The blackout that took down the Iberian grid serving Spain and Portugal in April was the result of a number of smaller interacting problems, according to an investigation by the Spanish government. The report concludes that several steps meant to address a small instability made matters worse, eventually leading to a self-reinforcing cascade where high voltages caused power plants to drop off the grid, thereby increasing the voltage further. Critically, the report suggests that the Spanish grid operator had an unusually low number of plants on call to stabilize matters, and some of the ones it did have responded poorly.
The full report will be available later today; however, the government released a summary ahead of its release. The document includes a timeline of the events that triggered the blackout, as well as an analysis of why grid management failed to keep it in check. It also notes that a parallel investigation checked for indications of a cyberattack and found none.
Oscillations and a cascade
The document notes that for several days prior to the blackout, the Iberian grid had been experiencing voltage fluctuations—products of a mismatch between supply and demand—that had been managed without incident. These continued through the morning of April 28 until shortly after noon, when an unusual frequency oscillation occurred. This oscillation has been traced back to a single facility on the grid, but the report doesn’t identify it or even indicate its type, simply referring to it as an “instalación.”
The grid operators responded in a way that suppressed the oscillations but increased the voltages on the grid. About 15 minutes later, a weakened version of this oscillation occurred again, followed shortly thereafter by oscillations at a different frequency, this one with properties that are commonly seen on European grids. That prompted the grid operators to take corrective steps again, which increased the voltages on the grid.
The Iberian grid is capable of handling this sort of thing. But the grid operator only scheduled 10 power plants to handle voltage regulation on the 28th, which the report notes is the lowest total it had committed to in all of 2025 up to that point. The report found that a number of those plants failed to respond properly to the grid operators, and a few even responded in a way that contributed to the surging voltages.
Floating solar panels appear to conserve water while generating green electricity.
The Gila River Indian Community in Arizona has lined 3,000 feet of their canals with solar panels. Credit: Jake Bolster/Inside Climate News
GILA RIVER INDIAN RESERVATION, Ariz.—About 33 miles south of Phoenix, Interstate 10 bisects a line of solar panels traversing the desert like an iridescent snake. The solar farm’s shape follows the path of a canal, with panels serving as awnings to shade the gently flowing water from the unforgiving heat and wind of the Sonoran Desert.
The panels began generating power last November for the Akimel O’otham and Pee Posh tribes—known together as the Gila River Indian Community, or GRIC—on their reservation in south-central Arizona, and they are the first of their kind in the US. The community is studying the effects of these panels on the water in the canal, hopeful that they will protect a precious resource from the desert’s unflinching sun and wind.
In September, GRIC is planning to break ground on another experimental effort to conserve water while generating electricity: floating solar. Between its canal canopies and the new project that would float photovoltaic panels on a reservoir it is building, GRIC hopes to one day power all of its canal and irrigation operations with solar electricity, transforming itself into one of the most innovative and closely watched water users in the West in the process.
The community’s investments come at a critical time for the Colorado River, which supplies water to about 40 million people across seven Western states, Mexico and 30 tribes, including GRIC. Annual consumption from the river regularly exceeds its supply, and a decadeslong drought, fueled in part by climate change, continues to leave water levels at Lake Powell and Lake Mead dangerously low.
Covering water with solar panels is not a new idea. But for some it represents an elegant mitigation of water shortages in the West. Doing so could reduce evaporation, generate more carbon-free electricity and require dams to run less frequently to produce power.
But, so far, the technology has not been included in the ongoing Colorado River negotiations between the Upper Basin states of Colorado, New Mexico, Utah, and Wyoming, the Lower Basin states of Arizona, California, and Nevada, tribes and Mexico. All are expected to eventually agree on cuts to the system’s water allocations to maintain the river’s ability to provide water and electricity for residents and farms, and keep its ecosystem alive.
“People in the US don’t know about [floating solar] yet,” said Scott Young, a former policy analyst in the Nevada state legislature’s counsel bureau. “They’re not willing to look at it and try and factor it” into the negotiations.
Several Western water managers Inside Climate News contacted for this story said they were open to learning more about floating solar—Colorado has even studied the technology through pilot projects. But, outside of GRIC’s project, none knew of any plans to deploy floating solar anywhere in the basin. Some listed costly and unusual construction methods and potentially modest water savings as the primary obstacles to floating solar maturing in the US.
A tantalizing technology with tradeoffs
A winery in Napa County, California, deployed the first floating solar panels in the US on an irrigation pond in 2007. The country was still years away from passing federal legislation to combat the climate crisis, and the technology matured here haltingly. As recently as 2022, according to a Bloomberg analysis, most of the world’s 13 gigawatts of floating solar capacity had been built in Asia.
Unlike many Asian countries, the US has an abundance of undeveloped land where solar could be constructed, said Prateek Joshi, a research engineer at the National Renewable Energy Laboratory (NREL) who has studied floating solar, among other forms of energy. “Even though [floating solar] may play a smaller role, I think it’s a critical role in just diversifying our energy mix and also reducing the burden of land use,” he said.
Credit: Paul Horn/Inside Climate News
This February, NREL published a study that found floating solar on the reservoirs behind federally owned dams could provide enough electricity to power 100 million US homes annually, but only if all the developable space on each reservoir were used.
Lake Powell could host almost 15 gigawatts of floating solar using about 23 percent of its surface area, and Lake Mead could generate over 17 gigawatts of power on 28 percent of its surface. Such large-scale development is “probably not going to be the case,” Joshi said, but even if a project used only a fraction of the developable area, “there’s a lot of power you could get from a relatively small percentage of these Colorado Basin reservoirs.”
The study did not measure how much water evaporation floating solar would prevent, but previous NREL research has shown that photovoltaic panels—sometimes called “floatovoltaics” when they are deployed on reservoirs—could also save water by changing the way hydropower is deployed.
Some of a dam’s energy could come from solar panels floating on its reservoir to prevent water from being released solely to generate electricity. As late as December, when a typical Western dam would be running low, lakes with floating solar could still have enough water to produce hydropower, reducing reliance on more expensive backup energy from gas-fired power plants.
Joshi has spoken with developers and water managers about floating solar before, and said there is “an eagerness to get this [technology] going.” The technology, however, is not flawless.
Solar arrays can be around 20 percent more expensive to install on water than land, largely because of the added cost of buoys that keep the panels afloat, according to a 2021 NREL report. The water’s cooling effect can boost panel efficiency, but floating solar panels may produce slightly less energy than a similarly sized array on land because they can’t be tilted as directly toward the sun as land-based panels.
And while the panels likely reduce water loss from reservoirs, they may also increase a water body’s emissions of greenhouse gases, which in turn warm the climate and increase evaporation. This January, researchers at Cornell University found that floating solar covering more than 70 percent of a pond’s surface area increased the water’s CO2 and methane emissions. These kinds of impacts “should be considered not only for the waterbody in which [floating solar] is deployed but also in the broader context of trade-offs of shifting energy production from land to water,” the study’s authors wrote.
“Any energy technology has its tradeoffs,” Joshi said, and in the case of floating solar, some of its benefits—reduced evaporation and land use—may not be easy to express in dollars and cents.
Silver buckshot
There is perhaps no bigger champion for floating solar in the West than Scott Young. Before he retired in 2016, he spent much of his 18 years working for the Nevada Legislature researching the effects of proposed legislation, especially in the energy sector.
On an overcast, blustery May day in southwest Wyoming near his home, Young said that in the past two years he has promoted the technology to Colorado River negotiators, members of Congress, environmental groups and other water managers from the seven basin states, all of whom he has implored to consider the virtues of floating solar arrays on Lake Powell and Lake Mead.
Young grew up in the San Francisco Bay area, about 40 miles, he estimated, from the pioneering floating solar panels in Napa. He stressed that he does not have any ties to industry; he is just a concerned Westerner who wants to diversify the region’s energy mix and save as much water as possible.
But so far, when he has been able to get someone’s attention, Young said his pitch has been met with tepid interest. “Usually the response is: ‘Eh, that’s kind of interesting,’” said Young, dressed in a black jacket, a maroon button-down shirt and a matching ball cap that framed his round, open face. “But there’s no follow-up.”
The Bureau of Reclamation “has not received any formal proposals for floating solar on its reservoirs,” said an agency spokesperson, who added that the bureau has been monitoring the technology.
In a 2021 paper published with NREL, Reclamation estimated that floating solar on its reservoirs could generate approximately 1.5 terawatts of electricity, enough to power about 100 million homes. But, in addition to potentially interfering with recreation, aquatic life, and water safety, floating solar’s effect on evaporation proved difficult to model broadly.
So many environmental factors determine how water is lost or consumed in a reservoir—solar intensity, wind, humidity, lake circulation, water depth, and temperature—that the study’s authors concluded Reclamation “should be wary of contractors’ claims of evaporation savings” without site-specific studies. Those same factors affect the panels’ efficiency, and in turn, how much hydropower would need to be generated from the reservoir they cover.
The report also showed the Colorado River was ripe with floating solar potential—more than any other basin in the West. That’s particularly true in the Upper Basin, where Young has been heartened by Colorado’s approach to the technology.
In 2023, the state passed a law requiring several agencies to study the use of floating solar. Last December, the Colorado Water Conservation Board published its findings, and estimated that the state could save up to 407,000 acre feet of water by deploying floating solar on certain reservoirs. An acre foot covers one acre with a foot of water, or 325,851 gallons, just about three year’s worth of water for a family of four.
When Young saw the Colorado study quantifying savings from floating solar, he felt hopeful. “407,000 acre feet from one state,” he said. “I was hoping that would catch people’s attention.”
Saving that much water would require using over 100,000 acres of surface water, said Cole Bedford, the Colorado Water Conservation Board’s chief operating officer, in an email. “On some of these reservoirs a [floating solar] system would diminish the recreational value such that it would not be appropriate,” he said. “On others, recreation, power generation, and water savings could be balanced.”
Colorado is not planning to develop another project in the wake of this study, and Bedford said that the technology is not a silver bullet solution for Colorado River negotiations.
“While floating solar is one tool in the toolkit for water conservation, the only true solution to the challenges facing the Colorado River Basin is a shift to supply-driven, sustainable uses and operations,” he said.
Some of the West’s largest and driest cities, like Phoenix and Denver, ferry Colorado River water to residents hundreds of miles away from the basin using a web of infrastructure that must reliably operate in unforgiving terrain. Like their counterparts at the state level, water managers in these cities have heard floatovoltaics floated before, but they say the technology is currently too immature and costly to be deployed in the US.
Lake Pleasant, which holds some of the Central Arizona Project’s Colorado River Water, is also a popular recreation space, complicating its floating solar potential.
Credit: Jake Bolster/Inside Climate News
Lake Pleasant, which holds some of the Central Arizona Project’s Colorado River Water, is also a popular recreation space, complicating its floating solar potential. Credit: Jake Bolster/Inside Climate News
In Arizona, the Central Arizona Project (CAP) delivers much of the Colorado River water used by Phoenix, Tucson, tribes, and other southern Arizona communities with a 336-mile canal running through the desert, and Lake Pleasant, the company’s 811,784-acre-foot reservoir.
Though CAP is following GRIC’s deployment of solar over canals, it has no immediate plans to build solar over its canal, or Lake Pleasant, according to Darrin Francom, CAP’s assistant general manager for operations, power, engineering, and maintenance, in part because the city of Peoria technically owns the surface water.
Covering the whole canal with solar to save the 4,000 acre feet that evaporates from it could be prohibitively expensive for CAP. “The dollar cost per that acre foot [saved] is going to be in the tens of, you know, maybe even hundreds of thousands of dollars,” Francom said, mainly due to working with novel equipment and construction methods. “Ultimately,” he continued, “those costs are going to be borne by our ratepayers,” which gives CAP reason to pursue other lower-cost ways to save water, like conservation programs, or to seek new sources.
An intake tower moves water into and out of the dam at Lake Pleasant.
Credit: Jake Bolster/Inside Climate News
An intake tower moves water into and out of the dam at Lake Pleasant. Credit: Jake Bolster/Inside Climate News
The increased costs associated with building solar panels on water instead of on land has made such projects unpalatable to Denver Water, Colorado’s largest water utility, which moves water out of the Colorado River Basin and through the Rocky Mountains to customers on the Front Range. “Floating solar doesn’t pencil out for us for many reasons,” said Todd Hartman, a company spokesperson. “Were we to add more solar resources—which we are considering—we have abundant land-based options.”
GRIC spent about $5.6 million, financed with Inflation Reduction Act grants, to construct 3,000 feet of solar over a canal, according to David DeJong, project director for the community’s irrigation district.
Young is aware there is no single solution to the problems plaguing the Colorado River Basin, and he knows floating solar is not a perfect technology. Instead, he thinks of it as a “silver buckshot,” he said, borrowing a term from John Entsminger, general manager for the Southern Nevada Water Authority—a technology that can be deployed alongside a constellation of behavioral changes to help keep the Colorado River alive.
Given the duration and intensity of the drought in the West and the growing demand for water and clean energy, Young believes the US needs to act now to embed this technology into the fabric of Western water management going forward.
As drought in the West intensifies, “I think more lawmakers are going to look at this,” he said. “If you can save water in two ways—why not?”
“We’re not going to know until we try”
If all goes according to plan, GRIC’s West Side Reservoir will be finished and ready to store Colorado River water by the end of July. The community wants to cover just under 60 percent of the lake’s surface area with floating solar.
“Do we know for a fact that this is going to be 100 percent effective and foolproof? No,” said DeJong, GRIC’s project director for its irrigation district. “But we’re not going to know until we try.”
The Gila River Indian Community spent about $5.6 million, with the help of Inflation Reduction Act grants, to cover a canal with solar.
Credit: Jake Bolster/Inside Climate News
The Gila River Indian Community spent about $5.6 million, with the help of Inflation Reduction Act grants, to cover a canal with solar. Credit: Jake Bolster/Inside Climate News
GRIC’s panels will have a few things going for them that projects on lakes Mead or Powell probably wouldn’t. West Side Reservoir will not be open to recreation, limiting the panels’ impacts on people. And the community already has the funds—Inflation Reduction Act grants and some of its own money—to pay for the project.
But GRIC’s solar ambitions may be threatened by the hostile posture toward solar and wind energy from the White House and congressional Republicans, and the project is vulnerable to an increasingly volatile economy. Since retaking office, President Donald Trump, aided by billionaire Elon Musk, has made deep cuts inrenewableenergy grants at the Environmental Protection Agency. It is unclear whether or to what extent the Bureau of Reclamation has slashed its grant programs.
“Under President Donald J. Trump’s leadership, the Department is working to cut bureaucratic waste and ensure taxpayer dollars are spent efficiently,” said a spokesperson for the Department of the Interior, which oversees Reclamation. “This includes ensuring Bureau of Reclamation projects that use funds from the Infrastructure Investments and Jobs Act and the Inflation Reduction Act align with administration priorities. Projects are being individually assessed by period of performance, criticality, and other criteria. Projects have been approved for obligation under this process so that critical work can continue.”
And Trump’s tariffs could cause costs to balloon beyond the community’s budget, which could either reduce the size of the array or cause delays in soliciting proposals, DeJong said.
While the community will study the panels over canals to understand the water’s effects on solar panel efficiency, it won’t do similar research on the panels on West Side Reservoir, though DeJong said they have been in touch with NREL about studying them. The enterprise will be part of the system that may one day offset all the electrical demand and carbon footprint of GRIC’s irrigation system.
“The community, they love these types of innovative projects. I love these innovative projects,” said GRIC Governor Stephen Roe Lewis, standing in front of the canals in April. Lewis had his dark hair pulled back in a long ponytail and wore a blue button down that matched the color of the sky.
“I know for a fact this is inspiring a whole new generation of water protectors—those that want to come back and they want to go into this cutting-edge technology,” he said. “I couldn’t be more proud of our team for getting this done.”
DeJong feels plenty of other water managers across the West could learn from what is happening at GRIC. In fact, the West Side Reservoir was intentionally constructed near Interstate 10 so that people driving by on the highway could one day see the floating solar the community intends to build there, DeJong said.
“It could be a paradigm shift in the Western United States,” he said. “We recognize all of the projects we’re doing are pilot projects. None of them are large scale. But it’s the beginning.”
Under those circumstances, the rest of the difference will be made up for with fossil fuels. Running counter to recent trends, the use of natural gas dropped during the first three months of 2025. This means that the use of coal rose nearly as quickly as demand, up by 23 percent compared to the same time period in 2024.
Despite the rise in coal use, the fraction of carbon-free electricity held steady year-over-year, with wind/solar/hydro/nuclear accounting for 43 percent of all power put on the US grid. That occurred despite small drops in nuclear and hydro production.
Solar power also passed a key milestone in 2025, although it requires digging through the statistics to realize it. In terms of power on the grid, there was less solar than hydro. But the Energy Information Agency also estimates the production from small-scale solar, like the kind you’d find on people’s roofs. Some of this never enters the grid and instead simply offsets demand locally (in that it gets used by the house that sits beneath the panels). If you combine the TW-hr produced by small- and grid-scale solar, however, they surpass the production from hydropower by a significant margin.
This surge in solar comes on top of a 30 percent increase in production the year prior. The growth curve is clearly not slowing down.
That dynamic is also not likely to change immediately in response to cuts to tax breaks for renewable power that were part of the budget package passed by the House of Representatives on Thursday, and not only because it’s possible that some Republican Senators might object to budget changes that will harm their states. Solar power in most areas is now cheaper than alternatives, even without subsidies, and any power plant (renewable or otherwise) will likely see its costs rise due to the tariff environment. Finally, the tax breaks don’t expire immediately, and most power plant construction requires significant advanced planning.
All of those factors should continue the solar boom for at least a couple more years before all of the expected changes apply the brakes.
On Monday, however, the company announced that the hold had been lifted and construction would resume. But as with the hold itself, the reasons for its end remain mysterious. The Bureau of Ocean Energy Management page for the project was only updated with a new letter on Tuesday. That letter indicates a review of its approval is ongoing, but construction can resume during the review.
The Department of the Interior has not addressed the change and has not responded to a request for comment. A post by Interior Secretary Burgum doesn’t mention Empire Wind but does suggest the governor of New York will approve a pipeline: “I am encouraged by Governor Hochul’s comments about her willingness to move forward on critical pipeline capacity.”
That suggests there was a deal that allowed Empire Wind to resume construction in return for a pipeline for fossil fuels. The New York Times suggests that this is a reference to the proposed Constitution Pipeline, which was planned to move natural gas from Pennsylvania to eastern New York but was cancelled in 2020 due to state opposition.
But Governor Kathy Hochul has not made any comments about a willingness to move forward on any pipelines. Instead, Hochul’s statement on Empire Wind is very vague, saying that she “reaffirmed that New York will work with the Administration and private entities on new energy projects that meet the legal requirements under New York law.”
So while it’s good news that construction on Empire Wind has restarted, the whole process has been problematic, driven by apparently arbitrary decisions that the government has refused to justify.
China has been installing renewable energy at a spectacular rate, and now has more renewable capacity than the next 13 countries combined, and four times that of its closest competitor, the US. Yet, so far at least, that hasn’t been enough to offset the rise of fossil fuel use in that country. But a new analysis by the NGO Carbon Brief suggests things may be changing, as China’s emissions have now dropped over the past year, showing a one percent decline compared to the previous March. The decline is largely being led by the power sector, where growth in renewables has surged above rising demand.
This isn’t the first time that China’s emissions have gone down over the course of a year, but in all previous cases the cause was primarily economic—driven by things like the COVID pandemic or the 2008 housing crisis. The latest shift, however, was driven largely by the country’s energy sector, which saw a two percent decline in emissions over the past year.
China’s emissions have shown a slight decline over the last year, despite economic growth and rising demand for electricity. Credit: Carbon Brief
Carbon Brief put the report together using data from several official government sources, including the National Bureau of Statistics of China, National Energy Administration of China, and the China Electricity Council. Projections for future growth come from the China Wind Energy Association and the China Photovoltaic Industry Association.
The data indicate that the most recent monthly peak in emissions was March of 2024. Since then, total emissions have gone down by one percent—a change the report notes is small enough that it could easily reverse should conditions change. The report highlights, however, that the impact of renewables appears to be accelerating. The growth of clean power in the first quarter of 2025 was enough to drive a 1.6 percent drop compared to the same quarter a year before, outpacing the overall average of a one percent decline.
As President Donald Trump signed a slew of executive orders Tuesday aimed at keeping coal power alive in the United States, he repeatedly blamed his predecessor, Democrats, and environmental regulations for the industry’s dramatic contraction over the past two decades.
But across the country, state and local officials and electric grid operators have been confronting a factor in coal’s demise that is not easily addressed with the stroke of a pen: its cost.
For example, Maryland’s only remaining coal generating station, Talen Energy’s 1.3-gigawatt Brandon Shores plant, will be staying open beyond its previously planned June 1 shutdown, under a deal that regional grid operator PJM brokered earlier this year with the company, state officials, and the Sierra Club.
Talen had decided to close the plant two years ago because it determined that running the plant was uneconomical. But PJM said the plant was necessary to maintain the reliability of the grid. To keep Brandon Shores open while extra transmission is built to bolster the grid, Maryland ratepayers will be forced to pay close to $1 billion.
“There’s some people who say that Brandon Shores was retiring because of Maryland’s climate policy,” says David Lapp, who leads the Maryland Office of People’s Counsel, which fought the deal on behalf of ratepayers. “But it was purely a decision made by a generation company that’s operating in a free market.”
Cheaper power from natural gas and renewable energy has been driving down use of coal across the United States for roughly 20 years. Coal plants now provide about 15 percent of the nation’s electricity, down from more than 50 percent in 2000.
In some cases, state and local officials have raised concerns over whether the loss of coal plants will make the grid more vulnerable to blackouts. In Utah, for example, the Intermountain Power Agency’s 1,800-megawatt coal power facility in Utah’s West Desert is the largest US coal plant that was scheduled to shut down this year, according to the US Energy Information Administration. IPA is going forward with its plan to switch to natural gas plants that can be made cleaner-operating by using hydrogen fuel. But under a new law, IPA will shut down the coal plants in a state where it can be easily restarted, said IPA spokesman John Ward. The Utah legislature voted last month in favor of a new process in which the state of Utah will look for new customers and possibly a new operator to keep the coal plant running.
The UK has transitioned to a lower-emission grid. Now comes the hard part.
With the closure of its last coal-fired power plant, Ratcliffe-on-Soar, on September 30, 2024, the United Kingdom has taken a significant step toward its net-zero goals. It’s no small feat to end the 142-year era of coal-powered electricity in the country that pioneered the Industrial Revolution. Yet the UK’s journey away from coal has been remarkably swift, with coal generation plummeting from 40 percent of the electricity mix in 2012 to just two percent in 2019, and finally to zero in 2024.
As of 2023, approximately half of UK electricity generation comes from zero-carbon sources, with natural gas serving as a transitional fuel. The UK aims to cut greenhouse gas emissions by 42 percent to 48 percent by 2027 and achieve net-zero by 2050. The government set a firm target to generate all of its electricity from renewable sources by 2040, emphasizing offshore wind and solar energy as the keys.
What will things look like in the intervening years, which will lead us from today to net-zero? Everyone’s scenario, even when based in serious science, boils down to a guessing game. Yet some things are more certain than others, the most important of these factors being the ones that are on solid footing beneath all of the guesswork.
Long-term goals
The closure of all UK coal-fired power stations in 2024 marked a crucial milestone in the nation’s decarbonization efforts. Coal was once the dominant source of electricity generation, but its contribution to greenhouse gas emissions made it a primary target for phase-out. The closure of these facilities has significantly reduced the UK’s carbon footprint and paved the way for cleaner energy sources.
With transition from coal, natural gas is set to play a crucial role as a “transition fuel.” The government’s “British Energy Security Strategy” argued that gas must continue to be an important part of the energy mix. It positioned gas as the “glue” that holds the electricity system together during the transition. Even the new Starmer government recognizes that, as the country progresses towards net-zero by 2050, the country may still use about a quarter of the gas it currently consumes.
Natural gas emits approximately half as much carbon dioxide as coal when combusted, making it a cleaner alternative during the shift to renewable energy sources. In 2022, natural gas accounted for around 40 percent of the UK’s electricity generation, while coal contributed less than two percent. This transition phase is deemed by the government to be essential as the country ramps up the capacity of renewable energy sources, particularly wind and solar power, to fill gaps left by the reduction of fossil fuels. The government aims to phase out natural gas that’s not coupled with carbon capture by 2035, but in the interim, it serves as a crucial bridge, ensuring energy security while reducing overall emissions.
But its role is definitely intended to be temporary; the UK’s long-term energy goal is to reduce reliance on all fossil fuels (starting with imported supplies), pushing for a rapid transition to cleaner, domestic sources of energy.
The government’s program has five primary targets:
Fully decarbonizing the power system (2035)
Ending the sale of new petrol and diesel cars (2035)
Achieving “Jet Zero” – net-zero UK aviation emissions (2050)
Creating 30,000 hectares of new woodland per year (2025)
Generating 50 percent of its total electricity from renewable sources by 2030
Offshore wind energy has emerged as this strategy’s key component, with significant investments being made in new wind farms. Favorable North Sea wind conditions have immense potential. In recent years, a surge in offshore wind investment has translated into several large-scale developments in advanced planning stages or now under construction.
The government has set a target to increase offshore wind capacity to 50 GW by 2030, up from around 10 GW currently. This initiative is supported by substantial financial commitments from both the public and private sectors. Recent investment announcements underscore the UK’s commitment to this goal and the North Sea’s central role in it. In 2023, the government announced plans to invest $25 billion (20 billion British pounds) in carbon capture and offshore wind projects in the North Sea over the next two decades. This investment is expected to create up to 50,000 jobs and help position the UK as a leader in clean energy technologies.
This was part of investments totaling over $166 million (133 million pounds) to support the development of new offshore wind farms, which are expected to create thousands of jobs and stimulate local economies.
In 2024, further investments were announced to support the expansion of offshore wind capacity. The government committed to holding annual auctions for new offshore wind projects to meet its goal of quadrupling offshore wind capacity by 2030. These investments are part of a broader strategy to leverage the UK’s expertise in offshore industries and transition the North Sea from an oil and gas hub to a clean-energy powerhouse.
Offshore wind
As the UK progresses toward its net-zero target, it faces both challenges and opportunities. While significant progress has been made in decarbonizing the power sector, the national government’s Climate Change Committee has noted that emissions reductions need to accelerate in other sectors, particularly agriculture, land use, and waste. However, with continued investment in renewable energy and supportive policies, the UK is positioning itself to become a leader in the global transition to a low-carbon economy.
Looking ahead, 2025 promises to be a landmark year for the UK’s green energy sector, with further investment announcements and projects in the pipeline.
The Crown Estate, which manages the seabed around England, Wales, and Northern Ireland, has made significant strides in facilitating new leases for offshore wind development. In 2023, the Crown Estate Scotland announced the successful auction of seabed leases for new offshore wind projects, totaling a capacity of 5 gigawatts. And in 2024, the government plans to hold its next major leasing round, which could see the deployment of an additional 7 GW of offshore wind capacity.
The UK government also approved plans for the Dogger Bank Wind Farm, which will be the world’s largest offshore wind farm when completed. Located off the coast of Yorkshire, this massive project will ultimately generate enough electricity to power millions of homes. Dogger is a joint venture linking SSE Renewables, Equinor, and Vattenfall.
This is in line with the government’s broader strategy to enhance energy independence and resilience, particularly in light of the geopolitical uncertainties affecting global energy markets. The UK’s commitment to renewable energy is not merely an environmental imperative; it is also an economic opportunity. By harnessing the vast potential of the North Sea, the UK aims not only to meet its net-zero targets but also to drive economic growth and job creation in the green energy sector, ensuring a sustainable future for generations to come.
Recognizing wind’s importance, the UK government launched a 2024 consultation on plans to develop a new floating wind energy sector.
The transition to a greener economy is projected to create up to 400,000 jobs by 2030 across various sectors, including manufacturing, installation, and maintenance of renewable energy technologies.
Its growing offshore wind industry is expected to attract billions in investment, solidifying the UK’s position as a leader in the global green energy market. The government’s commitment to offshore wind development, underscored by substantial investments in 2023 and anticipated announcements for 2024, signals a robust path forward.
Moving away from gas
Still, the path ahead remains challenging, requiring a multifaceted approach that balances economic growth, energy security, and environmental sustainability.
With the transition from coal, natural gas is now poised to play the central role as a bridge fuel. While natural gas emits fewer greenhouse gases than coal, it is still a fossil fuel and contributes to carbon emissions. However, in the short term, natural gas can help maintain energy security and provide a reliable source of electricity during periods of low renewable energy output. Additionally, natural gas can be used to produce hydrogen, potentially coupled with carbon capture, enabling a clean energy carrier that can be integrated into the existing energy infrastructure.
To support the country’s core clean energy goals, the government is implementing specific initiatives, although the pace has been quite uneven. The UK Emissions Trading Scheme (ETS) is being strengthened to incentivize industrial decarbonization. The government has also committed to investing in key green industries alongside offshore wind: carbon capture, usage and storage (CCUS), and nuclear energy.
Combined, these should allow the UK to limit its use of natural gas and capture the emissions associated with any remaining fossil fuel use.
While both countries are relying heavily on wind power, the UK’s energy-generation transformations are different from Germany’s. While both governments push to make some progress on the path to net-zero carbon emissions, their approaches and timelines differ markedly.
Energiewende, Germany’s energy transition, is characterized by what some critics consider to be overly ambitious goals for achieving net greenhouse gas neutrality by 2045. Those critics think that the words don’t come close to matching the required levels of either government or private sector financial commitment. Together with the Bundestag, the chancellor has set interim targets to reduce emissions by 65 percent by 2030 and 88 percent by 2040 (both compared to 1990 levels). Germany’s energy mix is heavily reliant on renewables, with a goal of sourcing 80 percent of its electricity from renewable energy by 2030—and achieving 100 percent by 2035.
However, Germany has faced challenges due to continued reliance on coal and natural gas, which made it difficult to reach its emissions goals.
The UK, however, appears to be ahead in terms of immediate reductions in coal use and the integration of renewables into its energy mix. Germany’s path is more complex, as it balances its energy transition with energy security concerns, particularly in light of how Russia’s war affects gas supplies.
We can expect next year’s numbers to also show a large growth in solar production, as the EIA says that the US saw record levels of new solar installations in 2024, with 37 gigawatts of new capacity. Since some of that came online later in the year, it’ll produce considerably more power next year. And, in its latest short-term energy analysis, the EIA expects to see over 20 GW of solar capacity added in each of the next two years. New wind capacity will push that above 30 GW of renewable capacity each of these years.
The past few years of solar installations have led to remarkable growth in its power output. Credit: John Timer
That growth will, it’s expected, more than offset continued growth in demand, although that growth is expected to be somewhat slower than we saw in 2024. It also predicts about 15 GW of coal will be removed from the grid during those two years. So, even without any changes in policy, we’re likely to see a very dynamic grid landscape over the next few years.
But changes in policy are almost certainly on the way. The flurry of executive orders issued by the Trump administration includes a number of energy-related changes. These include defining “energy” in a way that excludes wind and solar, an end to offshore wind leasing and the threat to terminate existing leases, and a re-evaluation of the allocation of funds from some of the Biden administration’s energy-focused laws.
In essence, this sets up a clash among economics, state policies, and federal policy. Even without any subsidies, wind and solar are the cheapest ways to produce electricity in much of the US. In addition, a number of states have mandates that will require the use of more renewable energy. At the same time, the permitting process for the plants and their grid connections will often require approvals at the federal level, and it appears to be official policy to inhibit renewables when possible. And a number of states are also making attempts to block new renewable power installations.
It’s going to be a challenging period for everyone involved in renewable energy.
Set to be killed by Trump, the rules mostly lock in existing trends.
In April last year, the Environmental Protection Agency released its latest attempt to regulate the carbon emissions of power plants under the Clean Air Act. It’s something the EPA has been required to do since a 2007 Supreme Court decision that settled a case that started during the Clinton administration. The latest effort seemed like the most aggressive yet, forcing coal plants to retire or install carbon capture equipment and making it difficult for some natural gas plants to operate without capturing carbon or burning green hydrogen.
Yet, according to a new analysis published in Thursday’s edition of Science, they wouldn’t likely have a dramatic effect on the US’s future emissions even if they were to survive a court challenge. Instead, the analysis suggests the rules serve more like a backstop to prevent other policy changes and increased demand from countering the progress that would otherwise be made. This is just as well, given that the rules are inevitably going to be eliminated by the incoming Trump administration.
A long time coming
The net result of a number of Supreme Court decisions is that greenhouse gasses are pollutants under the Clean Air Act, and the EPA needed to determine whether they posed a threat to people. George W. Bush’s EPA dutifully performed that analysis but sat on the results until its second term ended, leaving it to the Obama administration to reach the same conclusion. The EPA went on to formulate rules for limiting carbon emissions on a state-by-state basis, but these were rapidly made irrelevant because renewable power and natural gas began displacing coal even without the EPA’s encouragement.
Nevertheless, the Trump administration replaced those rules with ones designed to accomplish even less, which were thrown out by a court just before Biden’s inauguration. Meanwhile, the Supreme Court stepped in to rule on the now-even-more-irrelevant Obama rules, determining that the EPA could only regulate carbon emissions at the level of individual power plants rather than at the level of the grid.
All of that set the stage for the latest EPA rules, which were formulated by the Biden administration’s EPA. Forced by the court to regulate individual power plants, the EPA allowed coal plants that were set to retire within the decade to continue to operate as they have. Anything that would remain operational longer would need to either switch fuels or install carbon capture equipment. Similarly, natural gas plants were regulated based on how frequently they were operational; those that ran less than 40 percent of the time could face significant new regulations. More than that, and they’d have to capture carbon or burn a fuel mixture that is primarily hydrogen produced without carbon emissions.
While the Biden EPA’s rules are currently making their way through the courts, they’re sure to be pulled in short order by the incoming Trump administration, making the court case moot. Nevertheless, people had started to analyze their potential impact before it was clear there would be an incoming Trump administration. And the analysis is valuable in the sense that it will highlight what will be lost when the rules are eliminated.
By some measures, the answer is not all that much. But the answer is also very dependent upon whether the Trump administration engages in an all-out assault on renewable energy.
Regulatory impact
The work relies on the fact that various researchers and organizations have developed models to explore how the US electric grid can economically meet demand under different conditions, including different regulatory environments. The researchers obtained nine of them and ran them with and without the EPA’s proposed rules to determine their impact.
On its own, eliminating the rules has a relatively minor impact. Without the rules, the US grid’s 2040 carbon dioxide emissions would end up between 60 and 85 percent lower than they were in 2005. With the rules, the range shifts to between 75 and 85 percent—in essence, the rules reduce the uncertainty about the outcomes that involve the least change.
That’s primarily because of how they’re structured. Mostly, they target coal plants, as these account for nearly half of the US grid’s emissions despite supplying only about 15 percent of its power. They’ve already been closing at a rapid clip, and would likely continue to do so even without the EPA’s encouragement.
Natural gas plants, the other major source of carbon emissions, would primarily respond to the new rules by operating less than 40 percent of the time, thus avoiding stringent regulation while still allowing them to handle periods where renewable power underproduces. And we now have a sufficiently large fleet of natural gas plants that demand can be met without a major increase in construction, even with most plants operating at just 40 percent of their rated capacity. The continued growth of renewables and storage also contributes to making this possible.
One irony of the response seen in the models is that it suggests that two key pieces of the Inflation Reduction Act (IRA) are largely irrelevant. The IRA provides benefits for the deployment of carbon capture and the production of green hydrogen (meaning hydrogen produced without carbon emissions). But it’s likely that, even with these credits, the economics wouldn’t favor the use of these technologies when alternatives like renewables plus storage are available. The IRA also provides tax credits for deploying renewables and storage, pushing the economics even further in their favor.
Since not a lot changes, the rules don’t really affect the cost of electricity significantly. Their presence boosts costs by an estimated 0.5 to 3.7 percent in 2050 compared to a scenario where the rules aren’t implemented. As a result, the wholesale price of electricity changes by only two percent.
A backstop
That said, the team behind the analysis argues that, depending on other factors, the rules could play a significant role. Trump has suggested he will target all of Biden’s energy policies, and that would include the IRA itself. Its repeal could significantly slow the growth of renewable energy in the US, as could continued problems with expanding the grid to incorporate new renewable capacity.
In addition, the US is seeing demand for electricity rise at a faster pace in 2023 than in the decade leading up to it. While it’s still unclear whether that’s a result of new demand or simply weather conditions boosting the use of electricity in heating and cooling, there are several factors that could easily boost the use of electricity in coming years: the electrification of transport, rising data center use, and the electrification of appliances and home heating.
Should these raise demand sufficiently, then it could make continued coal use economical in the absence of the EPA rules. “The rules … can be viewed as backstops against higher emissions outcomes under futures with improved coal plant economics,” the paper suggests, “which could occur with higher demand, slower renewables deployment from interconnection and permitting delays, or higher natural gas prices.”
And it may be the only backstop we have. The report also notes that a number of states have already set aggressive emissions reduction targets, including some for net zero by 2050. But these don’t serve as a substitute for federal climate policy, given that the states that are taking these steps use very little coal in the first place.
John is Ars Technica’s science editor. He has a Bachelor of Arts in Biochemistry from Columbia University, and a Ph.D. in Molecular and Cell Biology from the University of California, Berkeley. When physically separated from his keyboard, he tends to seek out a bicycle, or a scenic location for communing with his hiking boots.
What’s with the sudden interest in nuclear power among tech titans?
Fuel pellets flow down the reactor (left), as gas transfer heat to a boiler (right). Credit: X-energy
On Tuesday, Google announced that it had made a power purchase agreement for electricity generated by a small modular nuclear reactor design that hasn’t even received regulatory approval yet. Today, it’s Amazon’s turn. The company’s Amazon Web Services (AWS) group has announced three different investments, including one targeting a different startup that has its own design for small, modular nuclear reactors—one that has not yet received regulatory approval.
Unlike Google’s deal, which is a commitment to purchase power should the reactors ever be completed, Amazon will lay out some money upfront as part of the agreements. We’ll take a look at the deals and technology that Amazon is backing before analyzing why companies are taking a risk on unproven technologies.
Money for utilities and a startup
Two of Amazon’s deals are with utilities that serve areas where it already has a significant data center footprint. One of these is Energy Northwest, which is an energy supplier that sends power to utilities in the Pacific Northwest. Amazon is putting up the money for Energy Northwest to study the feasibility of adding small modular reactors to its Columbia Generating Station, which currently houses a single, large reactor. In return, Amazon will get the right to purchase power from an initial installation of four small modular reactors. The site could potentially support additional reactors, which Energy Northwest would be able to use to meet demands from other users.
The deal with Virginia’s Dominion Energy is similar in that it would focus on adding small modular reactors to Dominion’s existing North Anna Nuclear Generating Station. But the exact nature of the deal is a bit harder to understand. Dominion says the companies will “jointly explore innovative ways to advance SMR development and financing while also mitigating potential cost and development risks.”
Should either or both of these projects go forward, the reactor designs used will come from a company called X-energy, which is involved in the third deal Amazon is announcing. In this case, it’s a straightforward investment in the company, although the exact dollar amount is unclear (the company says Amazon is “anchoring” a $500 million round of investments). The money will help finalize the company’s reactor design and push it through the regulatory approval process.
Small modular nuclear reactors
X-energy is one of several startups attempting to develop small modular nuclear reactors. The reactors all have a few features that are expected to help them avoid the massive time and cost overruns associated with the construction of large nuclear power stations. In these small reactors, the limited size allows them to be made at a central facility and then be shipped to the power station for installation. This limits the scale of the infrastructure that needs to be built in place and allows the assembly facility to benefit from economies of scale.
This also allows a great deal of flexibility at the installation site, as you can scale the facility to power needs simply by adjusting the number of installed reactors. If demand rises in the future, you can simply install a few more.
The small modular reactors are also typically designed to be inherently safe. Should the site lose power or control over the hardware, the reactor will default to a state where it can’t generate enough heat to melt down or damage its containment. There are various approaches to achieving this.
X-energy’s technology is based on small, self-contained fuel pellets called TRISO particles for TRi-structural ISOtropic. These contain both the uranium fuel and a graphite moderator and are surrounded by a ceramic shell. They’re structured so that there isn’t sufficient uranium present to generate temperatures that can damage the ceramic, ensuring that the nuclear fuel will always remain contained.
The design is meant to run at high temperatures and extract heat from the reactor using helium, which is used to boil water and generate electricity. Each reactor can produce 80 megawatts of electricity, and the reactors are designed to work efficiently as a set of four, creating a 320 MW power plant. As of yet, however, there are no working examples of this reactor, and the design hasn’t been approved by the Nuclear Regulatory Commission.
Why now?
Why is there such sudden interest in small modular reactors among the tech community? It comes down to growing needs and a lack of good alternatives, even given the highly risky nature of the startups that hope to build the reactors.
It’s no secret that data centers require enormous amounts of energy, and the sudden popularity of AI threatens to raise that demand considerably. Renewables, as the cheapest source of power on the market, would be one way of satisfying that growth, but they’re not ideal. For one thing, the intermittent nature of the power they supply, while possible to manage at the grid level, is a bad match for the around-the-clock demands of data centers.
The US has also benefitted from over a decade of efficiency gains keeping demand flat despite population and economic growth. This has meant that all the renewables we’ve installed have displaced fossil fuel generation, helping keep carbon emissions in check. Should newly installed renewables instead end up servicing rising demand, it will make it considerably more difficult for many states to reach their climate goals.
Finally, renewable installations have often been built in areas without dedicated high-capacity grid connections, resulting in a large and growing backlog of projects (2.6 TW of generation and storage as of 2023) that are stalled as they wait for the grid to catch up. Expanding the pace of renewable installation can’t meet rising server farm demand if the power can’t be brought to where the servers are.
These new projects avoid that problem because they’re targeting sites that already have large reactors and grid connections to use the electricity generated there.
In some ways, it would be preferable to build more of these large reactors based on proven technologies. But not in two very important ways: time and money. The last reactor completed in the US was at the Vogtle site in Georgia, which started construction in 2009 but only went online this year. Costs also increased from $14 billion to over $35 billion during construction. It’s clear that any similar projects would start generating far too late to meet the near-immediate needs of server farms and would be nearly impossible to justify economically.
This leaves small modular nuclear reactors as the least-bad option in a set of bad options. Despite many startups having entered the space over a decade ago, there is still just a single reactor design approved in the US, that of NuScale. But the first planned installation saw the price of the power it would sell rise to the point where it was no longer economically viable due to the plunge in the cost of renewable power; it was canceled last year as the utilities that would have bought the power pulled out.
The probability that a different company will manage to get a reactor design approved, move to construction, and manage to get something built before the end of the decade is extremely low. The chance that it will be able to sell power at a competitive price is also very low, though that may change if demand rises sufficiently. So the fact that Amazon is making some extremely risky investments indicates just how worried it is about its future power needs. Of course, when your annual gross profit is over $250 billion a year, you can afford to take some risks.
John is Ars Technica’s science editor. He has a Bachelor of Arts in Biochemistry from Columbia University, and a Ph.D. in Molecular and Cell Biology from the University of California, Berkeley. When physically separated from his keyboard, he tends to seek out a bicycle, or a scenic location for communing with his hiking boots.
Enlarge/ The Ratcliffe-on-Soar plant is set to shut down for good today.
On Monday, the UK will see the closure of its last operational coal power plant, Ratcliffe-on-Soar, which has been operating since 1968. The closure of the plant, which had a capacity of 2,000 megawatts, will bring an end to the history of the country’s coal use, which started with the opening of the first coal-fired power station in 1882. Coal played a central part in the UK’s power system in the interim, in some years providing over 90 percent of its total electricity.
But a number of factors combined to place coal in a long-term decline: the growth of natural gas-powered plants and renewables, pollution controls, carbon pricing, and a government goal to hit net-zero greenhouse gas emissions by 2050.
From boom to bust
It’s difficult to overstate the importance of coal to the UK grid. It was providing over 90 percent of the UK’s electricity as recently as 1956. The total amount of power generated continued to climb well after that, reaching a peak of 212 terawatt hours of production by 1980. And the construction of new coal plants was under consideration as recently as the late 2000s. According to the organization Carbon Brief’s excellent timeline of coal use in the UK, continuing the use of coal with carbon capture was given consideration.
But several factors slowed the use of fuel ahead of any climate goals set out by the UK, some of which have parallels to the US’s situation. The European Union, which included the UK at the time, instituted new rules to address acid rain, which raised the cost of coal plants. In addition, the exploitation of oil and gas deposits in the North Sea provided access to an alternative fuel. Meanwhile, major gains in efficiency and the shift of some heavy industry overseas cut demand in the UK significantly.
Through their effect on coal use, these changes also lowered employment in coal mining. The mining sector has sometimes been a significant force in UK politics, but the decline of coal reduced the number of people employed in the sector, reducing its political influence.
These had all reduced the use of coal even before governments started taking any aggressive steps to limit climate change. But, by 2005, the EU implemented a carbon trading system that put a cost on emissions. By 2008, the UK government adopted national emissions targets, which have been maintained and strengthened since then by both Labour and Conservative governments up until Rishi Sunak, who was voted out of office before he had altered the UK’s trajectory. What started as a pledge for a 60 percent reduction in greenhouse gas emissions by 2050 now requires the UK to hit net zero by that date.
Enlarge/ Renewables, natural gas, and efficiency have all squeezed coal off the UK grid.
These have included a floor on the price of carbon that ensures fossil-powered plants pay a cost for emissions that’s significant enough to promote the transition to renewables, even if prices in the EU’s carbon trading scheme are too low for that. And that transition has been rapid, with the total generations by renewables nearly tripling in the decade since 2013, heavily aided by the growth of offshore wind.
How to clean up the power sector
The trends were significant enough that, in 2015, the UK announced that it would target the end of coal in 2025, despite the fact that the first coal-free day on the grid wouldn’t come until two years after. But two years after that landmark, however, the UK was seeing entire weeks where no coal-fired plants were active.
To limit the worst impacts of climate change, it will be critical for other countries to follow the UK’s lead. So it’s worthwhile to consider how a country that was committed to coal relatively recently could manage such a rapid transition. There are a few UK-specific factors that won’t be possible to replicate everywhere. The first is that most of its coal infrastructure was quite old—Ratcliffe-on-Soar dates from the 1960s—and so it required replacement in any case. Part of the reason for its aging coal fleet was the local availability of relatively cheap natural gas, something that might not be true elsewhere, which put economic pressure on coal generation.
Another key factor is that the ever-shrinking number of people employed by coal power didn’t exert significant pressure on government policies. Despite the existence of a vocal group of climate contrarians in the UK, the issue never became heavily politicized. Both Labour and Conservative governments maintained a fact-based approach to climate change and set policies accordingly. That’s notably not the case in countries like the US and Australia.
But other factors are going to be applicable to a wide variety of countries. As the UK was moving away from coal, renewables became the cheapest way to generate power in much of the world. Coal is also the most polluting source of electrical power, providing ample reasons for regulation that have little to do with climate. Forcing coal users to pay even a fraction of its externalized costs on human health and the environment serve to make it even less economical compared to alternatives.
If these later factors can drive a move away from coal despite government inertia, then it can pay significant dividends in the fight to limit climate change. Inspired in part by the success in moving its grid off coal, the new Labour government in the UK has moved up its timeline for decarbonizing its power sector to 2030 (up from the previous Conservative government’s target of 2035).
While solar power is growing at an extremely rapid clip, in absolute terms, the use of natural gas for electricity production has continued to outpace renewables. But that looks set to change in 2024, as the US Energy Information Agency (EIA) has run the numbers on the first half of the year and found that wind, solar, and batteries were each installed at a pace that dwarfs new natural gas generators. And the gap is expected to get dramatically larger before the year is over.
Solar, batteries booming
According to the EIA’s numbers, about 20 GW of new capacity was added in the first half of this year, and solar accounts for 60 percent of it. Over a third of the solar additions occurred in just two states, Texas and Florida. There were two projects that went live that were rated at over 600 MW of capacity, one in Texas, the other in Nevada.
Next up is batteries: The US saw 4.2 additional gigawatts of battery capacity during this period, meaning over 20 percent of the total new capacity. (Batteries are treated as the equivalent of a generating source by the EIA since they can dispatch electricity to the grid on demand, even if they can’t do so continuously.) Texas and California alone accounted for over 60 percent of these additions; throw in Arizona and Nevada, and you’re at 93 percent of the installed capacity.
The clear pattern here is that batteries are going where the solar is, allowing the power generated during the peak of the day to be used to meet demand after the sun sets. This will help existing solar plants avoid curtailing power production during the lower-demand periods in the spring and fall. In turn, this will improve the economic case for installing additional solar in states where its production can already regularly exceed demand.
Wind power, by contrast, is running at a more sedate pace, with only 2.5 GW of new capacity during the first six months of 2024. And for likely the last time this decade, additional nuclear power was placed on the grid, at the fourth 1.1 GW reactor (and second recent build) at the Vogtle site in Georgia. The only other additions came from natural gas-powered facilities, but these totaled just 400 MW, or just 2 percent of the total of new capacity.
Enlarge/ Wind, solar, and batteries are the key contributors to new capacity in 2024.
The EIA has also projected capacity additions out to the end of 2024 based on what’s in the works, and the overall shape of things doesn’t change much. However, the pace of installation goes up as developers rush to get their project operational within the current tax year. The EIA expects a bit over 60 GW of new capacity to be installed by the end of the year, with 37 GW of that coming in the form of solar power. Battery growth continues at a torrid pace, with 15 GW expected, or roughly a quarter of the total capacity additions for the year.
Wind will account for 7.1 GW of new capacity, and natural gas 2.6 GW. Throw in the contribution from nuclear, and 96 percent of the capacity additions of 2024 are expected to operate without any carbon emissions. Even if you choose to ignore the battery additions, the fraction of carbon-emitting capacity added remains extremely small, at only 6 percent.
Gradual shifts on the grid
Obviously, these numbers represent the peak production of these sources. Over a year, solar produces at about 25 percent of its rated capacity in the US, and wind at about 35 percent. The former number will likely decrease over time as solar becomes inexpensive enough to make economic sense in places that don’t receive as much sunshine. By contrast, wind’s capacity factor may increase as more offshore wind farms get completed. For natural gas, many of the newer plants are being designed to operate erratically so that they can provide power when renewables are under-producing.
A clearer sense of what’s happening comes from looking at the generating sources that are being retired. The US saw 5.1 GW of capacity drop off the grid in the first half of 2024, and aside from a 0.2 GW of “other,” all of it was fossil fuel-powered, including 2.1 GW of coal capacity and 2.7 GW of natural gas. The latter includes a large 1.4 GW natural gas plant in Massachusetts.
But total retirements are expected to be just 7.5 GWO this year—less than was retired in the first half of 2023. That’s likely because the US saw electricity use rise by 5 percent in the first half of 2025, based on numbers the EIA released on Friday (note that this link will take you to more recent data a month from now). It’s unclear how much of that was due to weather—a lot of the country saw heat that likely boosted demand for air conditioning—and how much could be accounted for by rising use in data centers and for the electrification of transit and appliances.
That data release includes details on where the US got its electricity during the first half of 2024. The changes aren’t dramatic compared to where they were when we looked at things last month. Still, what has changed over the past month is good news for renewables. In May, wind and solar production were up 8.4 percent compared to the same period the year before. By June, they were up by over 12 percent.
Given the EIA’s expectations for the rest of the year, the key question is likely to be whether the pace of new solar installations is going to be enough to offset the drop in production that will occur as the US shifts to the winter months.
