target an increase in coal-power capacity by another 80-100GW by 2030-32, with 35GW already under construction as of July 2025.
The rationale for this is the increase in peak electricity loads, associated in particular with worsening heatwaves and growing use of air conditioning. The increase might yet prove unneeded.
Analysis by CREA shows that solar and wind are making an increasing contribution to meeting peak loads. This contribution will increase with the roll-out of solar power with integrated battery storage, the cost of which fell by 50-60% from 2023 to 2025.
The latest auction held in India saw solar power with battery storage bidding at prices, per unit of electricity generation, that were lower than the cost of new coal power.
This creates the opportunity to accelerate the decarbonisation of India’s power sector, by reducing the need for thermal power capacity.
The clean-energy buildout has made it possible for India to peak its power-sector emissions within the next few years, if contracted projects are built, clean-energy growth is maintained or accelerated beyond 2030 and demand growth remains within the government’s projections.
This would be a major turning point, as the power sector has been responsible for half of India’s recent emissions growth. In order to peak its emissions overall, however, India would still need to take further action to address CO2 from industry and transport.
With the end-of-September 2025 deadline nearing, India has yet to publish its international climate pledge (nationally determined contribution, NDC) for 2035 under the Paris Agreement, meaning its future emissions path, in the decades up to its 2070 net-zero goal, remains particularly uncertain.
The country is expected to easily surpass the headline climate target from its previous NDC, of cutting the emissions intensity of its economy to 45% below 2005 levels by 2030. As such, this goal is “unlikely to drive real world emission reductions”, according to Climate Action Tracker.
In July of this year, it met a 2030 target for 50% of installed power generating capacity to be from non-fossil sources, five years early.
This analysis is based on official monthly data for fuel consumption, industrial production and power generation from different ministries and government institutes.
Coal consumption in thermal power plants is taken from the monthly reports downloaded from the National Power Portal of the Ministry of Power. The data is compiled for the period January 2019 until June 2025. Power generation and capacity by technology and fuel on a monthly basis are sourced from the NITI data portal.
Coal use at steel and cement plants, as well as process emissions from cement production, are estimated using production indices from the Index of Eight Core Industries released monthly by the Office of Economic Adviser, assuming that changes in emissions follow production volumes.
These production indices were used to scale coal use by the sectors in 2022. To form a basis for using the indices, monthly coal consumption data for 2022 was constructed for the sectors using the annual total coal consumption reported in IEA World Energy Balances and monthly production data in a paper by Robbie Andrew, on monthly CO2 emission accounting for India.
Annual cement process emissions up to 2024 were also taken from Robbie Andrew’s work and scaled using the production indices. This approach better approximated changes in energy use and emissions reported in the IEA World Energy Balances, than did the amounts of coal reported to have been dispatched to the sectors, showing that production volumes are the dominant driver of short-term changes in emissions.
For other sectors, including aluminium, auto, chemical and petrochemical, paper and plywood, pharmaceutical, graphite electrode, sugar, textile, mining, traders and others, coal consumption is estimated based on data on despatch of domestic and imported coal to end users from statistical reports and monthly reports by the Ministry of Coal, as consumption data is not available.
The difference between consumption and dispatch is stock changes, which are estimated by assuming that the changes in coal inventories at end user facilities mirror those at coal mines, with end user inventories excluding power, steel and cement assumed to be 70% of those at coal mines, based on comparisons between our data and the IEA World Energy Balances.
Stock changes at mines are estimated as the difference between production at and despatch from coal mines, as reported by the Ministry of Coal.
In the case of the second quarter of the year 2025, data on domestic coal has been taken from the monthly reports by the Ministry of Coal. The regular data releases on coal imports have not taken place for the second quarter of 2025, for unknown reasons, so data was taken from commercial data providers Coal Hub and mjunction services ltd.
Product-wise petroleum product consumption data, as well as gas use by sector, was downloaded from the Petroleum Planning and Analysis Cell of the Ministry of Petroleum & Natural Gas.
As the fuel dispatch and consumption data is reported as physical volumes, calorific values are taken from IEA’s World Energy Balance and CO2 emission factors from 2006 IPCC Guidelines for National Greenhouse Gas Inventories.
Calorific values are assigned separately to different fuel types, including domestic and imported coal, anthracite and coke, as well as petrol, diesel and several other oil products.
Electric trucks can beat diesel-fueled ones on the cost of moving freight from California’s seaports to its inland distribution hubs — as long as the battery-powered vehicles can reliably recharge at both ends of their route. That fact is spurring a boom in the construction of truck-charging depots across the state.
On Thursday, EV Realty, a San Francisco-based charging site developer, broke ground on what will be one of California’s biggest fully grid-powered, fast-charging depots for electric trucks so far.
The company’s site in San Bernardino, located in a region known as the Inland Empire that’s crowded with distribution warehouses, will pull about 10 megawatts of power from the grid once it’s up and running in early 2026. It will be equipped with 76 direct-current fast-charging ports, including a number of ultra-high-capacity chargers capable of refilling a Tesla Semi truck in 30 minutes or less.
EV Realty has more large-scale depots in the works, including another in San Bernardino, one in Torrance near the Port of Long Beach, and a fourth in Livermore in Northern California. Thursday’s groundbreaking was accompanied by the announcement that the company had raised $75 million from private equity investor NGP, which also led a $28 million investment in 2022.
With that cash infusion, along with last year’s debut of a joint venture with GreenPoint Partners to develop $200 million in charging hubs, “we are fully capitalized against an underwritten, five-year business plan,” EV Realty CEO Patrick Sullivan told Canary Media.
That plan includes “five to seven more projects of the scale we have in San Bernardino, plus some smaller, more built-to-suit projects,” he said.
EV Realty does build and operate sites for passenger vehicles, such as the chargers it installed in a parking garage in Oakland, California, backed by power provider Ava Community Energy. But the company isn’t in the business of setting up open public charging sites that depend on drive-by traffic to earn money back, Sullivan said.
Instead, it’s signing deals with major freight carriers and fleet owners that want a dedicated spot to get their trucks charged and back on the road as quickly as possible.
That’s why EV Realty’s 76 chargers at its San Bernardino site are all dedicated to specific customers, he said. Of those, 72 are committed to those paying monthly rates on multiyear contracts. “Our customers will have stalls and amounts of power that are theirs 24/7, and we will have customers basing their operations out of that site,” he said.
The remaining four chargers, including those offering high-voltage megawatt charging systems, are “pull-through” slots where trucks towing trailers can get a quick recharge. “That pricing will be more of a pay-as-you-go, per kilowatt-hour — but all those trucks are registered at our site,” he said.
EV Realty is far from the only business building megawatt-scale truck-charging sites in California. Big EV truck depots are springing up around Southern California’s massive port complexes and along its major freight corridors, built by startups such as Terawatt Infrastructure, Forum Mobility, Voltera, WattEV, and Zeem; freight haulers like NFI Industries and Schneider National; and logistics operators such as Prologis.
Most of these depots are providing dedicated service to customers under contracts, but a few are starting to offer charging on a first-come, first-served basis. Greenlane, a joint venture of Daimler Truck North America, utility NextEra Energy, and investment firm BlackRock Alternatives, opened a 10-megawatt truck-charging site in Colton, a city neighboring San Bernardino, that’s meant to provide a more traditional “truck stop” service to vehicles needing to charge.
If anything, EV Realty has been “a little bit more slow and purposeful than others” in building its charging hubs, Sullivan said. But he insists that the broader truck-electrification project remains economically viable, despite the challenges erected by the Trump administration and Republicans in Congress.
There’s no doubt that electric trucking is experiencing a tough moment in California and across the country. The megalaw passed by Republicans in July cut short tax credits for commercial EVs and EV chargers that had been put in place by the 2022 Inflation Reduction Act. This has weakened support for purchasing battery-powered vehicles, which still cost two to three times more than their fossil-fueled counterparts, even if EVs’ lower fueling and maintenance costs can make them cheaper in the long run.
This summer, Republicans and the Trump administration also revoked Clean Air Act provisions that permitted California and 10 other states to set mandates forcing manufacturers to sell increasing numbers of zero-emissions trucks. Last month, major truck manufacturers sued California, seeking to extricate themselves from a clean-vehicle partnership agreement.
Meanwhile, the Trump administration’s trade policies have thrown “sand into the works” of the U.S. freight industry, Sullivan said. Imports are set to decline significantly under President Donald Trump’s tariffs on foreign-made goods, and the on-again, off-again nature of his taxes has scrambled long-term planning.
“Carriers, trucking, transportation companies are at the very front lines of a global trade war,” Sullivan said. “You have no predictability on how you can utilize your assets.”
In the face of that uncertainty, cementing charging for electric trucks along established routes becomes more important than ever, he said. Like many of its charging depot competitors, EV Realty is inking partnerships with other parties in the broader freight-hauling industry, such as its August agreement with Prologis to share and streamline access and software systems across both companies’ networks.
With dedicated charging in hand, freight companies and their customers can start to realize the underlying competitive economics of electric trucks, Sullivan said. “A carrier bidding on freight on a lane is bidding whatever their marginal operating cost is, above or below the cost of fuel,” he said. “If you can move short and regional haul, point to point, with an EV, you’re bidding on a marginal cost that’s lower than diesel.”
Cleveland has big ambitions to reduce its planet-warming emissions. But a massive steelmaking facility run by Cleveland-Cliffs, one of Ohio’s major employers, could make it difficult for the city to see those plans through.
The plant emits roughly 4.2 million metric tons of greenhouse gases each year, complicating Cleveland’s effort to achieve net-zero emissions by 2050, according to a report released by advocacy group Industrious Labs this summer. The plant is the city’s largest single source of planet-warming pollution.
Cleveland’s climate action plan is “bold and achievable,” said Hilary Lewis, steel director for Industrious Labs. But “if they want to achieve those goals, they have to take action on this Cleveland Works facility.”
As a major investment decision looms over an aging blast furnace at the facility, it’s unclear whether the company will move to cut its direct greenhouse gas emissions — or opt to reinvest in its existing coal-dependent processes.
Cliffs’ progress in reducing its nationwide emissions earned it recognition as a 2023 Goal Achiever in the Department of Energy’s Better Climate Challenge. As this year began, the company was set to slash emissions even further through projects supported by Biden-era legislation — the Inflation Reduction Act and the 2021 infrastructure law.
Then the Trump administration commenced its monthslong campaign of reneging on funding commitments for clean energy projects, including ones meant to ramp up the production of “green” hydrogen made with renewable energy. In June, Cliffs’ CEO Lourenco Goncalves backed away from a federally funded project to convert its Middletown Works in southwestern Ohio to produce green steel, saying there wouldn’t be a sufficient supply of hydrogen for the plant.
To Lewis, coauthor of the Industrious Labs report, that’s a weak excuse, because hydrogen production by other companies would have ramped up to supply the facility. “[Cliffs was] going to need so much hydrogen that they would be creating the demand,” she said.
Meanwhile, Cliffs’ Cleveland Works continues to spew emissions that drive climate change and harm human health. Industrious Labs’ modeling estimates that pollution from Cleveland Works is responsible for up to 39 early deaths per year, more than 1,700 lost work days, and more than 9,000 asthma cases. Cleveland ranks as the country’s fifth-worst city for people with asthma, according to the Asthma and Allergy Foundation of America.
Cleveland Works’ Blast Furnace #6 is a hulking vessel that removes impurities from iron ore by combining it with limestone and coke, a form of coal that burns at very high temperatures. Industrious Labs’ report notes the unit’s lining is nearing the end of its useful life.
To Industrious Labs, this presents an opportunity: The company could replace the old infrastructure with equipment that can process iron ore with natural gas or hydrogen instead of coal. Investing in this technology, called direct reduction, would cut the plant’s greenhouse gas emissions by more than 30% if natural gas is used. Using green hydrogen would slash emissions even more, the Industrious Labs team found.
The alternative is to just reline the furnace, which was the course Cliffs chose for the Cleveland facility’s Blast Furnace #5 in 2022.
Relining might provide small emissions cuts when measured per ton of steel, due to increased efficiencies, Lewis said. But ramped-up production from running more ore through the furnace could offset those reductions or even increase total emissions.
Cliffs did not respond to Canary Media’s repeated requests for comment for this story, and it has not yet publicly announced its plans for Blast Furnace #6.
To put itself on track with Cleveland’s emissions goals, however, the company would need to do more than just convert Blast Furnace #6 to the direct reduction process, Industrious Labs said.
The next step in the road map the group laid out would be for Cliffs to process refined iron ore into steel with an electric arc furnace — which can run on carbon-free power — instead of using the current basic oxygen equipment. Investing in green-hydrogen-based direct reduction and an electric arc furnace, instead of relining Blast Furnace #6, would increase emissions cuts to 47%, according to the Industrious Labs report.
Later steps would use direct reduction of iron and an electric arc furnace to refine and process the ore that is currently handled by Blast Furnace #5. Completing that work would cut Cleveland Works’ greenhouse gas emissions by 96%, according to the report.
The Industrious Labs analysis appears to lay out a credible decarbonization pathway, although not necessarily the only one, said Jenita McGowan, Cuyahoga County’s deputy chief of sustainability and climate. Cuyahoga County, which includes Cleveland, also has a goal of net-zero greenhouse gas emissions by 2050 and is in the process of finalizing the latest version of its climate action plan.
“My question about the paper is how feasible it truly is that Cleveland-Cliffs will deploy it in the near future,” McGowan said. Policy uncertainties at the federal level further complicate matters, she added.
For now, the city and county seem to be taking a pragmatic approach, focusing on achievements to date and encouraging future cuts wherever companies will make them.
But getting to net-zero for the industrial sector “will require more fundamental changes … [which] will take place over decades, rather than over a few years,” Cleveland’s climate action plan says. It also notes that low-carbon steel costs 40% more to produce compared to standard methods, “making it difficult for steelmakers to justify the investment in clean production.”
Cuyahoga County’s draft climate plan highlights Cliffs’ energy-efficiency improvements, including Cleveland Works’ use of some iron from the firm’s direct reduction plant in Toledo, Ohio. Cleveland Works also leverages much of the waste heat from its industrial activities to make electricity. The facility recently boosted that combined-heat-and-power generation by about 50 megawatts, the plan notes. That replaces electricity the plant would otherwise need from the grid, a majority of which still comes from fossil fuels.
Faster emissions reductions are certainly better, McGowan said. But the county also wants to make sure companies can stay in business as they decarbonize — especially Cliffs, one of the largest sources of commerce at the city’s port.
In Lewis’ view, decarbonizing Cleveland Works earlier rather than later would be a smart business move for Cliffs. “I think the biggest thing is staying competitive,” Lewis said.
One of Cliffs’ largest markets is supplying high-quality steel for automobiles, including electric vehicles, she added. In March, Hyundai announced plans to invest $6 billion in a new plant in Ascension Parish, Louisiana, that will produce low-carbon steel. As automakers face global pressure to source cleaner metal, Cliffs could find itself left behind, Lewis suggested.
The Industrious Labs report “opens the door for Cleveland to be a leader in clean steel,” Lewis said. Before that can happen, though, “there’s a lot of work to do.”
California’s Legislature has approved a slate of policies aimed at curbing high and rising electricity costs, involving everything from short-term relief for high summertime utility bills to public financing of transmission grids — a big accomplishment in the waning days of the session.
The affordability measures emerged as part of a sprawling energy and climate package negotiated by legislative leaders and Gov. Gavin Newsom’s office last week and passed by lawmakers Saturday. Newsom, a Democrat, now has until Oct. 12 to sign the bills into law.
“It’s just a massive end of session,” said state Sen. Josh Becker, a Democrat whose bill, SB 254, was included in the package. “We had all these planes in the air. Are they all going to crash, or are they going to land?”
Becker hopes the provisions in SB 254 will contain rapidly rising costs for the state’s three biggest utilities — Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric — which are in turn driving up rates for their customers. Those residents now pay roughly twice the U.S. average for their power, and nearly one in five are behind on paying their energy bills.
“Energy affordability was understood to be one of the top issues the Legislature needed to act on, due to massive rate increases and widespread customer outrage,” said Matthew Freedman, staff attorney at The Utility Reform Network, a consumer advocacy group that supported SB 254.
Among other things, that legislation aims to rein in how much utilities spend hardening their grids to reduce the risk of sparking wildfires, a major factor in cost increases. To that end, the bill would prohibit utilities from earning profits on some of the investments they make in wildfire-related upgrades.
It would also create a new “transmission accelerator” that enables utilities to use public financing to expand the state’s high-voltage grid rather than recoup those expenditures by charging customers. Those savings will take longer to kick in but could add up to billions of dollars a year, said Sam Uden, managing director of Net-Zero California, an advocacy group that cowrote a report last year examining how much utilities could save by relying on public financing.
“There’s a strategic role for public-sector investment to drive the clean energy transition,” he said. “We see this transmission financing as an embodiment of that viewpoint.”
SB 254 ended up as a 136-page document with a multitude of energy and climate provisions, Becker told Canary Media last week. But he highlighted one set of key cost-containment measures that the utilities had particularly resisted.
Utilities typically earn a profit by receiving a return on the investments they make in grid upkeep. Now, though, California’s big three utilities will have to finance a portion of what they spend hardening their grids via bonds — a process known as securitization.
Utilities “were kicking and screaming on that,” Becker said.
The amount to be financed through bonds was initially set to be $15 billion for all three utilities. But Freedman suggested that the utilities might have used their political clout last week to negotiate the final securitization requirement down to $6 billion, which is “a pretty big reduction,” he said.
Regardless, securitizing a portion of the growing grid-hardening costs will reduce pressure on utilities to increase rates in the future, said Merrian Borgeson, California policy director for climate and energy for the Natural Resources Defense Council, which supported the legislation. “I don’t know what the rates are going to be next year, but they’ll be lower,” she said.
Enabling public financing of transmission projects could deliver even more savings over time, Borgeson said. The “transmission accelerator” created by SB 254 for that purpose would be based out of the Governor’s Office of Business and Economic Development (GO-Biz). That entity would be authorized to pool state funds drawn from California’s cap-and-trade program and from a climate bond passed last year to lower the cost of capital for transmission projects.
The California Independent System Operator, which manages the state’s grid, estimates that California must invest between $46 billion and $63 billion into transmission over the next 20 years to meet its goal of achieving a carbon-free grid by 2045. Using public money to offset a portion of utilities’ capital spending on those projects could cut the costs of the currently planned long-range transmission buildout by more than half, saving customers as much as $3 billion a year, according to an October report from Net-Zero California and the Clean Air Task Force.
Just how much money could be saved will depend on how the accelerator structures its public-private financing, Freedman said. “SB 254 leaves open a range of possible outcomes on this front,” he added. “It depends on the ambitiousness of the implementation by this and future governors.”
The final days of this year’s session also saw lawmakers reauthorize the state’s decade-old cap-and-trade program, an initiative to reduce greenhouse gas emissions that was set to expire in 2030. AB 1207 and SB 840 would extend the program through 2045 and make a number of changes with significant implications for polluting industries, though regulators and lawmakers still need to work out the exact structures for executing the new rules, Borgeson said.
The bills also take an initial stab at reallocating funds raised by the cap-and-trade system to the myriad state programs and industry sectors jockeying for the money.
For example, one key affordability measure in AB 1207 institutes important changes to the “climate credit” now paid to utility customers out of funds collected from the cap-and-trade program.
Today, those credits are delivered to customers in twice-a-year lump-sum rebates. Under the new structure created by AB 1207, those rebates can be redirected to specifically help lower utility bills during summer months, when air conditioning drives up power consumption.
“Just think about the Central Valley,” Becker said during a virtual town-hall event in June, referring to a region of California that’s both hotter and poorer than the rest of the state. During summer heat waves, “it’s 100 degrees all day — and sometimes all night — in those areas. It’s literally a matter of life and death to keep the air conditioning on.”
AB 1207 will also redirect climate credits issued to gas utilities to support lowering summer electrical bills exclusively, through a process to be worked out by California utility regulators, Borgeson said. (Today, both gas utilities and electric utilities issue climate credits to their customers.)
That provision was strongly opposed by Sempra, the holding company of San Diego Gas & Electric and Southern California Gas Co., the state’s biggest gas-only utility. In an opposition letter, Sempra said the shift would create a “statewide subsidy requiring gas customers to fund bill relief for electric customers, worsening the high cost of living in California for millions of families.”
But climate advocates say the legislation aligns with California’s goal of shifting customers from using gas to using electricity. “This is a good idea, because it doesn’t need any more money,” Juliet Christian-Smith, Western states program director at the Union of Concerned Scientists, told Canary Media in July. Instead, “it’s redirecting money already in a pot to reduce electricity rates and enable the clean energy transition in a more affordable way.”
The U.S. does not have a big enough power grid to accommodate rising energy demand — a fact that’s making electricity less affordable and reliable nationwide.
But there’s broad public support for growing the grid and allowing more electricity, including cheap, clean energy, to come online.
So says a new survey of likely voters in Ohio and Pennsylvania — two states in the severely backlogged PJM Interconnection grid region — and Arkansas, Mississippi, and Missouri, which are covered by the Midcontinent Independent System Operator (MISO). The survey was conducted by polling firm Cygnal on behalf of the Conservative Energy Network.
Roughly three-fourths of likely voters support expanding the electric grid, the survey found. About two-thirds are in favor of adding more transmission lines to connect clean energy and strengthen grid reliability.
And nearly 90% of respondents are concerned about rising energy costs. A majority of surveyed Republicans, Democrats, and Independents said they are “very concerned.”
“This is not a partisan issue. … You don’t have to appeal to one side or another,” said Chris Lane, a senior partner at Cygnal, who previewed the findings at the National Conservative Energy Summit in Cleveland on Aug. 25.
He noted that the results stand out for their consistency between regions and among different groups — including political parties. Even so, the Trump administration has in recent months worked against grid expansion, not toward it.
Energy costs are climbing in part because of rising power demand from data centers and the electrification of buildings and vehicles. Bringing more electricity generation online — especially quick-to-build, low-cost wind and solar — could increase competition and lower prices under the basic principles of supply and demand.
But just as transportation planners need to make sure highways can handle increased road traffic, the Federal Energy Regulatory Commission and regional transmission operators need to make sure the grid has room for more electrons. That calls for more “lanes” in the form of added transmission lines, plus technologies to squeeze more capacity out of the system overall.
Currently, “there aren’t enough power lines, they’re not all in the right places, and the ones we have are too outdated to meet the rising power demand for electricity,” Evelyn Robinson, director of PJM affairs for the renewable-energy industry group MAREC Action, said during a separate panel at the conference in Cleveland.
While all of the United States faces delays in getting new energy onto the grid, the problem is worst in the PJM region, where hundreds of projects have been stalled in the queue for years. To deal with the backlog, the grid operator switched to a new interconnection process in 2023; as of June, PJM still had about 63 gigawatts of power, mostly clean energy, stuck in that “transition queue.”
Across the country, wind, solar, and battery storage make up most of the resources waiting to come online, and their “levelized cost of energy” is cheaper or on par with other electricity sources.
The Trump administration has called for “the rapid and efficient buildout” of energy infrastructure, including transmission lines and grid-enhancing technologies, “by easing Federal regulatory burdens.”
But the administration’s actions have so far had the opposite effect. A February executive order calling for review of independent agency rulings threatens the Federal Energy Regulatory Commission’s ability to expand transmission. And in July, the Trump administration canceled a $4.9 billion loan guarantee for the Grain Belt Express — the largest transmission line underway in the United States. The project aims to shuttle gigawatts of wind and solar power from the Great Plains to the East, and Sen. Martin Heinrich, D-N.M., has called the cancellation of its federal loan guarantee illegal.
The administration’s policies, including the One Big Beautiful Bill Act, are also expected to more than halve the amount of clean energy built over the next decade, further exacerbating concerns about soaring power prices and rising demand.
The survey results may help the Conservative Energy Network convince decision makers to take steps to expand the grid.
“To the best of my knowledge, this is the first poll that’s been done in the PJM area testing these things, and in the MISO south area,” said John Szoka, the group’s CEO, at the National Conservative Energy Summit.
The polling also gauged the persuasiveness of four statements to support grid expansion. The takeaways could inform how advocates and legislators work to boost public support for clean energy.
Among conservatives in Ohio and Pennsylvania, a message focused on lower costs was about 12 times more likely to shift someone’s opinion than one about preventing blackouts, Lane noted. Messages about increasing American energy production, preventing blackouts, and providing positive job and economic impacts for Americans were more likely to move liberals than one about lowering costs.
Opinions were more divided on whether the federal government, states, or private companies should pay for grid expansion, although a slight majority of respondents in both the PJM and MISO areas said they would be willing to pay a few dollars more per month in the short term if it would reduce outages and lower costs over time.
Respondents were also mixed on who should get to choose how electricity is produced. States, landowners, and local officials all ranked above federal authorities.
Clean energy, meanwhile, received only modest support on its own. About one-fourth of the Ohio and Pennsylvania respondents said using clean energy was one of their top two policy goals, with nearly one-fifth of those surveyed in Arkansas, Mississippi, and Missouri giving that response.
Ultimately, affordability and reliability were the clear consensus energy policy priorities for poll respondents in both the PJM and MISO areas.
With the federal government standing in the way of both grid expansion and clean energy development, however, it will be tough for the voters to get the improvements they want.
LAS VEGAS — There were plenty of reasons to think that this year’s RE+, the U.S. solar industry’s biggest annual gathering, would be a gloomy and downtrodden affair.
The Trump administration had declared an energy emergency, then set about reducing energy supply by going after renewables projects. The massive spending law yanked nearly seven years of tax credits for wind and solar. The White House arbitrarily halted construction on two major offshore wind farms that had all their permits in order, raising the fear that it might block other fully approved projects. Tariffs have changed the price of parts that go into clean energy equipment on a sometimes weekly basis. The cleantech bankruptcies have been relentless: Powin, Sunnova, Mosaic, Northvolt, Li-Cycle, Nikola, to name a few.
“I can’t think of a time when we have been subject to quite as much of a brutal swing as we’ve been in now,” said Abby Ross Hopper, president and CEO of the Solar Energy Industries Association, which puts on the conference.
But when I got to the exhibit hall at the Venetian Expo, it stretched farther than I’d ever seen at a clean energy show, and I heard rumors of additional halls above and below. The exhibitors even sprawled across a sunwashed bridge to Caesar’s Forum, where vendors of flow batteries and other alternative technologies hawked their wares, quite fittingly, from the periphery of the event.
Final attendance for the show hit 37,000, just shy of the record 40,000 from the previous two years, and other metrics broke records. The mood on the floor, in the halls, and at the myriad Vegas afterparties reflected an industry that had taken some punches, had lost some nice things, but was nonetheless charging forward, resolute and battle-tested.
“If you’d asked me in May how I was feeling about RE+, I would have a very different answer,” Hopper noted at a roundtable with journalists a few days into the show. “But we have more exhibitors than we’ve ever had in our history, and we have more registration revenue than we’ve ever had in our history. … [People] are really, really hungry for information and for a vision for what’s coming next.”
Judging by this year’s dire headlines, the show’s ebullient atmosphere does not seem entirely rational. Of course, even teetering startups try to project confidence among peers, customers, and especially journalists. And the overstimulated Vegas backdrop inspires a particular strain of optimism, the kind that encourages you to light cash on fire and feel lucky for the opportunity.
But after three days of roaming the frenetic halls, I came to see this year’s positive outlook as warranted. The general consensus among conference goers seemed to be that though political headwinds are blowing hard, economic tailwinds are blowing harder. Here are three reasons why I think they are right.
With the federal tax credits cut short, fewer solar projects will get built, and costs will rise for the ones that still go forward, passing on higher energy bills to American consumers.
But, with a little distance from the sting of this summer’s legislative setbacks, many solar and energy storage professionals believe losses in the policy arena are counterbalanced by increasingly rosy outlooks in the marketplace.
“I think people tend to over-orient on the policy story, and under-orient on the economic and financial story,” said Alfred Johnson, CEO of the clean energy financing platform Crux, as we sipped espressos outside the hubbub of the cavernous expo halls.
Johnson’s company launched as a marketplace for tax credit transferability, which was created by the Inflation Reduction Act, but has expanded into other forms of financing, like debt and tax equity. That perch gives him visibility into clean energy project economics and the flows of capital into the sector. He ticked off a series of key factors defining the current energy market: Electricity prices are way up; solar and battery keeps getting cheaper while improving performance; gas prices are rising as the Trump administration promotes exports; gas turbine prices are rising due to intense competition from buyers.
In short, it’s a bad time to be someone who uses electricity in America, despite President Donald Trump’s campaign promise to cut energy prices. That means, though, that it’s a great time to be someone who sells power.
Even better for power producers, the biggest new customers — data centers — have the price sensitivity of a ravenous grizzly bear. They’re trying, with the enthusiastic support of the White House, to win a global arms race to unlock artificial superintelligence, whatever that means. Facing such civilizational stakes, the hyperscalers aren’t going to quibble over nickels and dimes.
Even with elevated electricity prices, hyperscalers still have to pay a lot more for the “graphics processing units” that train and run their AI models, Johnson noted. And once they’ve paid for those GPUs, they want to use them as much as possible, which means gobbling up as much electricity as they can get.
“The value of being faster on delivering the model … is worth so much more … than the additional cost of energy, which means that the marginal demand in a lot of these markets is the data centers, who are not price sensitive,” Johnson said.
Solar is clearly the cheapest source of new electricity production. But what matters most now is speed to market, and here solar and batteries easily trounce all other commercially viable sources of power. Taking mass-produced panels and parts and assembling them in a field is fundamentally easier than constructing a traditional large power plant. And it’s a hell of a lot easier than some of the hyperscalers’ other ideas, like building nonexistent nuclear fusion plants, or nonexistent small modular reactors, or restarting a long-shuttered nuclear reactor at the notorious Three Mile Island plant.
These dynamics led some of my fellow conference goers to muse about a counterfactual choice: Would you rather have strong federal policy tailwinds and an unfavorable market, or booming market fundamentals but unfavorable policy? Nine months ago, the industry enjoyed both. Trump ended those good times, but the robust market serves to mollify the pain of his policy attacks.
SEIA has strived to welcome energy storage into the fold, and diversification from solar alone looks especially prescient these days. Rooftop solar is struggling in a big way, with the federal onslaught and friendly fire from states like California, and large-scale developers are racing to cram in a bumper crop of projects before tax credits disappear next July. (Projects that start construction after that must be operating by the end of 2027 to qualify for the federal incentives.) But storage companies evaded the policy setbacks of their solar-powered brethren, and are building toward yet another record year of construction.
“Right now, we are seeing all of the factors are very supportive to storage,” said Johnson. “Demand is going up, there’s more of a focus on having dispatchable power. It got tax credits for the first time in the IRA … and then it retained the tax credits in [the One Big Beautiful Bill Act].”
The budget law preserves the battery-installation tax credits through 2033, with the stipulation that projects prove they don’t excessively rely on parts or corporate support from China. That sparked initial concerns from some analysts that these Foreign Entity of Concern rules (FEOC) could be enforced in a way that strangles development arbitrarily.
A few months later, many storage developers are encouraged by how clearly the text of the law lays out the boxes to check. Even so, compliance creates extra work for the American companies trying to expand the capacity of the grid, and the law does not explicitly encourage domestic manufacturing, since the rules are anti-China rather than pro-America.
Trump’s tariffs also pose a unique threat to storage, because so many of the battery cells used in these projects come from China. The U.S. has only just begun building supply chains for lithium ferrous phosphate, the battery chemistry now favored for grid storage. LG opened an LFP factory in Michigan this summer; AESC did so in an old Nissan Leaf battery plant in Tennessee, and Tesla is working on one in Nevada slated to start up early next year.
Now, said Brian Hayes, CEO of storage developer Key Capture Energy, it’s common for suppliers to offer three battery-sourcing options: China, Southeast Asia, and domestic. Buyers can toggle based on current tariff rates, U.S. manufacturing premiums, and the FEOC obligations of a particular project. Once the new FEOC rules kick in, though, the industry will need to move away from Chinese-made battery cells.
“I’m feeling a lot more positive today than I was six months ago,” said Hayes, whose company has built 40 megawatts in New York and 580 megawatts in Texas. “We ended up in a good place.”
That’s not to say storage developers can afford to get complacent.
“We can’t rest on our laurels,” Hayes mused. “We always have to be paying attention to what else could come.”
The Biden administration combined trade policy with methodical domestic incentives to reshore the manufacturing of clean energy equipment and other tech, like semiconductors. Trump supports the resurgence of domestic manufacturing in theory, but his primary tactic for that goal has been frequently shifting and legally dubious tariffs. These policies raise the price for materials that American manufacturers need to make their products and for the equipment required to build new factories, and they undermine the long-term certainty that reassures investors.
Still, the reshoring of clean energy supply chains has continued, and signs touting FEOC compliance have become a new form of currency on the expo hall floors.
Nextracker, the homegrown solar-tracking manufacturer and publicly traded cleantech success story, used the occasion of the conference to publicize its acquisition of Origami Solar for $53 million. That marked a refreshing shift in an era when cleantech acquisitions have tended to feature bankruptcy auctions or the kind of firesale where participants abashedly refuse to share the purchase price.
Origami developed a steel frame technology to replace the usual aluminum frames that wrap around solar panels. This enhances structural integrity as solar modules grow ever larger and more powerful. Indiana manufacturer Bila Solar, for instance, recently tapped Origami to frame its new 550-watt solar module.
But beyond preventing bending or buckling, the acquisition is a domestic-production play. The U.S. aluminium industry has cratered since the 1980s, so aluminum frames are now largely an import business, subject to all the vagaries of trade in 2025. The U.S. still makes things with steel though; Nextracker has been working with partners to open steel plants around the country to produce the torque tubes that carry the panels through their daily rotation. Origami manufactures in the U.S. too; now Nextracker can offer a more complete domestic solar package, making it easier for developers to clinch the 10% tax credit adder for Made-in-America content.
Over in Texas, module manufacturer T1 Energy signed a deal a few weeks back with glass producer Corning for a lot more than oven-safe casserole dishes. Corning subsidiary Hemlock Semiconductor will make hyper-pure polysilicon and carve it into solar wafers in Michigan, to supply T1’s forthcoming solar cell factory starting in the second half of 2026.
I tracked down Alex Zhu, CEO of ES Foundry, which in January opened one of the only currently operating solar cell factories in the country. Production from the 1-gigawatt line in Greenwood, South Carolina, is already sold out until 2027, Zhu said. He has greenlit a 2-gigawatt expansion, slated to be fully running by June 2026, to meet demand from domestic panel producers. A digital display by the company’s booth advertised “No FEOC Ownership. No FEOC Board. No FEOC Funding.”
Zhu stressed that it wasn’t easy opening a cell factory when the U.S. lacks a supply chain for some of the industrial inputs that are abundant and cheap in China. One of the key gases used in the process cost him 120 times the rate it sells for in that country’s solar industry centers. But Zhu nonetheless raised investment, launched the company, and built the factory all in the last two years.
Sales of these U.S.-made cells very much depend on the domestic content adder to compete with cheaper imports: “That’s the only drive to make the economic sense to buy a more expensive domestic module and domestic cell,” Zhu noted.
That’s a clear risk factor, because that perk will disappear along with the solar tax credits. But tax rules say that if developers start construction before next July 4, they can take up to four years to finish projects. That means projects could get built with both the credit and the domestic content adder through the end of the decade.
It’s hard to know what context manufacturers will be operating in at that point. But Zhu noted that “after five years, we definitely need to move to the next generation.” Much like semiconductor fabs, solar cell factories must regularly refresh themselves to keep up with technological advancements.
Longer-term certainty would be nice for the generational effort to reshore the solar supply chain, but maybe five busy years of manufacturing is enough to look forward to right now.
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