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It isn’t easy to trace the flows of electricity across a high-voltage transmission grid that spans 15 states from Louisiana to North Dakota. It’s harder still to differentiate the clean electrons from the dirty ones.
But doing so is necessary for states, companies, and other entities to track real progress toward decarbonization goals. Ultimately, it can be done — so long as you have the right data sources and the willingness to conduct some tricky analysis on power plant emissions and how power moves on the grid.
Just ask the Midcontinent Independent System Operator (MISO), the country’s largest grid operator by geography, and Singularity Energy, a startup developing open-source carbon emissions accounting software. In March, the partners unveiled a “consumed emissions” dashboard, revealing the carbon footprint of electricity within MISO regions, states, and even individual counties, measured on an hour-by-hour basis.
That data is useful for utilities offering “green tariff” programs that promise climate-focused customers a certain share of renewable or carbon-free energy. It also helps states with zero-carbon or renewable energy targets determine the emissions impacts of importing power from out of state versus shuttering fossil-fuel power plants and building clean generation within their own borders.
Those were the two use cases detailed by Jordan Bakke, MISO’s director of strategic insights and assessments, during an April 23 workshop. “Our members and states are pursuing emissions goals both on their own behalf and on behalf of end customers,” he said. “The request that has been given to MISO is to fill that need for temporal, spatial, and timely granularity of emission estimations across our footprint.”
Greg Miller, research and policy lead at Singularity, said similar approaches could help companies that have contracted with wind and solar farms or nuclear power plants to determine how much of that carbon-free power is actually reaching their data centers, factories, and office buildings from hour to hour. That’s a big deal for corporate clean-energy buyers like Google and Microsoft that have committed to serving a growing amount of their enormous power needs with carbon-free electricity.
Singularity is one of many companies working on providing these increasingly complex grid-emissions calculations.
Software providers such as Electricity Maps, Flexidao, and Kevala are tracking power plant emissions and energy flows across swaths of Europe and North America. Companies like REsurety and WattTime have built “marginal emissions” methods to calculate the impact of clean energy generated at different times on regional grids. Major clean energy investors like Quinbrook Infrastructure Partners and HASI are building carbon-tracking methods. And the EnergyTag international consortium has developed “granular certificate” standards to track hourly emissions associated with clean energy contracts.
But MISO’s consumed-emissions dashboard brings a new level of detail, Miller said. “We can’t trace individual electrons, just like we don’t trace water molecules in a river,” he said. “But we can trace larger power flows from generators to the loads where these flows are going.”
Two key data inputs feed Singularity’s emissions outputs for MISO’s new dashboard. The first is its fine-grained estimates of how much carbon is being emitted from individual fossil-fuel power plants — a seemingly simple calculation that’s actually quite complicated to nail down.
“Every generator’s efficiency is described in its heat rate — how much fuel it needs to burn to generate a unit of electricity,” Miller explained. Heat rates change from hour to hour, depending on factors ranging from the outdoor temperature to whether generators are running at maximum efficiency or are just being started up.
Singularity worked with nonprofit and research partners on a project called the Open Grid Emissions initiative to develop a method for calculating those constantly shifting emissions rates using public data and open-source methodologies. In the past year, it has developed a way to use available historical data to estimate those emissions changes in real time, Miller said. Experts in the field can check the methodology themselves “because it’s all modeled off publicly available data.”
The second key source of information at play for MISO’s dashboard is more proprietary — the power-flow data used to assess how much electricity from fossil-fueled power plants and all other sources is reaching the nodes on MISO’s transmission network on an hourly basis. That includes “information about how much power is getting generated and injected to the grid, how much power is getting withdrawn for loads, and the power flows for each transmission line in that network,” Miller said.
The platform that Singularity developed for running that analysis, dubbed CarbonFlow, uses open-source methods to reach its conclusions, he said. But the input data itself is kept confidential, both to protect the competitive interests of the power plant operators in MISO’s energy markets and to comply with federal mandates meant to protect critical infrastructure.
The end result isn’t as complete a picture as some might imagine, Miller emphasized. MISO only tracks power down to the individual substations that convert high-voltage power to lower voltages for use on distribution grids, for example, not to individual customers.
And while the dashboard’s emissions data will be made available on a near-real-time basis at the regional and state level, users have to wait a month after the end of each quarter to look at the hourly data for counties. That’s to avoid revealing operational information about fossil-fueled power plants in those counties to competitors, at least in timeframes that would allow them to act on it in ways that could give them unfair advantages.
Nonetheless, publicly accessible data at the hourly and county level is breaking new ground in the world of grid carbon accounting, Miller said. “This may be for only one region in the U.S. But it proves it’s possible to calculate this data — and other grid operators can do it too, if this data were required more broadly in accounting standards.”
Kathleen Spees, a principal with consultancy The Brattle Group, would like to see MISO and Singularity’s approach picked up by more grid operators. “At the least, they have to start providing the data,” she said.
Brattle was hired by the Illinois Commerce Commission to help develop the state’s Renewable Energy Access Plan, a road map for how the state can meet its mandate to reach 100% carbon-free power by 2045. Illinois already gets more than half of its power from in-state nuclear plants and is aiming to dramatically expand its use of solar and wind power from both within and outside its borders.
“But Illinois, like many states, is highly interconnected with its neighbors,” Spees said. “You can’t just reduce the fossil emissions in your state and say you’re done.” In fact, “if you ramp down gas in Illinois and ramp up coal somewhere else, that’s counterproductive” to the state’s carbon-cutting goals.
That’s why grid operators must be in the picture. The energy markets they run don’t account for carbon emissions today, although some grid operators are starting to make certain emissions data available to participants. But “over time, they have to create the mechanisms for trade,” Spees said, “so that the states that value green energy and avoiding carbon emissions have valid signals.”
Utilities and regulators need hard data to start translating these commonsense understandings of how grids work into real policy decisions with dollars and cents attached to them, Spees said. “We’re not talking minor academic interest here — we’re talking real money. What fraction of the enormous amount of capital going into our sector can ignore carbon implications? It has to be validated.”
That’s going to be complicated, particularly in Illinois, which is served both by MISO throughout most of the state and by PJM Interconnection, a grid operator serving 13 states from Virginia to the Chicago region. But the work has to start somewhere, and “the contribution that MISO is making here is really pushing the envelope in terms of the technical advance of what they can offer,” she said.
Singularity CEO Wenbo Shi pointed out another key use case for MISO’s data: informing “green tariff” programs that are available in most states. Green tariffs offer customers — usually corporate buyers looking to add clean power — the option to pay higher rates to secure a greater share of renewable or carbon-free electricity than what is available from the utility’s general mix of generation.
But to balance things out, each transfer of clean-power ownership rights from a utility to a customer must then be subtracted from the utility’s mix for other customers, lest it be “double-counted” as the same resource belonging to multiple end users.
“Once you can do that, you know exactly who gets what, and what’s left,” Shi said. “This eliminates the risk of double-counting.” The new MISO dashboard can help utilities make these calculations, he said. To accurately allocate clean electricity to the right customers, utilities must first understand their whole supply mix — and those that are part of a regional grid like MISO also need to factor in the energy that they purchase from the wholesale market.
Singularity has worked with utility Southern Co. to deploy such a system to provide customers with unprecedented visibility into their energy mix and emissions, Shi said. In MISO, one of the first users of the grid operator’s consumed-emissions data-tracking capabilities has been utility Entergy Arkansas, which offers green tariffs for customers such as steelmakers.
To be clear, MISO is explicitly not using its consumed-emissions data to inform “market-based” carbon accounting, Miller said. That’s the term for contractual arrangements that establish ownership of a unit of clean energy, such as the renewable energy certificates created under Greenhouse Gas Protocol Scope 2 Guidance, the gold standard in emissions accounting.
At the same time, the GHG Protocol is in the midst of changes that may make the kind of tracking Singularity is doing quite useful for market-based accounting, Miller noted.
Today, companies can offset emissions associated with their electricity use through clean energy purchases that are averaged out over the course of a year, and which can come from sources far removed from a company’s power-using facilities.
Those loose accounting rules helped enable corporate spending in building more clean energy when solar and wind were rare and expensive, and when linking their generation and delivery to a corporate customer’s actual energy consumption was less important. But clean energy has now become the cheapest and most common source of new grid capacity, which means that when and where new clean energy is being built — and whether it’s actually being used by the facilities of the companies claiming it — matters much more.
The data center boom is pushing these issues to the forefront for utilities and regulators. Data center expansions being proposed to feed the AI ambitions of tech giants are threatening to overwhelm the capacity of power grids in key markets across the country, including states like Wisconsin that lie within MISO’s grid footprint.
These ballooning load forecasts are driving utilities and grid operators to propose fast-tracking new fossil gas-fired power plants. But that threatens to undermine the aggressive clean-energy targets set by Amazon, Google, Meta, Microsoft, and other companies driving the data center boom, giving them impetus to seek cleaner options.
Just how the GHG Protocol’s rules on clean electricity accounting should work is a contentious subject, with major clean-energy buyers split on issues such as the well-publicized debate over whether they should aspire to 24/7 clean power at their facilities or invest in projects that will reduce the most emissions.
Singularity hasn’t waded into those debates, Shi said. But the technology that it and competing firms are developing can provide the tools necessary to allow clean-energy buyers and states to go beyond high-level and potentially misleading understandings of their emissions — and get closer to actually measuring those crucial figures.
Singularity is “tracing everything, whether it’s based on power flows or contracted,” Shi added “There are technologies that are being deployed that can solve that problem.”
Companies making and deploying lithium-ion batteries in the U.S. recently gathered in Washington, D.C., to ask the federal government for the policy support they say they need. Their request came alongside a big promise: to cumulatively spend $100 billion by 2030 to build a self-sufficient, all-American grid battery industry.
“Within five years, and with $100 billion in investment, we can satisfy 100% of U.S. demand for battery storage,” said Jason Grumet, CEO of the American Clean Power Association, a trade group.
“This is unquestionably an ambitious commitment, but it is absolutely achievable if the private and public sectors work together,” he said. The $100 billion promise represents a major increase in the $10 billion to $15 billion that the American Clean Power Association estimates was invested in U.S. grid battery manufacturing and deployment last year.
As recently as a few months ago, industry analysts largely agreed that a domestic ramp-up on the scale of what Grumet proposes was at least possible, if not inevitable. Lucrative federal tax credits for companies that build and deploy clean energy technology within the nation’s borders have helped close the price gap between U.S.-made batteries and those made in China, the world’s main supplier of lithium-ion battery modules, cells, and materials.
These tax incentives, created by the 2022 Inflation Reduction Act, have also helped bolster the economics of installing large-scale batteries alongside solar power. Solar and batteries are by far the fastest-to-deploy option for utilities seeking to meet rising electricity demand from data centers, factories, electric vehicles, and broader economic growth. The two energy sources have dominated new additions to the U.S. grid in recent years.
But that’s changing under the Trump administration.
Republicans in Congress may kill the Biden-era tax credits that make domestic battery manufacturing possible. The Department of Energy Loan Programs Office, which has lent huge sums to battery manufacturers like Eos and Kore Power, could soon be shuttered or radically scaled back. And President Donald Trump’s aggressive and ever-shifting tariffs are making it more expensive for manufacturers to produce batteries in the U.S., since the duties raise the costs of everything from cells imported from China to general-purpose materials like steel and aluminum.
On Monday, China and the U.S. announced they’d temporarily ease tariffs on one another, but the situation has not been permanently resolved and leaves tariffs on Chinese imports at 30%. Manufacturers and developers still lack clarity about what the underlying economics of their business will look like months from today.
As Grumet conceded in a briefing with reporters before the American Clean Power Association’s D.C. media event in April, “there is a remarkable tension right now between probably the best fundamentals for investment in the energy sector that we’ve seen in a generation and the greatest amount of uncertainty that we’ve seen in a generation.”
When it comes to plugging batteries into the U.S. power grid, tariffs are the most immediate threat by far. The impacts are already showing up in sagging forecasts and postponed projects.
In February, the U.S. Energy Information Administration predicted the country would deploy more than 18 gigawatts of batteries in 2025, up from 11 gigawatts in 2024, continuing what’s been a meteoric increase over the past several years. But the forecast for 2025 grid battery additions has fallen in recent months, at least according to the latest analysis from the American Clean Power Association and consultancy Wood Mackenzie, which is tucked into the end of the clean energy industry group’s fact sheet for its $100 billion-by-2030 investment pledge. They predict that a little over 13 GW of energy storage will be plugged into the nation’s grid this year.
Several factors play into that drop-off, but the primary one is that nearly 70% of lithium-ion batteries in the U.S. came from China last year — and that tariffs on Chinese lithium-ion batteries and components had spiked to 156% as of last month, according to BloombergNEF.
Monday’s news that the U.S. and China had agreed to a 90-day pause on their dueling tariffs means that the blanket 145% tariffs that the Trump administration had imposed on China in April will fall to 30% as of Wednesday — at least if the deal holds.
Now, once again, energy storage companies will be recalibrating the economics of their projects, almost all of which currently rely on battery materials or components from China.
“For the next five to seven years, there is no cost-effective, time-critical alternative to battery storage to meet domestic electricity demand,” said David Fernandes, chief financial officer of OnEnergy, a grid storage and microgrid developer with 120 megawatt-hours of projects in operation and 3 gigawatt-hours in development across the U.S. and Latin America. “That means cells from China.”
Tariffs on Chinese imports simply mean the batteries that the U.S. grid needs “will just be more expensive,” he said, which will in turn drive up electricity prices.
Regardless of where tariffs settle, they have already disrupted some grid storage projects.
Take Fluence, a major U.S.-based energy storage provider that’s made more than $700 million in commitments to manufacture battery cells and modules in the U.S. to date, according to John Zahurancik, Fluence’s president of the Americas. In its second-quarter earnings call last week, the company reported a significant downward revision in its 2025 revenue forecasts, driven by decisions to “pause U.S. projects under existing contracts” and “defer entry into pending contracts until there exists better visibility and certainty on the tariff environment.”
More delays are on their way, according to Ravi Manghani, senior director of strategic sourcing at Anza Renewables, a data analytics firm focused on solar and energy storage. Of the batteries bound for grid storage deployments in the U.S. in 2025, roughly half are “at risk of getting delayed or renegotiated to make the economics work in 2026 and beyond,” he said.
Some larger-scale projects scheduled to come online this year have likely already brought their batteries into the country, escaping the tariff premium, Manghani said. But many that are procuring batteries now for delivery from late 2025 to early 2026 “are indefinitely postponed until we get more clarity around where the tariffs end up, and what happens to non-Chinese manufacturing at large,” he said.
Projects that are being built as part of state-regulated utilities’ broader generation and grid plans may be able to absorb cost increases, he said. But “merchant projects” that are operated by independent power producers in competitive energy markets are “still figuring out if they can pencil out,” he said.
In a Monday email, Manghani updated his view based on the latest news of a U.S.-China trade rapprochement.
“We will have to see if suppliers can actually ship out within this 90-day window,” he wrote. The determination of which countries end up having the most affordable battery components in the long run “will depend not only on which countries have tariffs, but where the tariff percentages exactly land.” Trump’s seesawing on tariffs “just adds another layer of complexity for long-term investments,” Manghani added.
Those dynamics could crimp the rapid pace of development in the competitive energy market of Texas, the country’s grid energy storage leader.
Stephanie Smith, chief operating officer at grid battery developer Eolian, said during the American Clean Power Association’s April briefing that Texas has been well-served by its fleet of grid batteries, which have helped the state ride through summer heat waves while avoiding grid emergencies that have plagued it in the past.
But it’s going to be harder for Texas, and the rest of the country, to keep rapidly installing grid batteries in the face of rising prices for Chinese batteries. Eolian is scrambling to “source as much outside of China as possible right now” to deal with the tariffs, Smith said. But “obviously, there are some limitations on that.”
Despite the uncertainty and rising prices, utilities and grid operators desperate to meet rising electricity demand have little choice but to build more batteries, said Gary Dorris, CEO and cofounder of clean energy-focused consultancy Ascend Analytics. That’s because the alternative — new gas-fired power plants — takes much, much longer to build.
Manufacturers of the turbines used in gas power plants are reporting up to four-year wait times for customers seeking to build power plants not already in the works, Dorris told Canary Media in an email. Solar panels and batteries, by contrast, can be ordered, shipped, and deployed in less than a year.
While the specifics of Trump’s tariffs matter — there is, after all, an enormous difference between 156% and 30% tariffs on China — at this point the hardest thing for manufacturers is “the confusion surrounding” trade policy, Dorris said.
Firms are asking, “What are the goals? Will they stay in place? How will other countries react?” he said. “This has created a lot of uncertainty, which suppresses appetite for making large, irreversible capital investment decisions.”
This unpredictability, paired with the immediate price hikes on imported materials and equipment needed to build and expand factories, has hurt the U.S. manufacturers that the Trump administration’s tariffs are ostensibly meant to help. These impacts are particularly dangerous for the still-nascent U.S. battery manufacturing sector.
The American Clean Power Association is tracking 25 major projects to build or expand grid-scale energy storage factories in the U.S., of which 11 are in operation or under construction. Much of this manufacturing capacity is for battery modules, meaning it continues to rely on Chinese battery cells and materials.
“The domestic supply chain is unfortunately going to be at the receiving end of the tariff,” Manghani said. “A lot of the raw materials that would go into domestic batteries, as well as the manufacturing equipment you need to build these cell factories, are still slated to come from China. We don’t have a lot of alternatives yet.”
That dependence on Chinese-made cells underscores just how vulnerable today’s battery-manufacturing industry is to tariffs, Grumet said. Some domestic facilities are also starting to make those cells and refine and manufacture battery materials.
Those include the facilities that Fluence has invested in that are making battery modules, cells, and associated equipment in Utah and Tennessee. It also includes Tesla’s expanding cell-manufacturing capacity from its factories in Nevada and Texas, and its lithium-refining facility in Texas.
Speaking at the American Clean Power Association’s D.C. event, Michael Snyder, Tesla’s vice president of energy and charging, highlighted the EV and grid battery manufacturer’s advances in lithium iron phosphate cells. These cells are safer and easier to source materials for than nickel manganese cobalt cells and have become the favored technology for EV batteries and grid batteries alike. Today, Chinese companies make 99% of the world’s lithium iron phosphate cells, according to Benchmark.
“We think we’re going to be the first non-Chinese company making these cells at scale, and we know there are a lot of other companies working on that as well,” Snyder said. South Korea-based LG Energy Solution in February announced plans to invest $1.4 billion in U.S. lithium iron phosphate cell production for grid storage, which will take place at the firm’s existing factory in Holland, Michigan.
But those efforts are in their early stages, and they’ll only succeed if they have customers to buy their products — a prospect made less certain by the chill settling in over grid battery deployment.
The Trump administration’s hostility to Biden-era climate policy and its broad support for fossil fuels is undermining investor confidence in the continued growth of U.S. grid battery markets, with consequences for the domestic manufacturing projects that would aim to supply them. The first three months of 2025 saw cancellations of billions of dollars in planned battery cell-manufacturing investment from Freyr Battery (now T1 Energy) in Georgia and Kore Power in Arizona.
But the bigger threat to U.S. clean energy deployment and manufacturing is the possibility that Republicans in Congress will undo the tax credits created by the 2022 Inflation Reduction Act to benefit companies that build and deploy lithium-ion batteries and many other clean energy technologies.
Republicans in Congress have pledged to extend tax cuts passed during the first Trump administration that will add trillions of dollars to the federal deficit, and they are hunting for federal spending cuts to make that possible. The estimated $780 billion in clean-energy tax credits is a tempting target. Some Republicans are arguing to keep the tax credits that undergird major investments in factories and power projects in their districts, while others have called for eliminating them completely.
These incentives currently boost the economics for grid battery projects with a 30% base credit on the cost of the up-front investment, but developers can get more if the projects obtain a certain amount of materials from domestic suppliers or if they are built in “energy communities” that face losses in jobs and economic activity due to closures of fossil fuel infrastructure. The tax credits have accelerated storage deployments — and boosted demand for batteries from U.S. manufacturers.
But for battery manufacturers, the most vital piece of policy is the 45X Advanced Manufacturing Production tax credit. That credit is tied to every unit of battery module, cell, component, and material produced domestically, at a level designed to make them cost-competitive with Chinese products.
45X has been the primary spur for investors committing hundreds of billions of dollars to U.S. clean technology manufacturing. It’s hard to see how those investors could keep their commitments if that support went away — and harder still to see how any new factories will be planned now, while the fate of that incentive is up in the air.
Road transport is responsible for around three-quarters of global carbon dioxide emissions from transport. Switching from petrol and diesel to electric vehicles is an important solution to decarbonize our economies.
This chart shows the change in share of new cars that were electric in China, the European Union (EU), and the United States (US) between 2020 and 2023. This includes fully electric and plug-in hybrid cars, though most are fully electric.
In 2020, electric cars were rare everywhere. But by 2023, over one-third of new vehicles in China were electric, compared to less than a quarter in the EU and under a tenth in the US.
While we only have annual data up to 2023, preliminary figures suggest that in 2024, electric cars outsold conventional ones for the first time in China.
Explore data on electric car sales for more countries →
Illinois’s ambitious clean energy transition, which mandates a phaseout of fossil-fuel power by 2045, depends on adding large amounts of energy storage to the grid. This is especially true now with the proliferation of data centers. Utility-scale battery installations will be key to ensuring that renewables — along with the state’s existing nuclear fleet — can meet electricity demand.
That’s why energy companies and advocates are racing to get legislation passed that incentivizes the addition of battery storage on the grid, before the state legislative session ends May 31.
On May 1, a state regulatory commission released a report outlining its recommendations for a summer procurement of grid-connected battery storage by the Illinois Power Agency, which procures power on behalf of utilities ComEd and Ameren.
Clean energy industry leaders and advocates have been pushing for storage incentives for years and were disappointed that such provisions were not included in the 2021 Climate and Equitable Jobs Act.
In a January lame-duck session, the legislature passed a narrow bill that ordered the Illinois Commerce Commission — which regulates utilities — to hold stakeholder workshops to study grid storage capacity needs and possible incentive structures. The resulting report is meant to inform legislation that backers hope will pass this spring and lead to the storage procurement this summer.
In the report, the commission noted that energy storage would reduce prices, increase grid reliability and resilience, avoid costly grid upgrades and power plant construction, facilitate renewable energy deployment, and create “macroeconomic benefits” like jobs and investment in local infrastructure.
Jeff Danielson, vice president of advocacy for the Clean Grid Alliance, whose members include renewable power and battery storage developers, said the plans are long overdue.
“Wind and solar are important, but for the grid itself to be holistically sustainable requires battery storage,” Danielson said. “Battery storage has value. It’s time for Illinois to add this tool in its toolbox for a sustainable grid.”
The report recommends that the Illinois Power Agency do an initial procurement for 1,038 megawatts of grid-connected storage this summer — a total that the commission says should include 588 MW in the PJM Interconnection regional transmission organization’s territory in northern Illinois and 450 MW in the territory managed by the Midcontinent Independent System Operator. Additional procurements by the end of 2026 should incentivize the construction of 3 gigawatts of storage to be in operation by 2030, the report says. And it calls for setting a second target for additional storage beyond 2030.
Advocates and industry groups said they are generally happy with the proposals, though energy storage and renewable industry leaders were asking for a 1,500-MW initial procurement and up to 15 GW of storage by 2035. The commission’s draft report had called for only 840 MW in an initial procurement, but after hearing public comments, it upped the amount in the final version. The industry also wants incentives for both stand-alone storage and storage paired with renewable energy, but the commission’s report recommends that the initial procurement only be for stand-alone batteries.
“It’s now up to lawmakers to meet the moment and provide both a short-term and long-term solution to high utility bills,” said Danielson. “Energy storage is the right answer, at the right time, for the right reasons.”
It’s crucial that legislation pass this year since storage developers are seeing increasing demand nationwide and deciding where to invest, said Samarth Medakkar, Illinois lead for Advanced Energy United, an industry group whose members include renewable and storage companies.
There are already gigawatts of proposed battery storage projects in Illinois that are waiting for approval from the Midcontinent Independent System Operator to interconnect to the grid. Those projects need funding to progress and meet deadlines set by the grid operator to stay in the queue, Medakkar explained.
“There’s competition — developers are looking at Illinois as a market, but they’re looking at other states as a market too,” Medakkar said. “We need to make these as least risky as possible. Procurement would give them confidence to make the payments to stay on course in the queue. We can send a signal to developers that if you make these nonrefundable payments, we will have a market for energy storage and you can bid your project into this market.”
A letter from storage and renewable developers to the chief of the Commerce Commission’s Public Utilities Bureau, offering comments on the draft report, noted that storage projects take seven to 10 years to develop, so the state needs to act soon to procure the grid battery capacity it wants online beyond the 2030 date discussed in the study.
“Developers across the country are facing a challenging federal environment, including newly announced tariffs,” the letter says. “As a result, many developers are now prioritizing their limited capital across fewer projects — focusing on states with established and supportive markets, and divesting from states that are not as far along.”
The commission’s report proposes incentivizing storage through a market for indexed storage credits, structured similarly to the state’s renewable energy credit program that has fueled a boom in solar power and, to a lesser degree, wind power. Under this design, the developer or owner of the storage is essentially allowed to sell credits for funds awarded by the state and collected from utility customers.
New York is the only other state with a storage credit market, according to experts. If Illinois passes legislation and launches the program this summer, it will be rolling out around the same time as the nascent program in New York, scheduled to hold its first procurement by the end of June. In other states, grid storage is supported through a structure known as tolling agreements, wherein utilities or other companies build and operate battery installations on the grid, and utility customers are essentially charged for their use.
In both models, residents pay for the new storage through their electric bills — just as they pay for renewables under Illinois’ existing renewable energy credit program. The Commerce Commission found that 3 GW of storage incentivized through credits would cost utility customers between 39 cents and $1.69 per month, though storage would also lead to bill savings by avoiding costlier investments in generation.
Danielson said battery storage developers prefer a tolling structure since it is a much more common and potentially more effective practice. It would be “pretty odd” if Illinois did not offer that option, he said, though ultimately, companies are eager to get legislation passed in whatever way possible.
“We’re not making a judgment about which one’s better. It just needs to be a choice,” Danielson said.
James Gignac, Midwest policy director of the Union of Concerned Scientists, said clean energy advocates are on the same page.
“I would be hopeful we can identify a way to use tolling agreements because the more options we can offer to the market, that means we’ll be getting more companies interested in proposing projects,” Gignac said. “That’s good for consumers and provides more competition. We may learn that the indexed storage credit approach is producing a certain type of project, and a tolling agreement could be offered to attract a different size of facility or different use case.”
Danielson noted that California, New York, and Texas have the largest amounts of on-grid storage in the country, and Illinois could be poised to join them.
“One thing those three states have in common is density of businesses and people,” Danielson said. “There is no good reason why Illinois should be lagging these other states in terms of these projects being built.”
The battery storage workshops this spring were “eerily similar to what we just did” in the leadup to CEJA, Illinois’ 2021 climate law, he continued. “For five years, these ideas have been studied and bantered about. Now demand is higher for sustainable power, the technology is better, [and] the costs are lower, which means Illinois leadership matters now more than ever.”
One subject of debate is whether the storage incentives should include the same focus on equity that has characterized Illinois’s existing clean energy laws – CEJA and the Future Energy Jobs Act before that. Workforce training and solar deployment programs created by these laws prioritize people and communities impacted by fossil-fuel power plants, the criminal justice system, and other indicators of inequity. The commission’s draft report recommended that storage procurement exclude such equity provisions, in part because battery storage-related jobs include dangerous, high-voltage conditions.
Members of the Illinois Clean Jobs Coalition objected, noting that solar and wind jobs also involve high voltage. In comments to the commission on behalf of clean energy groups, Gignac stated that solar and wind developers can request waivers under the state law if they can’t find equity-qualifying candidates for certain jobs; meanwhile, there is “no evidence” that equity-eligible employees and contractors would be unqualified for storage development.
The final recommendations encourage the same equity standards for storage development as for renewables, a change lauded by advocates.
“This will help ensure that Illinois is advancing equitable workforce opportunities in battery storage facilities alongside other clean energy technologies such as wind and solar,” said Gignac.
Clean energy advocates and industry representatives plan to encourage lawmakers to amend or introduce legislation based on the findings in the Commerce Commission’s report, they said
The Illinois Clean Jobs Coalition, which helped pass CEJA, is pushing for a new energy omnibus bill this legislative session. Members said they are hoping to work with industry to add storage-related language. Meanwhile, renewable and storage industry stakeholders are backing a bill that would require the Illinois Power Agency to procure energy storage totaling 15 GW online by 2035, and require utilities to charge customers to fund it. The bill would allow both credit and tolling incentive structures.
Samira Hanessian, energy policy director of the Illinois Environmental Council, said she is “cautiously optimistic” about a bill incentivizing storage passing this legislative session.
“I’m feeling a lot more positive around how storage is now coming up in most conversations with legislators and in our coordination spaces,” Hanessian said. “To me it’s become a very real policy issue that we are on track to address this session.”
The Trump administration has launched an all-out assault on American energy-efficiency efforts that have saved consumers billions of dollars and eased the transition away from fossil fuels.
From proposing to eliminate the popular Energy Star and Low Income Home Energy Assistance programs to firing staff and delaying building efficiency standards, President Donald Trump’s moves threaten to upend decades of progress on making appliances and structures do more with less energy.
“Energy efficiency is the best, fastest, cheapest way to lower energy costs,” said Mark Kresowik, senior policy director at the nonprofit American Council for an Energy-Efficient Economy. “That’s something that, ostensibly, the Trump administration said they want to do.”
Trump’s actions could undercut his own promise to halve energy bills during his first 18 months in office, as well as hamper climate action.
Efficiency is an undersung tool for reducing carbon pollution. If the globe maximized efficiency efforts, it could phase out fossil fuels by 2040, according to nonpartisan clean energy nonprofit RMI. It’s typically the lowest-cost way utilities can meet power needs, a crucial consideration as electricity bills rise around the country. And with electricity demand forecast to climb to record highs due in large part to the rapid expansion of AI data centers, efficiency could take on new importance as a way to get more out of every unit of energy.
One of the most recent and notable moves against efficiency programs is the Environmental Protection Agency’s plan to kill Energy Star. The EPA announced the decision to shutter the program at an all-hands meeting last week, according to The Washington Post, though the agency has not publicly confirmed the decision.
Energy Star is a voluntary program that certifies the most efficient appliances available to American households and businesses. Products that have earned the iconic aqua-blue label span dozens of residential and commercial categories, including data center storage, water heaters, clothes dryers, furnaces, and heat pumps.
The program has been wildly successful. Since 1992, Energy Star has prevented 4 billion metric tons of planet-warming greenhouse gas emissions — equivalent to a year’s pollution from 933 million cars — and helped consumers save more than $500 billion in energy costs. For every dollar the federal government spends on the program, consumers save a whopping $350.
Axing Energy Star would also scramble eligibility for federal and local incentives that require the program’s seal of approval, such as the $2,500 tax credit for home builders.
More than 1,000 companies, building owners, and other organizations have come out in support of Energy Star. “Eliminating it will not serve the American people,” a coalition of appliance manufacturers and industry leaders wrote in a letter to EPA head Lee Zeldin, Inside Climate News reported.
Energy Star isn’t the only federal energy-efficiency program in peril.
In April, the Department of Health and Human Services fired the more than two dozen staff members who administered the Low Income Home Energy Assistance Program (LIHEAP), according to Harvest Public Media. The initiative provided financial support to nearly 6 million households in 2023 across all 50 states and the District of Columbia, helping vulnerable Americans cover utility costs, undertake energy-related home repairs, and make weatherization upgrades that reduce energy bills.
Released in early May, the president’s “skinny” budget proposal for the next fiscal year recommends shuttering the $4 billion program, which in particular helps households with older adults, individuals with disabilities, and children.
Cutting program funding and failing to hire back staff may affect more than energy bills, according to advocates.
“The elimination of the staff administering LIHEAP could have dire, potentially deadly, impacts for folks who will not be able to safely cool their homes as we enter what is predicted to be another historically hot summer,” Amneh Minkara, deputy director of Sierra Club’s building electrification campaign, said in a statement.
President Trump and Congress are also targeting efficiency standards for appliances sold in the U.S. The president just signed four resolutions to undo a handful on Friday.
That’s despite both Democrats and Republicans saying they want appliance standards. According to an April poll by Consumer Reports, 87% of Americans, including four out of five Republicans, agree that new home appliances for sale in the U.S. should be required to achieve a minimum level of efficiency.
Part of the administration’s strategy will likely include simply not enforcing the standards, according to the Appliance Standards Awareness Project. Last month, ProPublica reported that Elon Musk’s Department of Government Efficiency team had “deleted” the consulting contract that the Department of Energy relies on to develop and enforce these rules. But the item subsequently disappeared from DOGE’s online “wall of receipts,” making its status cloudy.
Beyond appliances, the Trump administration is snarling rules for more efficient buildings, too.
In March, the Department of Housing and Urban Development delayed compliance deadlines set by a landmark 2024 measure that requires certain new homes purchased with federally backed mortgages and new HUD-funded apartments to meet updated building energy-efficiency codes. The rule would save single-family households an average of $963 per year on energy bills, according to the agency’s estimates, and affect up to a quarter of new homes nationwide, per RMI. The administration wrote in a recent court filing that it is “actively considering whether to revise or revoke” the rule.
In April, the Department of Energy proposed to indefinitely delay implementing efficiency standards for manufactured homes that would reduce average annual energy costs by $475.
And on May 5, the agency punted by a year the compliance date for a standard that would ensure federal buildings that are built or significantly renovated between this year and 2029 slash on-site fossil-fuel use by 90%. In 2030 and beyond, the standard requires new and renovated federal buildings to be all-electric.
That rule, Energy Star, and many of the other energy-efficiency efforts under threat are congressionally mandated — and not all Republicans are rolling with the administration’s attacks.
In a statement earlier this month, Sen. Susan Collins, a Republican from Maine, said she had “serious objections” to some measures in Trump’s budget blueprint, including the elimination of LIHEAP. Collins, who chairs the Senate Appropriations Committee, noted that “ultimately, it is Congress that holds the power of the purse.”
Corrections were made on May 12, 2025: This story originally misstated that consumers buying heat pumps must purchase Energy Star-certified equipment to qualify for the $2,000 25C federal tax credit. The tax credit does not base eligibility on Energy Star, but rather on the Consortium for Energy Efficiency specifications. The story also originally misstated that a handful of resolutions to undo federal efficiency standards await the president’s signature. President Trump signed the resolutions on May 9, 2025.
In his first 100 days, President Donald Trump has antagonized the clean energy industry, putting crucial federal funding on ice, rolling back key regulations, and even coming after state climate laws.
This week, Democrat-led states took to the courts to begin fighting back.
On Monday, attorneys general from 17 states and Washington, D.C., filed a lawsuit aimed at protecting the clean energy sector that’s caught most of Trump’s ire: wind.
Trump’s Day 1 executive order paused the approval of new federal leases, permits, and loans for wind farms, and his EPA and Interior Department have gone on to revoke existing permits from one offshore project and order work to stop on another that had already begun at-sea construction.
The suit alleges the president doesn’t have the authority to single-handedly shut down the permitting process — and that his moves threaten thousands of jobs, billions of dollars in investments, and the country’s clean energy transition.
In an interview with Canary Media’s Clare Fieseler, New Jersey Attorney General Matthew Platkin said Trump’s anti-wind orders fly in the face of his “energy dominance” goals, on top of being carried out unconstitutionally.
“This is a time when we’re dealing with rising costs, when everyone agrees we should be increasing domestic energy production,” Platkin said. “It’s flagrantly illegal, but it also just makes no sense.”
Environmental advocate and renewable energy professor Chris Powicki speculated to Massachusetts local news station CAI that Republican-led states may become quiet backers of the suit, given that Trump’s order also targets onshore wind farms, which many of them have benefited from.
A similar coalition of 16 states and D.C. hit the courts again on Wednesday, this time suing the U.S. Transportation Department for withholding billions of dollars for a national electric-vehicle charger buildout. The attorneys general alleged the administration’s move is illegal since the funding was allocated as part of the 2021 bipartisan infrastructure law, meaning only Congress has the power to pull it back. A rollback would jeopardize hundreds of charging stations that haven’t yet been built.
Energy Star is Trump’s latest target
President Trump’s attacks on energy efficiency reached new heights this week, as the U.S. EPA reportedly told staffers it’s planning to shut down its Climate Protection Partnerships division and the Energy Star program it houses. If there’s one EPA program you know, it’s probably Energy Star, which uses its signature blue sticker to indicate how much energy — and money — an appliance can save consumers.
Republicans in Congress have also made several moves against energy efficiency in the past few weeks, passing resolutions to undo Biden-era regulations governing commercial refrigerators, water heaters, and other appliances, and to repeal a rule affecting efficiency labeling and certification. More cuts could be on the way as the Trump administration and Congress work to roll back Inflation Reduction Act tax credits — some of which reduce the cost of home efficiency upgrades.
This offshore wind farm is a win for sea life
A new in-depth study of the South Fork offshore wind farm shows fish have nothing to fear when it comes to turbines. Scientists surveyed the seafloor off the Long Island coast before, during, and after the array’s construction and found it had no negative impact on the area’s biological communities. The wind farm also became a makeshift reef for marine invertebrates to latch onto, attracting dozens of fish and shellfish species to feast.
The study is further proof that the installations don’t necessarily pose serious threats to marine life — something President Trump and other offshore wind opponents have repeatedly alleged. And despite ongoing federal animosity toward offshore wind, two developers recently said they’ll continue building. Danish energy company Ørsted said it will move forward with its New York and Rhode Island wind farms, while Canary Media’s Clare Fieseler reported this week that Dominion Energy is pressing on in the waters off Virginia.
Manufacturing at risk: The Trump administration looks to gut the Energy Department’s Industrial Demonstrations Program, putting 26 U.S. manufacturing projects and thousands of jobs at risk. (Canary Media)
IRA uncertainty continues: A Republican Congress member says there’s “a lot of disagreement” in his party over whether to preserve, edit, or repeal Inflation Reduction Act tax credits. (E&E News)
A cleaner rebuild: A new report makes the case that it could be cheaper and quicker to replace Los Angeles buildings destroyed in January’s wildfires with all-electric structures, even after Mayor Karen Bass exempted rebuilds from all-electric building codes. (Canary Media)
Unfair share: As congressional Republicans look to tax EV drivers to make up for lost gas-tax revenue, an analysis shows EV and hybrid-vehicle owners would pay far more under those fees than drivers of gas-powered cars pay in fuel taxes. (Washington Post)
What’s the holdup? Energy analytics firm Enverus finds Texas has some of the shortest wait times for solar and wind projects looking to interconnect to the power grid, while California’s wait times are among the longest. (Forbes)
Oversight, out of mind: The U.S. EPA hasn’t filed any new cases against major polluters under President Trump, and has significantly scaled back minor criminal and civil enforcement cases. (Grist)
The grid’s growing pains: Grid operator PJM Interconnection selects 51 projects, mostly gas-fueled power plants and battery storage facilities, to jump to the head of its interconnection queue as part of an effort to get power online faster. Opponents to a similar plan in the Midwest say it could worsen grid bottlenecks while discouraging cheaper and clean energy. (E&E News, Canary Media)
A salty development: Startup Inlyte Energy looks to commercialize iron-salt battery technology invented in the 1980s, and is launching its first large-scale test with Southern Co., one of the biggest utilities in the U.S. South. (Canary Media)
Lots of costly and dangerous things can go wrong with high-voltage transmission lines.
Strong winds or equipment failures can cause individual lines on a tower to contact one another and short-circuit, or even break entirely. Lines can sag hazardously near trees or the ground, either due to overheating or being caked in ice. They can be damaged by wildfire smoke, windblown debris, or the simple wear and tear of time.
Sensors can help detect such threats. But it’s expensive and time-consuming to install, connect, and maintain those devices along power lines crossing remote plains, forests, and mountains.
It would be a lot cheaper and faster for utilities if they could simply use existing infrastructure to detect these issues instead of tacking on new sensors. That’s the route that Prisma Photonics has taken.
The Israel-based company has plugged its technology into the fiber-optic communications cables strung alongside thousands of miles of transmission lines in Israel, Europe, and the U.S.
That technology has been able to identify the precise locations of problems causing power outages, including ice buildup on power lines and nearby wildfires, all by “using the fiber as a microphone, or as an array of thousands of small microphones,” Eran Inbar, Prisma Photonics’ CEO, explained. The firm’s product has even picked up on the explosion of a meteor in the Earth’s upper atmosphere.
For decades, utilities have strung “optical ground wire” fiber-optic cables atop transmission towers, both to protect high-voltage wires from lightning strikes and to provide telecommunications for internal or third-party use. Across the world and the U.S., more than half of the transmission system is outfitted with these cables, Inbar said — and that coverage is only growing as more power lines are built.
That opens up a huge market for Prisma Photonics, as long as it can prove its technology is accurate enough to replace purpose-built sensors for a growing number of tasks. The more jobs Prisma’s technology can do, the more money it could potentially save transmission grid operators, Inbar said.
Finding ways to do more things with less money and less time is important for transmission owners striving to solve multiple challenges at once. Climate change-driven heat waves and winter freezes are causing more grid emergencies, both by increasing demand for electricity for air conditioning and heating and by subjecting transmission networks to increased stress.
“The grid is a very important market — but it was also a blue ocean. There were no other companies playing in this field,” said Inbar, a physicist by training who spent 20 years in the field of lasers for semiconductor and mobile technology markets before selling his company in 2014 and launching Prisma Photonics in 2017. “Can we detect short circuits? Can we detect partial discharge? Can we detect wildfire? Can we detect wind for dynamic line rating?”
Prisma’s “optical interrogator” devices plug into substations, where multiple transmission lines and the fiber-optic cables that run atop them converge. From these central points, its devices send pulses of light down an optical fiber, then capture and analyze infinitesimal reflections cast back from points along the fiber.
This is one of several methods to use fiber-optics as sensors to detect shifts in temperature, pressure, strain on the cables, and other signals, Inbar said. “It’s a very small change — but if you’re using a precise optical method, you can measure it.”
Connecting these nearly imperceptible variations to changes in the surrounding environment takes a ton of data, some complicated machine-learning algorithms to convert it into usable information, and a lot of real-world cross-checking, he said. One of Prisma’s first tasks was to eliminate the false positives — alerts of events that didn’t actually happen — that have stymied earlier efforts to use already-deployed fiber-optic cables to sense environmental conditions.
“You have to be highly committed to data collection,” he said. “There’s no way to do it in the lab — you have to go to the grid and collect data over months or, in our case, years.”
But the more Prisma’s systems are used in the real world, the more confident customers can be in correlating their measurements with real-world events. After a yearslong deployment with Prisma investor Israel Electric Corp. and other pilot projects with the New York Power Authority and as-yet-unnamed European grid operators, “we don’t have to do months and years of data collection” when deploying with its next utility partners, Inbar said. “We can go to work immediately.”
That’s the goal of Prisma’s latest project with Great River Energy, a rural electric cooperative operating transmission lines across Minnesota and Wisconsin. The initial project is targeting about 90 miles of power lines, all being monitored from computers operating inside substations.
“There is a huge impetus for reliability on the electric system,” said Michael Craig, Great River Energy’s manager of energy management systems. At the same time, “every time we’re looking to spend money, we have to justify that it’s going to be worth it to everybody in our membership. With Prisma, there were a couple of things that made it easier for us.”
“First, it’s using existing assets,” he said, referring to the fiber-optic cables already deployed on the 90 miles of line the co-op is monitoring. “We didn’t have to do this big buildout. It’s just going into the substation and doing the work” to connect Prisma’s equipment to the fiber-optic system.
Second, Prisma’s technology could offer a lower-cost way to deal with grid faults, Craig said. A bewildering array of technologies and techniques go into determining just where and how power flows have been interrupted along high-voltage power lines. Generally speaking, more precise approaches require more costly technologies, including sensors installed on transmission lines themselves.
Being able to tap into the continuous sensor of a fiber-optic line could help. “If there is an outage, maybe we’ll be able to detect what happened before we get out there,” he said. “Hopefully we can detect things more quickly. We hope it can allow us to be preventative, rather than reactive.”
Third, Prisma’s technology can potentially do many things at once, Craig said. One option is to use it for “dynamic line rating” — determining how much power transmission lines are able to safely carry under different temperatures and wind speeds, a process which can expand the capacity of existing grids without costly upgrades. Great River Energy is already testing dynamic line rating sensors installed on power lines but is eager to explore other approaches, he said.
At the same time, Craig said, Great River Energy is exploring the use of cameras in remote areas to detect wildfires — another pressing concern for power grid operators. With Prisma, “instead of installing cameras and having this one system, we can use the existing fiber as a sensor. That’s a cool way to do it.”
Inbar stressed that Prisma Photonics is still in the process of gaining real-world experience to prove how useful it can be for different tasks. Utilities must wait for bad things like faults or wildfires to happen to be able to check the technology’s accuracy, for example. Inbar added that Prisma plans to evaluate its dynamic line rating capabilities through tests hosted by the Electric Power Research Institute, a nonprofit power-sector research group considered the gold standard for utilities.
Whatever the use case, “one of the benefits of our solution is that it’s a platform,” he said. “It’s not like we’re developing a sensor for dynamic line rating or wildfire detection. It’s a platform that can collect very sensitive data on the grid, and eventually we can improve it over time — and build additional use cases.”
Antonio Baclig spent eight years as a researcher at Stanford University scouring as many battery designs as he could find in search of something cheap enough to transform the grid. He honed in on one from the 1980s that stores energy with iron and table salt, and founded the startup Inlyte Energy in 2021 to commercialize it anew.
“Our goal is solar-plus-storage baseload power that costs less than fossil fuels,” Baclig said.
Now Inlyte has secured its first major utility contract, a crucial step in proving the viability of the technology.
Southern Co., which owns the biggest utilities in Alabama, Georgia, and Mississippi, has agreed to install an 80-kilowatt/1.5-megawatt-hour Inlyte demonstration project near Birmingham, Alabama, by the end of the year. Utilities need to see new technologies work in the field before they take a chance on large-scale installations, so this project marks a necessary, but still early, stage in Inlyte’s commercialization.
New types of batteries are notoriously difficult to bring from the lab to large-scale production. Many startups have toiled at this task for years, pitching anyone who will listen about the superiority of their technology. None have come close to unseating the dominant lithium-ion battery designs that have plummeted in cost over the last decade as China massively scaled up production. But researchers have concluded that lithium-ion batteries can never get cheap enough for the mass deployments of storage that will be needed to run a grid dominated by renewable energy.
The onus is on Inlyte, then, to avoid the lackluster fate of its peers and prove its exceptionality among the ragtag camp of lithium-ion alternatives. The company has three important things going for it: dirt-cheap cost of materials, a simpler-than-usual manufacturing process, and system-level round-trip efficiency on par with lithium-ion battery systems. (Round-trip efficiency is a metric for how much of the electricity stored in a battery can later be recovered. The technologies challenging lithium-ion tend to fare poorly on this front.) Plus, the work of researchers in prior decades has already helped speed Inlyte’s path to market.
Some battery-startup founders have spent years toiling away in a lab on a favored chemistry, only to spend more years figuring out how to turn it into a viable product. Baclig, a materials scientist, surveyed the annals of battery science and plucked something off the proverbial shelf that had almost hit the big time but not quite.
He landed upon the family of sodium metal halide batteries, first developed in the late 1970s. A British firm called Beta Research explored iron-sodium batteries but in 1987 pivoted to nickel-sodium because its superior energy density made it more promising for electric vehicles.
The sodium-nickel-chloride chemistry became known in battery industry lore as the ZEBRA battery, because it was developed by a group called Zeolite Battery Research Africa. It got some traction in the 1990s: Daimler Benz built cars with this kind of battery and test-drove them for more than 60,000 miles. A European company called Horien still manufactures the battery for specialized uses, like a NATO rescue submarine and uninterruptible power supply at industrial facilities that can’t afford to go dark for even an instant.
Baclig contends that the historical abandonment of iron-salt chemistries did not reflect an intrinsic failing in the technology, just a different set of needs at the time. Today, with record solar panel installations reshaping electricity systems around the globe, there’s growing interest in cheap, long-term energy storage. And power plants don’t need to cram as much energy into a confined space as electric vehicles do.
“We have to focus this on cost now. It’s not [primarily] about energy density,” Baclig said. With those new parameters, putting the iron back into the battery might just work.
Baclig reached out to the company that had pioneered the technology in the first place: Beta Research. That firm was looking for a new project to focus on as the Covid pandemic receded, Baclig said; after a year of conversations, he and Beta Research decided to join forces in 2022. Inlyte thus pulled off a rare feat among climatetech startups, or any kind of startup: successfully conducting an international acquisition before it had even raised seed funding. The startup subsequently closed an $8 million seed round in 2023.
Since then, the team has worked at a steady clip to dial in the best iron cathode for the grid storage job. They also scaled up the size of each cell, which, unlike in lithium-ion batteries, takes the form of a ceramic tube that gets filled with powdered iron and salt. The new tubes hold 20 times the energy of the previous, EV-oriented cells.
From there, Inlyte set about testing its new battery cells, culminating in a recent third-party engineering test of a 100-cell module. Engineers typically have to tinker and improve a newfangled battery to unlock the desired level of performance. In this case, Baclig said, “That was our first module, and it just worked. We’re building on something that has a long track record, so we don’t have to reinvent.”
The chance to innovate on a legacy design attracted the firm’s chief commercial officer, Ben Kaun, who spent many years analyzing alternative grid storage concepts for the Electric Power Research Institute, a nonprofit research arm of the U.S. utility industry.
“It takes a long time to take a technology from the lab to deployment — there’s a lot of layers of scale-up and integration,” Kaun said. “It was appealing to me how much of that had been worked out with [Inlyte’s battery].”
Southern Co. will install and operate the first large-scale Inlyte battery system for at least a year as part of its ongoing efforts to test emergent long-duration storage technologies in a real-world environment.
The utility company was attracted to Inlyte’s low fire risk (it does not use flammable electrolytes like conventional lithium-ion batteries) and its ability to be sourced domestically, Southern Co. R&D manager Steve Baxley noted in an email.
“This system has the potential to be cost-competitive with lithium-ion batteries, particularly for longer durations,” he said.
The company’s subsidiary Georgia Power previously signed a landmark deal to test out another iron-based long-duration battery, from Form Energy, starting in 2026. (Baxley confirmed that project is still being developed.)
Researchers from the Electric Power Research Institute, Kaun’s former employer, will document the results of the Inlyte installation and share them with utilities around the country.
“A lot of companies will share the same learnings, so we don’t have to do the same pilot over and over again in every service territory,” Kaun said.
Of course, habitually risk-averse utilities often prefer to test-drive new technologies in their own backyard, even if that duplicates efforts elsewhere. Many utilities continued to tiptoe into lithium-ion battery installations even after the batteries had been operating for years on a massive scale in other parts of the country.
Baclig, for his part, hinted at many more trial runs in the works for next year. These projects will be doable because Inlyte gained possession of a pilot-scale factory in the U.K. as part of the Beta Research acquisition. That facility can pump out megawatt-hour-sized volumes for early test projects, but it won’t keep up if Inlyte starts closing commercial deals.
Baclig has begun seeking a location for a factory in the U.S. Building a first-of-a-kind factory can be risky, but he stressed that four factories have been set up around the world for essentially the same technology, and the Beta Research team advised on all of them. The plan is to build at the same scale as those previous facilities, to minimize uncertainty around factory economics.
“It’s not quite Intel’s ‘copy exact,’” Kaun said, referring to the pioneering microchip firm’s famous approach to replicating its factory designs. “But it’s ‘copy very similar.’”
Filling ceramic tubes with metal powders doesn’t require the same pinpoint precision as a lithium-ion battery factory. When companies construct lithium-ion factories in the U.S., they have tended to cost at least $1 billion; the capital cost for a full-scale Inlyte factory should be multiples lower than that, Kaun noted.
Furthermore, the machinery to manufacture this unique battery does not come from China’s dominant battery sector, a boon at a time when the Trump administration’s tariffs are driving up prices on Chinese imports (even the equipment needed to build factories in America).
Going forward, Inlyte will need to move from field demonstration to customer contracts, and the company is focused on buyers who need power every day but also have occasional long-term backup requirements.
Inlyte is pursuing utilities like Southern Co., which must deliver power to a fast-growing region while surviving hurricanes and other extreme weather. The startup also has a dedicated pitch for providing data centers with backup energy: The long-lasting iron-sodium batteries can ostensibly replace both the instant response from uninterruptible power supply systems and the diesel generators that would kick in until power is restored. And the batteries could run every day to lower a data center’s demand from the grid.
Convincing data center owners to adopt Inlyte’s product will not be trivial, but that sector is struggling to find the power capacity to fuel its growth, not to mention maintain corporate commitments to sourcing clean electricity. If Inlyte can really deliver clean, long-lasting power that’s cheaper than fossil-fueled alternatives, it would almost certainly find willing takers with the ability to pay.
The wildfires that ravaged parts of Los Angeles County in January were the most catastrophic in its history. Made worse by climate change, the disaster caused as much as $131 billion worth of damage and destroyed more than 16,000 homes and other properties.
In the name of a speedy recovery, LA Mayor Karen Bass, a Democrat, issued a broad executive order that same month, exempting replacement structures from a city ordinance that requires new buildings to be all-electric. (The waived code only applies to communities within the city boundaries, not to the entirety of LA County.)
The order effectively swept aside one of the city’s most important tools for eliminating its reliance on planet-warming fossil fuels, the continued use of which makes such climate-related disasters more likely in the future. Buildings accounted for more than 40% of LA’s carbon pollution in 2022 — more than any other sector — and are estimated to contribute a quarter of California’s total emissions.
The mayor’s move reflects a tacit assumption that has been echoed even in the State Assembly: that rebuilding with gas, which many of the affected buildings had used, must be the easiest path for recovering communities.
But a new report flips that premise on its head. Citing available research and expert interviews, a team at the University of California, Berkeley’s Center for Law, Energy, & the Environment argues that all-electric construction is likely to be the fastest and most cost-effective way to rebuild after the LA fires.
A key reason is that two systems are more complicated to rebuild than one. “We’re going to install electricity infrastructure in all buildings regardless,” said Kasia Kosmala-Dahlbeck, climate research fellow at the UC Berkeley center. “So it’s really about whether you also install a second system” that delivers fracked gas, also commonly known as natural gas.
Such dual-fuel construction has historically been the norm in California, but all-electric construction avoids the added time and cost of hooking up gas infrastructure. That often requires property owners to submit a separate service request to the gas utility; install gas meters, pipes, and ductwork; and coordinate gas safety checks, according to the authors.
The team expects all-electric rebuilds to not only deliver better indoor air quality for occupants but to be easier on people’s wallets. Their report cites a 2019 study that estimates building a new all-electric home in most parts of California costs about $3,000 to $10,000 less than building a home that’s also equipped with gas. The UC Berkeley team notes, though, that potential savings for LA County’s wildfire-hit neighborhoods are likely lower since existing gas infrastructure, much of it underground, was largely unscathed.
All-electric new homes in California that skip gas-burning appliances for much more efficient electric heat-pump heaters and ACs, water heaters, and clothes dryers, as well as induction stoves, are also likely to slash energy bills, per the report. An April analysis by climate think tank RMI provides support, finding that single-family households switching from gas furnaces and conventional air conditioners to heat pumps would save about $300 per year on average in LA County.
Kosmala-Dahlbeck points out that people going the all-electric route now will be able to avoid costly and complex retrofits in the future.
“We’ve seen repeatedly that retrofitting later down the line is more expensive than constructing all-electric to begin with,” she said. Upgrading a home’s electrical service alone can cost anywhere from $2,000 to $30,000 and take two months to two years, according to California-based all-electric home developer Redwood Energy.
In the near future, installing a new gas appliance when the old one conks out could be less of an option. Air regulators for the state are developing standards that could bar the sale of new gas furnaces and water heaters starting in 2030. Regulators covering LA County are poised to adopt rules that would discourage new installations of these polluting appliances as soon as 2027.
The report authors recommend that policymakers — including city council members, county supervisors, the mayor’s office, and state legislators and agencies — support an all-electric recovery.
Mayor Bass has already moved in that direction. While her office confirmed that the first executive order waiving all-electric standards remains in effect, she issued another directive on March 21: By later this month, LA departments must develop suggestions to streamline permitting for owners who rebuild with all-electric equipment.
Construction has begun in LA’s Pacific Palisades neighborhood, one of the areas hit hardest by the wildfires. According to the mayor’s office, 20 addresses in the Palisades have been issued permits for rebuilding efforts. Staff noted that the permits don’t have to specify whether a project is all-electric. But some affected residents do plan to rebuild without gas appliances, NPR recently reported.
All-electric new buildings are on the rise across California, according to the California Energy Commission. In 2023, 80% of line extension requests by builders to utilities Pacific Gas & Electric and San Diego Gas & Electric were electric-only.
In general, outside of the fire recovery process, the financial case for building all-electric homes in the state is getting stronger. “We’ve heard from California builders that recent updates to infrastructure rules — combined with a statewide energy code that strongly encourages heat pumps — have shifted the economics of building all-electric new construction,” said Will Vicent, deputy director of the Energy Commission’s building standards efficiency division.
The UC Berkeley team is also encouraging policymakers to bolster incentives and resources that make all-electric rebuilding more affordable. That could look like expanding the Rebuilding Incentives for Sustainable Electric Homes program and the electrification resource and rebate hub The Switch is On. Such investments would line up with LA County and the state’s climate goals to become carbon neutral by 2045.
Jonathan Parfrey, executive director of LA-based nonprofit Climate Resolve and an appointed member of a county commission focused on rebuilding sustainably after the fires, said the report’s findings are important for policymakers to consider as they help people who lost their homes navigate the potentially yearslong process of recovery.
“It’s an enormously traumatic experience, and the first impulse that you have after that terrible loss is a return to normalcy” by trying to rebuild what you once had, said Parfrey, who reviewed the UC Berkeley report before it was publicly released. But “it’s impossible to recapture that home once it’s gone.”
Instead, “there’s the possibility for creating something even superior to what you had before.”
Around the world, farmers are retooling their land to harvest the hottest new commodity: sunlight. As the price of renewable energy technology has plummeted and water has gotten more scarce, growers are fallowing acreage and installing solar panels. Some are even growing crops beneath them, which is great for plants stressed by too many rays. Still others are letting that shaded land go wild, providing habitat for pollinators and fodder for grazing livestock.
According to a new study, this practice of agrisolar has been quite lucrative for farmers in California’s Central Valley over the last 25 years — and for the environment. Researchers looked at producers who had idled land and installed solar, using the electricity to run equipment like water pumps and selling the excess power to utilities.
On average, that energy savings and revenue added up to $124,000 per hectare (about 2.5 acres) each year, 25 times the value of using the land to grow crops. Collectively, the juice generated in the Central Valley could power around 500,000 households while saving enough water to hydrate 27 million people annually. “If a farmer owns 10 acres of land, and they choose to convert 1 or 2 acres to a solar array, that could produce enough income for them to feel security for their whole operation,” said Jake Stid, a renewable energy landscape scientist at Michigan State University and lead author of the paper, published in the journal Nature Sustainability.
The Central Valley is among the most productive agricultural regions in the world: It makes up just 1% of all farmland acreage in the United States yet generates a third of the nation’s fruits and vegetables. But it’s also extremely water-stressed as California whiplashes between years of significant rainfall and drought. To irrigate all those crops, farmers have drawn so much groundwater that aquifers collapse like empty water bottles, making the earth itself sink by many feet.
Farmers can’t make their crops less thirsty, so many have been converting some of their acreage to solar. The Central Valley is ideal for this, being mostly flat and very sunny, hence the agricultural productivity. At the same time, farmers have been getting good rates for the electricity that they offset and that they send back to the grid.
Now, though, California has adopted standards that reduce those rates by 75% on average. For a farmer investing in panels, the investment looks less enticing. “The algebra or calculus — or whatever math discipline you want to reference — it just doesn’t work out the same way,” said Karen Norene Mills, vice president of legal advocacy at the California Farm Bureau, which promotes the state’s agricultural community.
Also, the study found that by fallowing land for solar panels, food production in the Central Valley dropped by enough calories to feed 86,000 people a year. But, Stid said, markets can adjust, as crops are grown elsewhere to make up the deficit. By tapping the sun instead, Stid added, growers can simultaneously help California reach its goals of deploying renewable and reducing groundwater usage.
The tension, though, is meeting those objectives while still producing incredible quantities of food. “That is always our concern about some of these pressures,” Mills said.
But this isn’t an either-or proposition: Many farmers are finding ways to grow some crops, like leafy greens and berries, under the panels. The shade reduces evaporation from the soil, allowing growers to water less often. In turn, a wetted landscape cools the panels, which improves their efficiency. “This is the compromise that’s going to allow for both energy independence and food security,” said horticulturalist Jennifer Bousselot, who studies agrisolar at Colorado State University but wasn’t involved in the new study.
Farmers are also turning livestock loose to graze under their panels. Their droppings fertilize the soil, leading to more plant growth and more flowers that support native pollinators. “The grass, it’s so much more lush under the panels, it’s amazing,” said Ryan Romack, founder of Virginia-based AgriSolar Ranch, which provides grazing services. “Especially when the sheep have been on site long-term, you can really see the added benefits of the manure load.”
Then, if a farmer decides not to replace the solar panels at the end of their lifespan — usually around 25 or 30 years — the soil will be refreshed with nutrients and ready to grow more crops. Even if a grower simply lets them sit for decades without any management, the fallowing can restore the soil’s health. “We really see solar as a collective landscape,” Stid said, “that can be sited, managed, and designed in a way to benefit both people and the planet and ecosystems as well.”
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