Back
This analysis and news roundup come from the Canary Media Weekly newsletter. Sign up to get it every Friday.
California made itself a rooftop solar leader — and now it’s undoing that legacy.
Sure, sunny skies have played a big role in getting Californians to install panels at their homes. But for years, the state has also offered hefty incentives to help rooftop solar grow, including net-metering policies, which determine how much utilities pay solar panel owners for sending excess generation back to the grid. Under the first two iterations of California’s net-energy metering policies — NEM 1.0, established in the 1990s, and NEM 2.0 in 2016 — that power was heavily rewarded. Those big payments for solar power made it easier to recoup the cost of putting up panels — and easier for homeowners to justify their clean investments.
Then came NEM 3.0. In 2022, California utility regulators approved a plan to slash net-metering payments by as much as 75%. The policy, which went into effect the following year, has seen numerous legal battles ever since. And just this week, a court upheld regulators’ solar-tanking move.
The decision comes at a crucial moment for rooftop solar nationwide. After years of setting records, residential solar installations in the U.S. slumped after 2023, falling in both 2024 and 2025, according to a new Solar Energy Industries Association report. Last year’s dip was largely due to economic uncertainty, tariffs, and contractors’ inability to quickly ramp up installations before federal tax credits expired, SEIA said.
In the post-incentive new year, some states have increased their own rebates and tax credits to keep clean energy rolling. But with this week’s ruling, California will continue heading in the opposite direction. Recent numbers of total residential solar installations in California suggest what the state’s future under NEM 3.0 will look like: Annual installations of residential solar dipped significantly from 2023 to 2024 and remained low in 2025. SEIA expects NEM 3.0 to slow installs even further in 2026.
The latest NEM 3.0 ruling could be appealed again to the state Supreme Court, and environmental advocates say they’re considering doing so. But as climate journalist Sammy Roth argues, maybe net metering isn’t worth the fight, and advocates should root for new ways to keep solar power growing.
Permissionless, plug-and-play balcony solar, anyone?
Good news for wind power in the U.S. and beyond
Wind power in the U.S. may be riding a roller coaster, but in the rest of the world, the industry is still on an upward climb.
A record 169 gigawatts of wind power came online around the globe last year, according to a report out this week from BloombergNEF. More than 100 gigawatts’ worth of those turbines were installed in China, though the rest of the world saw increases as well.
There’s also some good wind news to share on the home front. All five under-construction offshore wind farms the Trump administration tried to shut down are set to hit major milestones this month, Canary Media’s Maria Gallucci reports. Off Massachusetts, Vineyard Wind is nearly complete; the Coastal Virginia Offshore Wind project and Rhode Island’s Revolution Wind will soon begin delivering power to the grid; Sunrise Wind is about halfway complete; and New York’s Empire Wind is getting a turbine-installation vessel this month to continue building.
New York’s nuclear future is at a crossroads
New York has its sights set on scaling up nuclear power — but faces dueling proposals on how to make it happen.
It’s been nearly five years since the Indian Point nuclear plant fully shut down, taking with it a major supply of emissions-free power for New York City. Now, looking to spur a “nuclear renaissance,” the Trump administration is pushing for Indian Point’s restart. Energy Secretary Chris Wright recently joined the area’s Republican Congress member at a press event to call for the downstate plant’s reopening — an unlikely prospect given the surrounding communities’ opposition.
After Wright’s visit, Democratic Gov. Kathy Hochul’s office affirmed she “will not support” Indian Point’s reopening. The plant is mired in intense controversy — something Hochul is probably reluctant to wade into during in an election year. But her administration is pressing on with plans to build a nuclear plant somewhere upstate, and so far, at least eight communities have said they’re interested in hosting it.
Release the reserves: The Trump administration says it will release 172 million barrels of crude oil from the Strategic Petroleum Reserve — about 40% of its supply — in an attempt to curb rising prices. (Axios)
Nuclear pivot: Trump administration officials and industry sources say lagging talks with Westinghouse to construct its flagship AP1000 nuclear reactors are leading the DOE to explore rival developers. (Canary Media)
Plugging away: Virginia’s House passes a bill to legalize plug-in “balcony solar” panels, putting it on track to become the second state to allow for the easily installable clean-energy solution. (Canary Media)
Permission to pollute: Mississippi regulators have approved a plan by Elon Musk’s xAI to build 41 natural gas–burning turbines to power a large data center near Memphis, Tennessee, despite residents’ concerns about noise and air pollution. (Mississippi Today, CNBC)
Big battery buildout: Home-battery startup Base Power will use its recent $100 million fundraise to install 100 megawatts of residential energy storage outside Dallas — and the project will be completed quicker than building a typical gas-powered peaker plant with similar capacity. (Canary Media)
Solar influencers: A North Carolina food bank’s rooftop solar array inspired a nearby Goodwill headquarters to install its own panels, with plans to redirect its energy bill savings back to its mission. (Canary Media)
Drilling into the transition: Some former oil and gas workers are finding new work in the geothermal industry, which values their expertise in drilling and other essential skills. (Grist)
The war in the Middle East has spurred the largest oil disruption in history. The Strait of Hormuz, a choke point for much of the world’s oil and gas supply, is functionally closed. Oil prices are hovering around $100 a barrel.
Many Americans are seeing the fallout in the form of higher prices at the gas pump. But in Puerto Rico, a part of the U.S. especially dependent on oil power plants, the conflict also likely means higher electric bills — a painful outcome on an island already beset by an expensive and unreliable grid.
“In the continental U.S., no one’s burning a significant quantity of oil to generate electricity,” said Cathy Kunkel, an energy consultant at the Institute for Energy Economics and Financial Analysis. But that’s not the case in Puerto Rico, where oil-fired plants make up about 60% of generating capacity. The island “just has a lot of old oil-fired power plants that were constructed in the ’60s and ’70s, when oil was obviously a lot cheaper.”
Puerto Rico does not produce oil itself, and so it must ship in every last drop it burns. Given that the U.S. territory’s oil supply contracts are tied to global price benchmarks, Kunkel said that she “can’t imagine a scenario” in which power costs won’t rise in response to the historic oil shock.
“[Puerto Ricans] will see an increase in electricity bills,” said Rodrigo Rosas, a senior research analyst at Wood Mackenzie. The scale and duration of the increase, he said, depend on a “million-dollar question”: How long will the oil market disruption last?
The looming price hikes come amid heated conversation about the future of Puerto Rico’s energy system — and whether it should hitch itself further to imported fossil fuels or focus on transitioning to clean energy.
Puerto Rico relies on fossil fuels for more than 90% of its electricity, with liquefied natural gas as its next-biggest source after oil. For now, the territory is relatively protected from the considerable shocks that the war has sent rippling through the global LNG market, analysts told Canary Media.
That’s because it gets most of its LNG from Trinidad and Tobago and from a facility in Mexico that is fed by U.S. pipeline imports. Those sources both “operate in supply systems that are largely insulated from disruptions linked to the Middle East conflict,” Rosas said.
Puerto Ricans will soon have more specifics on what the war means for their bills in the near term. Every three months, the island’s electricity regulator adjusts prices for fuel costs, a process that is set to happen next at the end of March. That means higher rates would kick in starting in April.
Even a marginal rise in power bills could mean hardship in Puerto Rico, where the median household income is around $26,000 a year, less than one-third of the U.S. median. Already, the island faces some of the highest electricity prices in the U.S.
Faraway energy shocks have caused prices to climb in Puerto Rico before. After Russia’s 2022 invasion of Ukraine sent oil and gas markets reeling, the fuel-cost portion of Puerto Ricans’ electric rates jumped from 15 cents per kilowatt-hour at the beginning of that year to 22 cents per kilowatt-hour in the summer, according to Kunkel. That price jump, she noted, was driven by higher prices for both LNG and oil.
To some, the latest threat of price hikes underscores once again the need to embrace solar, wind, and batteries — all of which produce power unperturbed by global conflict.
Utility-scale renewables provide very little of Puerto Rico’s electricity today. But devastating hurricanes and frequent outages have motivated many Puerto Ricans to install rooftop solar and home batteries in recent years.
In 2023, the Biden administration launched a $1 billion program to boost the buildout of these distributed systems. The Trump administration, however, has clawed back or redirected much of that federal funding. Meanwhile, Jenniffer González-Colón, the Trump-allied governor of Puerto Rico elected in 2024, has supported plans to boost the island’s gas generation and weakened a 2019 law that commits it to ditching fossil fuels by 2050.
In late 2024, the Puerto Rican government approved the construction of a new gas plant on the island, and it’s currently looking to procure another 3 gigawatts of “firm” capacity, which likely means gas plants. Contracts for temporary generators run by LNG and diesel are also advancing, Kunkel said.
“I think the government’s making a huge mistake doubling down on natural gas as opposed to investing more in renewables,” said Sergio Marxuach, policy director at the Center for a New Economy, a Puerto Rican think tank.
In light of that, the island should work “as hard as possible” to insulate its economy from fossil fuels, said Tyson Slocum, director of the energy program at Public Citizen, a nonprofit consumer advocacy group.
“I don’t care what kind of supply agreement you negotiate. I don’t care if you’re getting your LNG from the United States,” Slocum said. “You are going to continue to be vulnerable to shortages and price shocks because of the inherent features of global fossil-fuel supply chains.”
The surge of new data center development is making people worried.
How much energy and water will these resource-hungry centers consume?
Will they drive new fossil fuel pollution?
How much will household electricity prices go up?
These questions have answers, but in many cases, the details of new data centers are blocked from public view.
Take this example from Montana. Quantica Infrastructure is planning to build a 5,000-acre energy and technology hub near Billings, Montana, which would use more electricity than all of the households in the state combined. The specifics are spelled out in the documents below – but they’re redacted.
Bipartisan opposition to data centers is growing fast, with 20 projects blocked or delayed nationwide in just a three-month period during spring 2025, according to the research group Data Center Watch.
But secret agreements make it nearly impossible for residents and elected officials to understand the impacts of data center development in their communities – or whether their electricity bills will soon be subsidizing Big Tech.
In Montana, advocacy groups are challenging NorthWestern Energy’s plans to serve data centers. (I’ve been involved as well: I serve on the steering committee of a fledgling nonprofit called Montanans for Affordable Energy.)
State Rep. Kelly Kortum, a Democrat from Bozeman, said he is wary of the proliferation of data center proposals in Montana, and he’s ready to push back.
“I’m looking to make sure the people don’t get screwed over,” he said. Kortum is a computer scientist who works in IT.
“I personally really need to know how much energy is being used and how much of that is public electricity,” he added. “And what’s that going to do to our rates?”
As data center developers scope out plans for new projects, they first need to make sure they can get enough electricity to feed the data center. Often, they turn to the local utility and make basic arrangements to purchase electricity.
The agreement reached between the data center developer and the utility is spelled out in a letter of intent. It includes how much energy will be delivered, the prices, the time frame for when the new electric service will start, and how the utility will ensure that it delivers sufficient electricity to keep the data center churning along.
NorthWestern Energy in Montana has signed letters of intent with developers of three proposed data centers. These three agreements alone would more than double the average amount of electricity used by NorthWestern’s customers. The electricity would be generated by burning coal at Montana’s Colstrip power plant, one of the most polluting power plants in the U.S.
Ari Peskoe is the director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program and an author of “Extracting Profits from the Public: How Utility Ratepayers Are Paying for Big Tech’s Power.” The report lays out tactics that data centers are using to off-load their costs onto households, such as making secret deals with utilities.
“I mean, look, these are monopolies,” Peskoe said. “They ought to be held to a standard about transparency. That requires they provide meaningful information about major deals that they’re a part of.”
NorthWestern Energy, like many utilities in the U.S., is a regulated monopoly. That means that the company can operate without competition, but it’s overseen by a governmental body. In theory, public utility commissions serve as a backstop against price gouging and other unfair practices.
“The whole point of utility regulation is to really dive into the accounting records, the details, and make sure that the public is protected from their monopoly power,” Peskoe explained.
But in this instance, Montana’s Public Service Commission sided with NorthWestern Energy. The commission decided that “proprietary Letters of Intent information derives independent economic value or competitive advantage from its secrecy.”
Peskoe disagrees.
“They’re claiming that this is a private business deal, but it’s kind of not when you’re a regulated monopoly,” he said. “They ought to have a higher standard for the information they disclose to the public than other private companies.”
“’Trust us’ doesn’t really cut it when you’re a monopoly provider,” he added.
A Montana bill that sought to address some of these issues (HJ-46) failed in the last legislative session, but Kortum, the representative from Bozeman, said that lawmakers will try again.
“Repeating the same bill builds knowledge with the legislators,” he said, noting that data centers are a new topic and many lawmakers are unfamiliar with the issues and possible solutions.
Kortum said when legislators don’t have a firm position one way or another, public input can hold more sway. For some lawmakers, “They have no dog in this race,” Kortum said. “I am expecting them to fall back on what the public wants,” he said.
For the Quantica Infrastructure project, the company already purchased 5,000 acres of land in a county with no zoning and limited local oversight. The project is scheduled to begin construction this year.
NorthWestern Energy said it plans to release a set of proposed terms and conditions for new data centers. These arrangements are called large load tariffs, and in theory, they can contain safeguards that help protect household energy users from shouldering the burden of new infrastructure. For example, the tariff could specify a minimum demand, so that if a data center uses less electricity than originally planned, it would still have to pay for the costs of all of the infrastructure built to bring electricity to the site.
NorthWestern Energy said it planned to file its large load tariff with Montana’s Public Service Commission by the end of 2025, but to date has not released a public plan.
In a recent NorthWestern Energy earnings call, the company appeared to walk back its earlier statement.
“We had said we will file a large load tariff, but I would note that that was tied to signing an ESA,” said Crystal Lail, NorthWestern Energy’s vice president and chief financial officer.
An ESA is an electric service agreement that spells out the specifics of the service between the utility and the data center. By the time a utility and a developer have an electric service agreement, it means the project is less of a proposal and more of a sure bet. In other words, the utility won’t share more details until the project is closer to reality, which also means it could be harder for communities to intervene.
What’s more, electric service agreements are also sometimes hidden from the public. For example, here’s an excerpt from the electric service agreement between Leola Data Center and Montana-Dakota Utilities in North Dakota.
NorthWestern’s Lail said the company wants to “get ahead of this argument that data centers aren’t paying their fair share.”
NorthWestern Energy CEO Brian Bird said the company expects to release its new large load tariff by the middle of 2026, six months later than originally promised.
When Gary Dirks arrived in China in 1995, the country’s government was looking to source more of its energy at home. Dirks was the incoming country head for BP, but efforts to find more oil and gas in the country had largely fizzled.
So government leaders pivoted, Dirks said. China invested heavily in its domestic coal and, later, in building wind and solar energy. Now, those investments and other steps are shielding China from more severe impacts of the volatility unleashed by the U.S.-Israeli war in Iran, despite Beijing’s continued reliance on foreign oil.
“They’ve been taking measures for a very long time to try to maximize their use of their own resources,” said Dirks, now senior director at the Global Futures Laboratory at Arizona State University. “They’ve been aware of this vulnerability for a very long time.”
By some measures, China could appear to be highly exposed to the price spikes and supply disruptions the war has sparked in global oil and gas markets. The country gets nearly half of its oil and one-third of its liquefied natural gas, or LNG, from the Middle East, according to an analysis of data by Columbia University’s Center on Global Energy Policy.
Yet China has built up a crude oil stockpile of nearly 1.4 billion barrels, meaning the country could be cut off from imports for months, “and they’d be OK,” said Erica Downs, a senior research scholar at the Center on Global Energy Policy.
China is more vulnerable with natural gas, for which it doesn’t have such a substantial stockpile, experts say. Because the war has caused prices in Asia to spike, some industrial users in China, like chemical or glass plants, will need to pay more, cut back their operations or both.
“There is definitely going to be short-term pain,” Downs said. “But I think in the longer term there are definitely some silver linings for China.”
In an essay in Foreign Policy written with Jason Bordoff, the founding director of the Center on Global Energy Policy, Downs argued that while the war has exposed China’s dependence on Middle Eastern oil, “it also underscores how deliberately Beijing has sought to prepare for a world in which energy security is inseparable from geopolitics—by electrifying its economy, securing domestic sources of energy, amassing stockpiles, and dominating clean technology supply chains.”
Last year more than half of new cars sold in China were electric, according to the energy think tank Ember, while the country is a leader in electrifying heavy-duty vehicles and high-speed rail, too. Meanwhile, a rapidly growing portion of its electricity is being generated by solar and wind energy as China installs more of those technologies than the rest of the world combined.
Gasoline and diesel demand have already begun to fall, despite rapid economic growth, while China’s total crude demand has plateaued, according to the International Energy Agency.
China has also retrofitted many of its coal plants to operate as flexible power sources, like natural gas turbines that can be turned on and off more easily than traditional coal plants, said Kate Logan, director of the China Climate Hub and Climate Diplomacy at the Asia Society Policy Institute.
“That set up China quite well in terms of any potential shocks to its power sector because China can ramp up coal usage,” Logan said.
Beyond the power sector, China could also use coal to produce liquid fuels and feedstocks to replace oil or gas in industrial processes or for chemical production. Any increased coal use could lead to a surge in greenhouse gas emissions.
“That’s something to keep an eye on in terms of the near-term impact on emissions,” Logan said.
Downs, at Columbia, said she expects any spike in coal use would be short-lived because of the country’s larger goals of reducing air pollution and climate emissions.
In its recently published 15th Five-Year Plan, the Chinese government said it planned to cut its carbon intensity 17 percent by 2030. That’s a slight decrease in ambition from the previous plan, and the program also renewed the possibility of a new gas pipeline from Russia’s Siberia region. The Iran war could prompt more urgent discussions between the countries, Logan said.
“I’d imagine this is something, again, that would bring China closer to Russia for both oil and gas imports,” Logan said.
The chokepoint at the Strait of Hormuz, a crucial passageway for commercial shipping effectively blocked by the Iran war, is also affecting global fertilizer shipments, potentially imperiling the spring planting season across much of the world. Roughly one-third of the global seaborne fertilizer shipments go through the strait, a statistic that has panicked agricultural producers.
But China has attempted to protect itself from fertilizer disruptions, too. While the country imports sulfur, a critical fertilizer ingredient, from the Gulf, it has otherwise become largely self-sufficient.
Fred Gale, a former U.S. Department of Agriculture economist and China specialist, explained that China is a net exporter for nitrogen fertilizer, which is made using natural gas.
In February, weeks before the U.S. attack on Iran, Chinese authorities “issued a document ordering companies and rail transport to ensure fertilizer supplies and build up reserves ahead of spring planting,” Gale explained.
“For now China seems to be feeling pretty smug about the fertilizer situation,” Gale noted.
A spokesperson for the Chinese embassy in Washington said the government has called for an immediate halt to military operations in the region to prevent the conflict from spreading.
“The Strait of Hormuz and waters nearby are an important route for international goods and energy trade. Keeping the region safe and stable serves the common interests of the international community,” the spokesperson said in a statement. “China will do what is necessary to protect its energy security.” The spokesperson added, “We will continue to strengthen communication with relevant parties, including parties to the conflict, and play a constructive role for deescalation and restoration of peace.”
Perhaps the greatest benefit to China, Downs said, could come from overseas. As the country has pushed to electrify and generate more of its energy from renewable sources, Chinese companies have become global leaders in these technologies. Already, nations around the globe have been turning to Chinese firms to import or build solar panels, EVs and batteries. Now, Downs argues, price shocks from the Iran war could accelerate this trend.
Dirks said the war is a reminder that governments still see oil as a geopolitical weapon.
“Any nation today that imports hydrocarbons has to be aware of that,” Dirks said. “And I think now that wind and solar in particular have come down dramatically in price, more and more countries will be asking themselves, ‘What is the balance of risk in using wind and solar and battery resources as opposed to importing oil and gas?’”
Whether at home or abroad, many experts say, the war-induced shock to fossil fuel markets reinforces China’s energy policies.
“The big takeaway,” Logan said, “is that this really vindicates a lot of China’s clean energy push.”
Across the country, state lawmakers are considering ways to address the risks posed by the explosion of power-hungry data centers. They have proposed an array of bills to impose moratoriums on data center development, revoke tax breaks, force data centers to pay for new energy infrastructure, and enact other safeguards.
In Illinois, lawmakers and renewable advocates are especially concerned that data centers could derail the state’s transition to 100% clean energy, since there’s likely not enough renewable sources in the state to meet data centers’ projected demand.
The Protecting Our Water, Energy, and Ratepayers Act, or POWER Act, aims to persuade data centers to pay to build enough new clean energy for sustaining their operations. This should shield customers from rising prices when overall electricity demand increases, proponents of the measure say, and it would ensure that the state’s coal and gas plants don’t need to run past their planned retirement dates just to fuel data centers.
The bill, introduced in February, would entice data centers to make clean energy investments by offering them two of the things such operations most prize: fast interconnection to the grid and uninterrupted power.
Stakeholders involved in crafting the bill said the incentive structure is meant to keep Illinois attractive to data centers, while defending the state’s clean energy shift and customers’ wallets. The facilities could account for between 64% and 72% of energy demand growth in the state by 2030, according to a recent report by the Union of Concerned Scientists, a nonprofit science advocacy group.
Illinois law mandates ending fossil fuel generation by 2045, but unchecked data center growth could cause continued reliance on the state’s fossil-fueled plants — allowed by law if the power is needed — and the importing of dirty power from elsewhere, the report explains.
The bill’s advocates are calling the approach BYONCCE, pronounced like the singer’s name but meaning “bring your own new clean capacity and energy.” (A similar term has been used in other states, sometimes referring to “carbon-free energy.”)
While the addition of new clean energy should help prevent a rise in electricity costs for regular customers, the bill also has other components to keep rates low. It requires data centers to pay for grid upgrades such as the transmission lines and substations needed to serve them. It demands that data centers pay into a “public benefits and affordability fund” that can be used to assist low-income households with utility costs and for environmental justice initiatives; each data center would pay an amount based on its peak demand. The bill also creates a compensation fund for community groups intervening in regulatory proceedings around data centers, helping them push for clean energy and customer protection in individual cases.
“We’re in a new world all of a sudden where demand has gone off the wall,” said MeLena Hessel, Midwest deputy program director of Vote Solar, a nonprofit policy-advocacy organization. “Writ large, we’re trying to figure out how can we get to large loads bringing their own new clean energy and capacity in ways that matter and keep costs lower for customers.”
Supporters of the bill emphasize that while the legislation provides incentives for data centers to develop clean energy, it does not actually force them to do so.
If the power-hungry facilities don’t provide their own energy, they would have to wait, along with all the other large users, in a potentially long line to get connected to the grid. The bill calls for data centers to submit a clean energy supply plan to regulators. If that plan shows that the data center has procured 80% of its predicted annual power demand from new clean energy by 2030 and 100% by 2045, it would receive “fast-track” grid connection.
“We want to encourage data center companies to be clean energy champions, and those that are really excelling are able to jump the queue,” said Kavi Chintam, Vote Solar’s Illinois campaign manager. “That is the incentive that data center companies need and want now.”
Data centers that don’t build enough clean energy could see their electricity curtailed during times of high demand. The bill empowers utilities to take such action as a way to protect other customers from increased prices when the energy supply is tight. That threat is further motivation for data centers to invest in clean energy.
Facilities that pay to build or acquire as much clean energy as they expect to use are guaranteed uninterrupted access to that same amount of power. Solar and wind, as well as battery storage, virtual power plants, and demand-response measures — such as reducing energy use when the grid is stressed — qualify toward that total. Data centers would still be subject to any emergency energy curtailment — like rolling brownouts or blackouts — ordered by regional grid operators.
Illinois has a restructured energy market, in which utility companies do not own generation and instead procure power on the open market to serve customers. In neighboring Wisconsin and Indiana and other states with vertically integrated energy markets, by contrast, utilities pay to build needed generation and pass on the costs to their customers.
Regulators in Illinois and other states with restructured markets may have fewer options to determine how data centers are charged for generation infrastructure, since that is not the purview of the utilities they oversee. In Illinois, management of the flow of electricity on the grid — which utilities do control — is the way to influence data centers’ behavior, said James Gignac, who is the Midwest policy director for the Union of Concerned Scientists’ climate and energy program and one of the authors of its recent report.
“Offering compelling incentives for what the data centers wish to have is our approach,” Gignac said. “They are looking for firm service and the quickest way possible to connect to the power grid. By challenging data centers to meet these higher levels of clean energy, we can recruit the most responsible data center operators to Illinois.”
The Data Center Coalition, a trade group that represents developers of the facilities, and the Illinois Chamber of Commerce, which promotes investment in the state, did not respond to queries for this story.
Three times in the last decade, Illinois’ clean energy supporters and industry representatives have worked closely with lawmakers to pass sweeping energy bills. A 2017 law created ambitious renewable-energy mandates and job creation programs, a 2021 law bolstered clean energy and equity targets, and a law passed last fall addressed the need for much more energy storage on the grid. Those three pieces of legislation were spearheaded by legislators working with the Illinois Clean Jobs Coalition, including dozens of advocates for consumers, clean energy, and environmental justice. That coalition is also backing the data center bill.
Coalition members described the POWER Act as a similarly ambitious measure, which will likely go through a long process of consensus-building.
In addition to the clean power and affordability provisions, the bill includes other safeguards, like mandates for water resource planning and quarterly water-use reports. It prohibits nondisclosure agreements with data centers, mandates community benefit agreements, and requires a proposed data center’s cumulative impact to be examined in the context of other existing or proposed burdens on local residents.
Illinois’ legislative session ends in late May, and bills can also pass in a fall veto session or a special session called by the governor.
Proponents of consumer protection and clean energy say it is crucial for a data center–focused bill to pass soon, since numerous such facilities for powering AI are proposed in the state. The Chicago region, in particular, is already home to around 200 data centers, according to the organization Data Center Map, and more could be in the works. A $20 billion data center proposal was recently approved by local officials southwest of Chicago, in Joliet, for example. In February, Democratic Gov. JB Pritzker called for a two-year pause on state tax incentives for data centers in response to the growing concern from communities.
“This is an urgent problem,” Chintam said. “We need to do something now.”
A correction was made on March 12, 2026: A previous version of this story misrepresented the Union of Concerned Scientists’ prediction for data center energy demand in Illinois by 2030. Data centers could account for between 64% and 72% of growth in demand by that time, not total demand.
One of the most promising low-carbon cement startups, Sublime Systems, has hit a major roadblock in its efforts to scale up production.
The startup said this week that it had laid off about two-thirds of its workforce, having already paused construction in December on its forthcoming commercial-scale facility in Holyoke, Massachusetts. The actions were in response to the Trump administration clawing back an $87 million award last year from the Department of Energy’s now mostly gutted Office of Clean Energy Demonstrations.
The grant, which was meant to help Sublime build the Holyoke manufacturing plant, was swept up in the administration’s broader rollback of billions of dollars in previously awarded funding for projects that curb carbon emissions from industrial facilities.
Ever since then, “the company has faced compounding challenges in assembling the capital stack required to scale our operations,” a Sublime spokesperson said on Thursday in an email to Canary Media. Sublime said its project had been expected to create hundreds of direct and indirect jobs in the region.
Sublime, an MIT spinout, has raised over $200 million in total funding, including the federal grant. The six-year-old company is part of a bigger global push to develop novel ways of making cement, without producing planet-warming pollution in the process.
Traditional cement — which is mixed with sand, gravel, and water to form concrete — is responsible for roughly 8% of global carbon dioxide emissions. Nearly all cement is made today by heating carbon-rich limestone in fossil-fuel-burning kilns as hot as molten lava.
Sublime’s approach is very different. It involves electrically charging a bath of chemicals and calcium silicate rocks. In March 2024, the Biden administration awarded Sublime and other producers a collective $1.5 billion to slash the carbon impact of cement, as part of a larger $6 billion investment in industrial decarbonization projects.
Before this week’s layoffs, Sublime employed as many as 90 people, and it was making progress around proving its technology and securing key customers, including Microsoft.
Last summer, Sublime completed a “pilot pour” of its low-carbon cement at a data center campus in northern Virginia owned by Stack Infrastructure. And in May, Microsoft signed a binding deal to purchase up to 622,500 metric tons of Sublime’s cement products — enough to build roughly 30 professional football stadiums — from the startup’s forthcoming manufacturing facilities.
This week’s setback casts doubt on Sublime’s ability to supply Microsoft with that cement, as Bloomberg first reported. The tech giant declined to comment directly on how Sublime’s layoffs might affect Microsoft’s own goals to reduce carbon emissions from infrastructure projects.
However, Microsoft “remains committed to advancing low‑carbon building materials and continues to work with Sublime and a range of partners to support our long‑term sustainability goals,” a spokesperson said by email.
Microsoft has also invested in the clean-cement startup Fortera to support construction of that firm’s 400,000-ton-per-year facility. And it’s partnering with RMI and the Center for Green Market Activation to develop a system enabling companies to purchase “environmental attribute certificates” that represent the emissions reductions provided by cleaner cement and concrete — without actually buying the physical product.
Sublime said it continues to see “strong customer demand and industry backing” and is sticking to its goal of building the first electrochemical cement plants in the United States and Europe by 2030. The startup added that it remains in talks with the Department of Energy to try to restore its award and resume construction on its Holyoke facility.
“Sublime remains strong and well-positioned to continue to attract capital, commercialize its technology and meet market demand,” the company said.
Wouldn’t it be nice if you could just buy a pair of solar panels at Walmart in the morning and plug them in on your deck in the afternoon — in the span of a few hours, setting yourself up to produce clean energy that will lower your electricity bill?
But that’s not an option for most Americans right now. For one thing, the devices aren’t widely available in U.S. stores. And if they were, you’d likely have to jump through a series of hoops with your utility to get them up and running.
Virginia lawmakers are about to change all that for residents of the state.
On Wednesday, the Democratic-controlled Virginia House of Delegates passed a bill legalizing “balcony solar” by a unanimous, bipartisan vote. The Senate, where Democrats also have a majority, had already approved the measure with only a handful of dissents. It will soon reach the desk of Gov. Abigail Spanberger, a Democrat, who is expected to sign it.
Set to take effect next January, the law will make Virginia just the second state in the country, after Utah, to treat solar panels like an appliance you can buy at your local big-box store and set up yourself — on your balcony, in your yard, or anywhere the sun shines on your property.
“That removes all kinds of barriers — not just cost barriers, but time and bureaucracy barriers,” said Victoria Higgins, Virginia director for the lobbying arm of Chesapeake Climate Action Network Action Fund, an advocacy nonprofit. “It makes clean energy more accessible to so many more Virginians, whether they live in apartments, or condos, or just don’t have the funding to put up a whole rooftop system.”
Homeowners and renters alike will be able to buy and install the plug-in solar panels, which come with a microinverter that enables the devices to offset some household electricity use.
“This legislation is about putting practical energy solutions in the hands of Virginians,” Senate Majority Leader Scott Surovell, a Democrat from Fairfax who sponsored the proposal, said in a news release.
The kits will be subject to safety standards and limited to a total of 1,200 watts, or about four panels, which is enough to supply between 5% and 15% of the average customer’s demand.
“On an extremely mild day in June, it might be pretty close to all of your energy needs, but that would be rare,” Higgins said. “Most of the time, you’re knocking off a chunk of energy that you would otherwise be buying from the utility.”
Like many Virginia Democrats who prevailed in the November elections, Spanberger campaigned on a promise to rein in costs. In December, she put balcony solar on her list of energy-affordability priorities, and her staff has advocated for the bill throughout Virginia’s 60-day legislative session, which ends at midnight on Saturday.
Balcony solar is already widespread in Europe, where over 1 million devices are in use in Germany alone. Proponents say the same could happen in the United States, with dozens of states, from Alaska to Illinois to South Carolina, considering legislation to allow the kits.
While a few states have deferred balcony solar bills because of safety concerns voiced by utilities, Higgins notes that Virginia’s bipartisan support helps show that red and blue states alike are eager to address energy affordability.
“Right now, the estimated payback period is somewhere between two and five years,” she said. “You might see 20 states pass legislation to enable balcony solar this year. Once you get to economies of scale, the price is going to come down quickly.”
All five offshore wind farms being built in the U.S. are on track to hit key construction and operational milestones this month — even as the Trump administration continues its campaign to halt their development.
Coastal Virginia Offshore Wind, a 2.6-gigawatt project near Virginia Beach, Virginia, is expected to begin delivering power to the state’s energy-hungry grid by the end of March, according to its developer, Dominion Energy. As the first turbines start spinning, construction will proceed on the rest of the 176-turbine wind farm, which is now more than 70% finished.
Farther up the east coast, near Martha’s Vineyard, Massachusetts, the 800-megawatt Vineyard Wind is effectively complete.
Iberdrola, the parent company of Avangrid, which is one of Vineyard Wind’s developers, said on Feb. 25 that the final two of the 62 turbines would be installed “in the next days,” and that about 85% of the turbines are either operating or approved to begin exporting electricity.
Ørsted, which is developing the 704-MW Revolution Wind near Rhode Island, said the project was expected to begin generating electricity “within weeks” of a Feb. 6 earnings call. At that time, the Danish developer was pushing to install the last of its 65 turbines before its contract with a specialized turbine-installation vessel expired in late February. As of Tuesday, 60 of the total turbines have been installed, a spokesperson confirmed.
The vessel, called Wind Scylla, is now at the Port of New London in Connecticut, where its equipment is being recalibrated as part of ongoing construction operations at Ørsted’s Sunrise Wind project. Work on that 924-MW installation, off the coast of New York, was nearly halfway complete as of last month’s earnings call.
Meanwhile, Equinor’s Empire Wind just notched another legal victory. On Tuesday, a federal judge rejected the Trump administration’s latest effort to further delay construction on the 810-MW wind farm near New York. The project, which is more than 60% complete, is set to receive a new turbine-installation vessel this month to start putting towers and blades in the ocean.
Offshore wind companies have been charging ahead since federal judges gave them a temporary reprieve in January and early February from the Trump administration’s stop-work order. On Dec. 22, the Interior Department required all five projects to pause for 90 days, citing unspecified “national security” concerns. Most recently, the administration tried to pause Equinor’s lawsuit against the stoppage by 45 days, which the D.C. judge declined to do.
Interior’s sweeping suspension order threatened to derail the multibillion-dollar energy projects — which are meant to supply huge amounts of carbon-free power to a region that’s barreling toward an electricity shortfall. Developers said the forced pauses cost them millions of dollars a day and put them at risk of losing access to the specialized vessels they need to install turbines and other offshore equipment.
An attorney for Vineyard Wind said in court that the $4.5 billion project was “at a grave risk of failing to meet its construction schedule, and in turn, its financial obligations” if it couldn’t reach full commercial operations by the end of March, The Martha’s Vineyard Times reported in January. He noted that Vineyard Wind’s contract for a turbine installation vessel expires on March 31.
While Vineyard Wind nears completion, many of its turbines have already been supplying electricity to the New England grid — including during a major winter cold streak that forced grid operators to run expensive oil-burning power plants to avert blackouts.
The completed South Fork Wind farm, which came online in 2024 and delivers power to New York’s Long Island, was also a crucial resource. During that period, market electricity prices frequently exceeded the long-term, fixed rates that utilities pay for the offshore wind power, said Stephanie Francoeur, senior vice president of communications and external affairs for the Oceantic Network, which advocates for marine renewable energy sectors.
“We’re really encouraged by this real-world performance data,” she said. “It’s going to be exciting to see more of it as more projects come to completion this year.”
Yet even after offshore wind farms come online, they won’t necessarily be spared from future attacks by the Trump administration, which has indicated that it sees operating turbines as the real purported threat. In its Dec. 22 memo, the Interior Department noted that “the movement of massive turbine blades” creates radar interference — though experts say such potential impacts are manageable and often minor, as IEEE Spectrum reported this week.
In the meantime, offshore wind developers continue stressing the need for their large-scale energy projects to get built. Robert M. Blue, Dominion Energy’s president and CEO, recently pointed to the soaring demand from AI data centers that’s straining the grid in Virginia and the broader mid-Atlantic region.
The utility sees Coastal Virginia Offshore Wind “as the fastest way to get a significant amount of electricity at a low cost … for our customers who are leading the AI race, who are building ships for the Navy,” he said during a Feb. 23 earnings call. The project, which was initially expected to finish later this year, is now likely to wrap up in early 2027.
“Slowing it down, as was demonstrated with the last stop-work order, adds costs, and adding costs and delays in the data center capital of the world, we think, doesn’t make sense,” Blue said.
Base Power, the Texas-based home-battery juggernaut, just revealed how it’s spending some of the $1 billion it raised in October. The startup’s plan is to build one of the nation’s largest fleets of home batteries, for a cooperative utility outside Dallas–Fort Worth.
Cleantech startups and advocates alike keep promising that small-scale energy devices such as residential batteries and thermostats can be coordinated and operated like traditional power plants. But in practice, it’s been harder for companies to build enough aggregated capacity, with high enough reliability, to truly match the performance that utilities are used to at their large-scale gas power plants. The new Base Power project tackles this challenge head-on.
Base Power will work to install 100 megawatts of home battery capacity in the territory of member-owned utility Denton County Electric Cooperative, known as CoServ, over the next two years. Crucially, that scale equates to the output of a natural-gas-fired peaker plant, a class of smaller conventional power plants that fire up when demand is highest. While building a new gas peaker could take around five years of permitting and construction, Base Power can deliver the capacity in two years by striking deals with homeowners and installing each system in a day, said Tim Pianta, the company’s head of utility partnerships.
“The whole business is oriented around, How do we get dispatchable megawatts on the grid really quickly to drive down grid and power supply costs? And I think this is a really good application of that,” he said.
In partnership with CoServ, Base Power will pitch the utility’s customer-owners on whole-home backup power for an installation fee starting at $695 and a monthly $19 subscription. That’s a slim fraction of the cost to buy a big enough battery on the open market, which could easily run to $15,000 or $20,000. Base Power can afford to offer that bargain because it retains ownership of the batteries and will call on them to fulfill a grid capacity contract for the utility.
On the utility side, this contract should offer the fastest path to adding capacity affordably, Pianta said. While CoServ could purchase power from the wholesale market managed by the Electric Reliability Council of Texas or build its own peaker plants, the battery fleet gives the utility the option to buy power when it is cheap and deliver it when prices are high. Lowering the amount of power CoServ has to ship in during peak times also reduces the utility’s transmission costs, he added.
In short, this deal is an affordability play for CoServ — the third-largest electric coop in the U.S., serving 330,000 electric meters — at a time when average U.S. electricity costs are rising faster than inflation (and gasoline and natural gas prices have also spiked, at least temporarily, following the U.S. attacks on Iran).
“That’s a core value proposition for them: driving down costs of their power supply. And then, in tandem with that,” Pianta said, is “the ability to offer members dramatically more affordable resiliency than they would otherwise be able to get.”
Base Power launched in 2023 with a similar offering in parts of Texas where customers can choose their retail electricity provider; the startup sells cheap backup power and a cheap electricity subscription, then dispatches the batteries in ERCOT to recoup the cost of installation. The company then launched a parallel business packaging this concept for utilities in parts of Texas where customers have just one local retailer to pick from. The CoServ collaboration marks the fifth of these deals, and the largest — all five total 180 megawatts.
First, though, Base Power must deliver on this ambitious promise. For the CoServ deal, Base Power sales associates will have to convince some 5,000 homeowners to pay for backup power. Even with a low price, that entails a significant ground game, and will depend on the level of customer interest in battery backup.
Pianta noted that CoServ “already has a very reliable system, so they have very few outages.” That compliment may be constructive for maintaining a strong partnership with the utility, but it runs against the usual marketing playbook for home backup — evoking the risk of being left in the dark by utility failures. This tension is playing out around the country in places where battery vendors have opted to sell their wares in partnership with utilities, instead of running insurgent marketing against them.
This being Texas, memories of the deadly Winter Storm Uri in 2021, which precipitated a systemwide collapse of natural gas and electricity supply, could motivate residents to sign up. The small investment and monthly fee could be an enticing insurance policy for Texans who harbor a healthy skepticism of politicians’ efforts to fortify the state energy system in the wake of that disaster (and the often-politicized response has left plenty of room for skepticism).
Pianta said Base Power will hit the 100-megawatt deployment target by leaning on its vertically integrated business model, in which the company designs, builds, sells, installs, and maintains its batteries, rather than outsourcing those functions.
“Base has been building up for a long time now, both the supply capacity to deliver that type of resource and the deployments engine to develop that local capacity really quickly,” Pianta said. The company is ramping up manufacturing in the former Austin American-Statesman building, and it has reached an installation pace of more than 60 customers per day, for a total of 300 megawatt-hours in operation.
The contract also protects CoServ customers, stipulating that the utility pays only for the capacity that Base Power actually delivers, Pianta said. This aligns incentives between the utility and the startup, giving the latter good reason to move swiftly on installing its batteries.
Longer term, the project will serve as a large-scale test case for decentralized batteries as an effective competitor to traditional fossil-fueled power plants. CoServ leadership thought this would be a good deal for serving its customers’ electricity demand, but the price point for that 100 megawatts matters only if the batteries work en masse. That’s why Base Power retains control and ownership of the batteries: It doesn’t have to worry about homeowners using the batteries in ways that undermine their availability when the utility wants them to discharge.
Beyond the efficacy of the battery network, Base Power must prove its overarching business case: Does paying all the money to build an in-house battery empire pay off in the end? Can the home battery market support a corporate newcomer with a $4 billion valuation and major investment from Silicon Valley royalty like Andreessen Horowitz? The only way to settle those questions is to install a lot more batteries.
The “cost” of cutting UK emissions to net-zero is less than the cost of a single fossil-fuel price shock, according to a new report from the Climate Change Committee (CCC).
Moreover, a net-zero economy would be almost completely protected from fossil-fuel price spikes in the future, says the government’s climate advisory body.
The report is being published amid surging oil and gas prices after the US and Israel attacked Iran, which has triggered chaos on international energy markets.
It builds on the CCC’s earlier advice on the seventh “carbon budget”, which found that it would cost the UK less than 0.2% of GDP per year to reach its net-zero target.
In the new report, the CCC sets out for the first time a full cost-benefit analysis of the UK’s net-zero target, including the cost of clean-energy investments, lower fossil-fuel bills, the health benefits of cleaner air and the avoided climate damages from cutting emissions.
It finds that the country’s legally binding target to reach “net-zero emissions” by 2050 will bring benefits worth an average of £110bn per year to the UK from 2025-2050, with a total “net present value” of £1,580bn.
The CCC states that its new report responds to requests from parliamentarians and government officials seeking to better understand its cost assumptions, amid the ongoing cost-of-living crisis in the UK.
The report also pushes back on “misinformation” about the cost of net-zero, with CCC chair Nigel Topping saying in a statement that it is “important that decision-makers and commentators are using accurate information to inform debates”.
The CCC’s new report is the first to compare the overall cost of decarbonising with the wider benefits of avoiding dangerous climate change, as well as other “co-benefits”, such as cleaner air and healthier diets.
It sets the CCC’s previous estimate of the net cost of net-zero – some £4bn per year on average out to 2050 – against the value of avoided damages and other co-benefits.
These “co-benefits” are estimated to provide £2bn to £8bn per year in net benefit by the middle of the century, according to the report.
The CCC notes that this approach allowed it to “fully appraise the value of the net-zero transition”.
It concludes that the net benefits of reaching net-zero emissions by 2050 are an average of £110bn per year from 2025 to 2050.
These benefits to the UK amount to more than £1.5tn in total and start to outweigh costs as soon as 2029, says the CCC, as shown in the figure below.
In addition, the CCC says that every pound spent on net-zero will bring benefits worth 2.2-4.1 times as much.
This updated analysis includes the value of benefits from improved air quality being 20% higher in 2050 than previously suggested by the CCC.
However, the “most significant” benefit of the transition is the avoidance of climate damages, with an estimated value of £40-130bn in 2050. The report states:
“Climate change is here, now. Until the world reaches net-zero CO2 [carbon dioxide] emissions, with deep reductions in other greenhouse gases, global temperatures will continue to rise. That will inevitably lead to increasingly extreme weather, including in the UK.”
The CCC’s conclusion is in line with findings from the Office for Budget Responsibility (OBR) in 2025, which suggested that the economic damages of unmitigated climate change would be far more severe than the cost of reaching net-zero.
The CCC notes that its approach to the cost-benefit analysis of the net-zero target is in line with the Treasury’s “green book”, which is used to guide the valuation of policy choices across UK government.
It says that one of the key drivers of overall economic benefit is a more efficient energy system, with losses halved compared with today’s economy.
It says that the UK currently loses £60bn a year through energy waste. For example, it says nearly half of the energy in gas is lost during combustion to generate electricity.
In a net-zero energy system, such energy waste would be halved to £30bn per year, says the CCC, thanks to electrified solutions, such as electric vehicles (EVs) and heat pumps.
For example, it notes that EVs are around four times more efficient than a typical petrol car and so require roughly a quarter of the energy to travel a given distance.
Collectively, these efficiencies are expected to halve energy losses, saving the equivalent of around £1,000 per household, according to the CCC.
The CCC tests its seventh carbon budget analysis against a range of “sensitivities” that reflect the uncertainties in modelling methodologies and assumptions for key technologies. This includes testing the impact of a fossil-fuel price spike between now and 2050.
In the original analysis, the committee had assumed that the cost of fossil fuels would remain largely flat after 2030.
However, the report notes that, in reality, fossil-fuel prices are “highly volatile”. It adds:
“Fossil-fuel prices are…driven by international commodity markets that can fluctuate sharply in response to geopolitical events, supply constraints, and global demand shifts. A system that relies heavily on fossil fuels is, therefore, exposed to significant price shocks and heightened risk to energy security.”
It draws on previous OBR modelling of the impact of a gas price spike. This suggested that future price spikes would cost the UK government between 2-3% of GDP in each year the spike occurs, assuming similar levels of support to households and businesses as was provided in 2022-23.
The CCC adapts this approach to test a gas-price spike during the seventh carbon budget period, which runs from 2038 to 2042.
It finds that, if a similar energy crisis occurred in 2040 and no further action had been taken to cut UK emissions, then average household energy bills would increase by 59%. In contrast, bills would only rise by 4%, if the UK was on the path to net-zero by 2050.
The committee says that when considering the impact on households, businesses and the government, a single fossil-fuel price shock of this nature would cost the country more than the total estimated cost of reaching.
The finding is particularly relevant in the context of rising oil and gas prices following conflict in the Middle East, which has prompted some politicians and commentators to call for the UK to slow down its efforts to cut emissions.
In his statement, Topping said that it was “more important than ever for the UK to move away from being reliant on volatile foreign fossil fuels, to clean, domestic, less wasteful energy”.
Angharad Hopkinson, political campaigner for Greenpeace UK, welcomed this finding, saying in a statement:
“Each time this happens it gets harder and harder to swallow the cost. The best thing the UK can do for the climate is also the best thing for the cost of living crisis – get off the uncontrollable oil and gas rollercoaster that drags us into wars we didn’t want but still have to pay for. Inaction on climate is unaffordable.”
In addition to testing the impact of more volatile fossil-fuel prices, the CCC also tests the implications if key low-carbon technologies are cheaper – or more expensive – than thought.
It concludes that the upfront investments in net-zero yield significant overall benefits under all of the “sensitivities” it tested. As such, it offers a rebuttal to the common narrative that net-zero will cost the UK trillions of pounds.
The net cost of net-zero comes out at between 0% and 0.5% of GDP between 2025 and 2050, says the CCC, under the various sensitivities it tested.
“This sensitivity analysis shows that an electrified energy system is both a more efficient and a more secure energy system,” adds the CCC.
Finally, the report takes into account the costs of the alternative to net-zero. It looks at what would need to be spent in an economy where net-zero was not pursued any further.
The CCC says that the gross system cost of the balanced pathway falls below the baseline cost from 2041, which is consistent with its previous seventh carbon budget advice.
As shown in the chart below, costs fall under a net-zero pathway between 2025 to 2050, whereas they rise in the baseline of no further action.
Moreover, the total costs of the alternatives are broadly similar, with the relatively small difference shown by the solid line.
The decline in energy system costs shown in the figure above is broadly driven by more efficient low-carbon technologies, says the CCC, helping costs to fall from 12% of GDP today to 7% by the middle of the century.
The CCC’s new analysis comes ahead of the UK parliament voting on and legislating for the seventh carbon budget, which it must do before 30 June 2026.
.svg)
