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The U.S. battery supply chain just got a little stronger.
LG Energy Solution, a division of the major Korean battery manufacturer, is now producing battery cells for grid-scale energy storage at a site in Holland, Michigan. The company spent $1.4 billion to expand the factory, which previously made electric vehicle batteries. At full capacity, the new lines will produce 16.5 gigawatt-hours of lithium iron phosphate cells per year.
“That’s a sizable portion of annual domestic demand for energy storage battery cells,” said Noah Roberts, vice president for energy storage at the American Clean Power Association trade group, who toured the LG factory Tuesday. “It’s a testament and demonstration of the industry’s commitment to onshoring manufacturing and ramping it up in short order.”
The lithium iron phosphate chemistry, often abbreviated as LFP, has grown increasingly popular for stationary storage and EVs; it offers fire-safety benefits, durability, and lower costs compared to the typical electric vehicle chemistries, at the expense of some energy density. Until now, American battery customers had to turn to China for any LFP supplies. LG’s facility appears to be the largest giga-scale LFP production in the U.S. Japan’s AESC recently launched LFP production at its factory in Smyrna, Tennessee, and Tesla is working to onshore LFP production as well.
As such, LG’s investment is strengthening the U.S. clean energy supply chain at a time of great precariousness, when several other would-be battery manufacturers have failed to deliver.
The plan originated as a way to bolster local supply chains, before Congress passed concerted battery manufacturing incentives, said Jaehong Park, CEO and president of LG Energy Solution Vertech, which focuses on stationary grid storage. But when the Inflation Reduction Act of 2022 created incentives for manufacturing and grid storage deployment, LG upped its planned capacity from 4 gigawatt-hours to the eventual 16.5.
The company initially intended to install these manufacturing lines in Arizona, but relocated them to a portion of its Holland facility that had been developed to expand EV battery production, which LG has done there since 2012. By shifting the LFP equipment to the space in Holland, LG could open commercial production a full year earlier than originally planned, noted Tristan Doherty, chief product officer at the storage division.
Now the Holland manufacturing space covers the area of 42 football fields, and will employ 1,700 people when fully staffed.
“It is very clearly a state-of-the-art facility with the most advanced manufacturing that you can have in the United States,” Roberts said.
The LFP products are booked up six months out, and LG is already looking at doubling the production capacity next year, Park said.
Manufacturers took a gamble in betting that the U.S. could reshore the battery production that China has cornered with dedicated industrial policy over the last decade or more. Companies need to build new industrial hubs and train American workers, and then try to match the quality and consistency of the incumbent industry in China.
The Biden administration passed several incentives to reduce the cost premium for “Made in the USA” batteries, including tax credits for purchasing electric vehicles with domestic batteries, and bonus credits for grid storage developers who buy domestic content.
But the current Republican majority in Congress is working to eliminate those policies, to save money for much more costly deficit spending in President Donald Trump’s signature policy bill. Companies like LG that greenlit multibillion-dollar factory investments under one tax credit regime no longer know which rules will apply when they start production.
Doherty acknowledged there’s a great deal of uncertainty at the moment, but said he’s confident in the long-term bet on U.S. battery production.
“It’s clear that the industry is here and it’s here to stay — the question is just what it looks like and what are the nuances to make it work,” he said. “There’s a lot of very big deals that are in the works. Everyone understands, you need to get U.S. battery supply in your supply chain as quickly as possible.”
Trump’s massive tariffs on China could in theory support domestic producers. But the president has changed his tariff plans from week to week, denying would-be manufacturers the stable business environment they like to see before committing billions of dollars to a yearslong endeavor. Blanket tariffs on China also inflate the cost of battery materials, which are almost entirely processed in that country, as well as the cost of battery manufacturing equipment, which also largely originates there.
LG, as a South Korea-based conglomerate, has been able to avoid the negative scrutiny that American politicians have increasingly leveled at Chinese clean energy manufacturers. LG now sources its battery materials for Holland from outside China, and its manufacturing equipment came from Korea and Japan, Park said.
When Trump came into office, the U.S. was on track to achieve self-sufficiency in battery cell production, per a 2024 analysis by Argonne National Laboratory. The U.S. could make 74 gigawatt-hours of lithium-ion battery cells in 2023, but was set to grow that to 1,133 gigawatt-hours by 2030, comfortably more than expected demand.
During Trump’s tenure, though, new manufacturing investments have plummeted compared to the Biden years, and project cancellations surged to nearly $8 billion in the first quarter of 2025. In that time, for instance, Freyr Battery canceled a planned battery factory in Georgia (and later rebranded itself as T1 Energy), and Kore Power axed a lithium-ion factory slated for Arizona.
Elsewhere in Michigan, startup Our Next Energy has been laboring to build the first large LFP factory in the U.S. But it has yet to secure the funding necessary to fill out the cavernous building it acquired west of Detroit, and the company is struggling to stay afloat.
T1 Energy, Kore Power, and Our Next Energy share something in common: They are venture capital-backed startups attempting to compete with the incumbents of the global battery industry. That model hasn’t produced a standout success yet — even Tesla initially tapped an incumbent, Panasonic, to make EV batteries at its Nevada Gigafactory.
The achievement at Holland looks rather modest compared to LG Energy Solution’s global portfolio, which Doherty said has reached around 500 gigawatt-hours of annual battery production.
“As a big company with a big balance sheet, we can have the confidence to say we’ll weather this storm,” Doherty said. “We’ll make it to the other end because we see where this is going.”
LG’s customers may have more difficulty riding out the turbulence of constantly changing tariffs and tax policy.
“This is a market that is growing, and any disruption that causes it to contract is something that will harm manufacturing,” Roberts said of the grid storage construction sector.
This analysis and news roundup comes from the Canary Media Weekly newsletter. Sign up to get it every Friday.
Record-breaking heat swept across the eastern U.S. this week — and with millions of air conditioners whirring, power demand came close to breaking records too.
The ISO New England grid region, which covers most of New England, saw its second-highest power demand ever on Tuesday. In Maine, experts with the Governor’s Energy Office told the Portland Press Herald that New England would’ve beaten the record if it wasn’t for behind-the-meter solar power, like panels on rooftops and over parking lots that aren’t controlled by grid operators. But the region still had to activate fossil fuel-fired peaker plants — which worsen climate change and air quality — to meet demand in the evening.
The grid operated by PJM Interconnection, which includes New Jersey, Ohio, Pennsylvania, Virginia, and other mid-Atlantic states, also came close to breaking demand records both Monday and Tuesday. Power outages affecting thousands of homes were reported throughout the region, with utilities blaming many of them on the high temperatures.
One growing technology could’ve helped the grid manage the heat even better: battery storage. Take New England. Instead of switching on fossil-fuel peaker plants, batteries could’ve stored excess power generated during the day and discharged it when demand peaked — something numerous studies have suggested as a solution for the region. It’s a method that the grid operators for Texas and California rely on every day, as power generated when the sun is shining is stored for use when it sets.
But not every region is embracing the technology. PJM, in particular, has failed to take advantage of batteries in spite of its demand challenges, partly because it has one of the longest waits in the country to connect to the grid.
Battery storage is also threatened by the “Big, Beautiful Bill” currently making its way through Congress. While the Senate did extend a lifeline to the energy-storage industry in its version of the bill, a Wood Mackenzie/American Clean Power Association analysis out this week found that grid-battery installations could still dip as much as 29% next year if tax credit and tariff uncertainty continues.
New York envisions a nuclear future
New York Gov. Kathy Hochul (D) launched an ambitious quest this week, directing the state’s Power Authority to build a large nuclear reactor. The reason? Rising power demand.
“If we don’t increase our capacity over the next decade, we will see rolling blackouts,” Hochul warned at a press conference. “This is the best technology to meet this demand.”
New York is already home to three nuclear power plants, and until just a few years ago, it had four. The Indian Point power plant shut down in 2021 over environmental contamination concerns. But since then, New York has had trouble making up Indian Point’s lost generation capacity, leading the state to rely on more gas power — which has in turn raised greenhouse gas emissions.
In Texas, a company led by Rick Perry, former Republican governor and Trump administration energy secretary, is proposing a nuclear project of its own. Fermi America aims to build four 1-gigawatt nuclear reactors to power a massive data-center campus.
It’ll be years before either one of these proposed plants would come online. But at the very least, it’s yet more evidence of nuclear power’s rebounding popularity on both sides of the aisle.
Senate parliamentarian rescues some energy measures from the “Big, Beautiful Bill”
Some of the Senate’s efforts to roll back Biden-era energy and environmental measures were knocked down a peg this week, courtesy of the body’s parliamentarian. The nonpartisan adviser to the Senate ruled that many “Big, Beautiful Bill” provisions can’t be passed via the 50-vote budget reconciliation process, and instead will need 60 votes to pass. Senate Republicans have only 53 seats.
The parliamentarian’s critique includes a measure that would force the U.S. Postal Service to sell all 7,200 of its newly purchased EVs and scrap its charging infrastructure — a move the USPS said would cost it $1.5 billion. The parliamentarian also ruled against provisions to speed fossil-fuel project approvals, repeal the EPA’s tailpipe-emissions rules, and sell off public lands.
In response, Senate Republicans unveiled new language on Wednesday that omits the tailpipe-emissions rollback and makes other energy-related edits.
Also this week, several groups — including car dealers, energy investors, and even Georgia Republican state legislators — wrote to the Senate urging it to protect clean energy tax credits.
EV funds restored: A federal judge orders the Trump administration to release billions of dollars of frozen funding for 14 states to build a public EV charging network, but leaves out Minnesota, Vermont, and Washington, D.C., which had also sued to get funding restored. (Associated Press)
Building more batteries: LG Energy Solution cuts the ribbon on its expanded battery plant in Michigan, where it’ll now produce utility-scale battery cells that utilize lithium iron phosphate chemistry. (Canary Media)
Coal’s deadly impact: The “old man’s disease” of black lung has been affecting younger coal miners at rates not seen since the 1970s, and advocates worry cuts to federal health and mining safety offices Trump’s attempt to revitalize the mining industry could exacerbate the problem. (New York Times)
Green lawns, greener mowers: Colorado landscapers are making the transition to electric lawn equipment after new state regulations went into effect this month to help curb noxious fumes that contribute to poor air quality. (Canary Media)
Fishing for electrification: Electric boats and solar-powered processing equipment are starting to create environmental and financial benefits for Maine’s growing shellfish industry, but uncertainties around federal funding could slow progress. (Maine Monitor)
A geothermal community: A suburb of Austin, Texas, aims to power 7,500 planned homes and commercial buildings with a sprawling geothermal energy project. (Texas Tribune/Floodlight)
Weatherization paradox: Many low-income households can’t access the free, energy-saving Weatherization Assistance Program because they can’t afford to make basic but expensive repairs required for qualification. (Grist)
Steel’s cleaner future: Steelmakers planning new facilities in the U.S. are embracing a cleaner technology for purifying iron ore, which can then be used in electric furnaces to finish the steelmaking process. (Canary Media)
Senate Republicans released a draft budget on Monday that presents a slightly less draconian prescription for clean energy tax credits than what the House had put forth.
In May, House Republicans voted to slash all the clean power credits, with some favorable treatment for nuclear plants. The Senate took a more nuanced approach, doing away with credits for cheap but intermittent resources, while continuing to incentivize projects that can generate power on demand.
The Senate version would crank down investment and production tax credits for wind and solar power starting in 2026, reducing them to zero by 2028. But the Senate Finance Committee threw a lifeline to other zero-carbon power plants, allowing hydropower, geothermal, and nuclear to keep their full credits until 2033. Crucially, energy storage was included in that group, which could help grid batteries keep their meteoric growth streak going.
This effort to continue supporting “firm” power sources, which provide energy even when the sun isn’t shining and the wind isn’t blowing, could be hugely consequential for America’s ability to meet spiking demand for electricity. Companies are racing to build new power plants to serve AI computing and domestic manufacturing (two avowed priorities of the Trump administration), not to mention the widespread electrification needed to address climate change.
The problem is, nuclear construction has stagnated since the woefully delayed and over-budget Vogtle expansion; hydropower has been essentially frozen for decades; and geothermal is just starting to gain traction thanks to a handful of startups developing new technologies.
Of the Senate’s chosen few, batteries are the only contender showing real dynamism in energy markets: In just a few years, they’ve jumped from the margins to become the second-biggest source of new power capacity added to the U.S. grid each year, after solar. Energy storage dominates the queues of projects waiting to hook up to the grid in the next few years in places like California and Texas.
The Senate still needs to debate this proposal and see if it rallies enough votes to pass. Then the Senate and House will have to reconcile their differences. There’s no way to know if the current Senate language will become the law of the land.
Nonetheless, this proposal changes the political landscape for clean energy advocates, by splitting clean energy into winners and losers. It also tacks on requirements around foreign influence that seem conceptually more workable than the House’s “poison pill” approach, but that could still thwart actual construction.
The idea of excluding wind and solar from receiving credits has been percolating over the last few months, though it was easy to miss in a generally turbulent news cycle. In April, U.S. Rep. Julie Fedorchak, a Republican from North Dakota, introduced a bill that she dubbed the “Ending Intermittent Energy Subsidies Act.”
“Wind and solar are no longer emerging technologies—they’re mature, market-proven, and widely deployed,” Fedorchak said in a statement at the time. “As all the grid operators are saying, we need more dispatchable resources. We must stop providing generous incentives that run contrary to that.”
The legislation didn’t get much attention at the time, and Fedorchak’s House colleagues yanked support from several of the dispatchable options anyway. But she had some historical facts on her side: Wind and solar have enjoyed federal tax structures since the George W. Bush era (incentives for wind actually go back further), when they emerged as a broadly supported Republican energy policy. Storage didn’t get its own tax credit until the Inflation Reduction Act kicked in for 2023. The technology is clearly the newest of the major power-sector players (excluding the nonexistent nuclear fusion and small modular reactor projects).
On June 3, a cohort of clean, dispatchable power providers chimed in on the debate with a letter noting that they can offer exactly the kind of on-demand power Republican senators seem to appreciate.
“Nuclear energy, geothermal, hydropower, and energy storage stand ready to deliver that reliable power,” said the group, which included novel storage startups Form Energy and Hydrostor, along with geothermal, nuclear, and hydro firms. “We believe it is possible to advance genuine deficit reduction without sacrificing the reliable, innovative power that American households, businesses, and national security require.”
They never said to throw wind and solar under the bus, but emphasized the particular value in keeping credits for dispatchable resources as senators decided where to cut spending.
The House, besides greatly shrinking the timeline for clean energy tax credits, tacked on new requirements that industry insiders decried as impossible to fulfill. The language would block incentives for projects that include any components from a “prohibited foreign entity,” legislative jargon which basically means companies in China. The state of globalized supply chains makes it effectively impossible to build a power plant with that constraint.
The Senate shares the concern about tax credits accruing to Chinese companies, but handled it differently. In its version, the company filing for tax credits cannot be literally or effectively controlled by prohibited foreign entities — that’s a test that U.S.-based developers should, in theory, have no trouble passing. But the text gets very specific on what kinds of arrangements could constitute “effective control” of a project, and calls for the Treasury secretary to issue guidance on how to qualify. That creates ample opportunities for U.S.-controlled storage companies that fulfill the spirit of the law to run afoul of certain sub-clauses.
Additionally, developers must spend a certain amount of the total project cost on products that are not from “foreign entities of concern.” The ratio starts at 40% in 2026, and increases annually from there. Lithium-ion batteries still largely come from China; if a project has to buy those, but can secure the remaining equipment for the power plant from the U.S., they may be able to hit the right ratio. On paper, this rule seems more achievable than the House version, which would penalize firms that use even small, low-value pieces like bolts or cables that originate from China, rather than focusing on critical, high-value components.
Of course, tax credit compliance is the province of well-paid lawyers, who would need to translate the details of the Senate language into actionable legal guidance for companies. The clean energy industry is still reeling from yearslong rulemakings at the Internal Revenue Service that held back many of the investments championed by the Biden administration. Today, the Trump administration has winnowed civil service staff and actively opposed clean energy; it’s hard to imagine IRS rulemaking moving more swiftly under those circumstances.
Storage developers are frantically running the numbers on whether their power plant designs can stay within the guidelines for foreign components, so that they’ll qualify for the tax credits. They also need their financiers to feel confident that they will. Highly prescriptive legislative interference in a high-tech business landscape complicates that process, and could cause investors to pull back until the dust clears.
That’s not to say battery construction will come to a halt without workable incentives. It’s arguably the only dispatchable technology that can be built quickly in the next few years. But saddling the credits with additional bureaucratic requirements would inject extra costs and delays into the industry, at a time when the U.S. desperately needs all the on-demand power it can get.
The Texas Legislature ended its biennial session without passing a slew of bills that could have killed the state’s booming solar and battery sector, and by extension, the ability to keep the Texas grid running amid extreme weather and surging demand for electricity.
It did pass a law that could strengthen the state’s electricity reliability by encouraging the construction of more microgrids — combinations of small-scale gas-fired power, solar, and batteries that can be built quickly. Last week, Texas lawmakers authorized a long-awaited $1.8 billion fund to support microgrid deployment at hospitals, nursing homes, water treatment plants, police and fire stations, and other critical facilities across the state.
The Texas Backup Power Package Program has awaited funding since 2023, when it was created as part of a broader legislative package. The goal is to help Texans protect themselves against extreme weather-driven grid emergencies like the disastrous blackouts during 2021’s Winter Storm Uri, or the widespread power outages after 2024’s Hurricane Beryl.
Lawmakers failed to authorize the $1.8 billion in microgrid funding in 2023, however. Instead, the state pushed ahead with $5 billion for the Texas Energy Fund, which offers low-interest loans to developers of large-scale gas-fired power plants. That program has struggled. One project that applied for funding was found to be fraudulent. Others were denied loans. And many more projects have dropped out of contention, as developers deal with the same gas turbine shortages and rising costs that are dogging gas build-outs across the country.
This year, lawmakers finally approved the microgrid funding, which is part of the remaining $5 billion in Texas Energy Fund spending officially authorized during the just-concluded session. That’s a big deal, said Doug Lewin, president of Texas-based energy consultancy Stoic Energy and author of The Texas Energy and Power Newsletter.
“Now those funds will presumably begin to flow — and I think that puts us in the upper echelon of states for microgrid policy,” he said.
Among the bills that failed this session in the face of opposition from environmental, business, and consumer groups were two — SB 388 and SB 715 — that would have forced new solar, wind, and battery projects to pay for a massive and equivalent amount of new capacity from fossil-gas power plants.
The problem with such policies is not just the fallacy that building more planet-warming gas power plants guarantees a more reliable grid, industry experts say. It’s also that companies simply can’t build gas power plants fast enough to meet booming energy needs, not just in Texas, but across the country. Because those bills would have required gas to be built alongside renewables — and because gas power plant construction is seriously constrained — the legislation would have amounted to a block on many gigawatts’ worth of new solar, wind, and battery developments in the state.
”I think one of the most important things that happened this session is this really broad-based business coalition communicating to anyone who would listen that these policies trying to restrict development of renewables aren’t helpful,” Lewin said.
Low-cost power from renewables and batteries “is a big deal to manufacturers, to industrial customers, and to the oil and gas industry that’s been working off diesel generators for decades and are now connecting to the grid,” he said.
For years now, Lewin has been calling on state leaders to focus on helping customers save energy and keep power flowing during hurricanes, heat waves, and winter storms. He thinks microgrids are a good way to do that.
When the broader grid is functioning well, facilities equipped with microgrids can use their solar, batteries, and generators to reduce their use of grid power. But when the grid goes down or experiences serious stress, those facilities can rely on those resources to continue running.
Microgrids could also help meet ballooning power demand from homes, businesses, factories, and especially data centers chasing the AI boom that make up a massive share of future load growth forecasts, he said. The Electric Reliability Council of Texas, the grid operator for most of the state, forecast in April that peak electricity demand could more than double in the next five years. The number of data centers that end up getting built in Texas will ultimately determine how much new power the state actually needs.
The microgrid program limits individual projects to no larger than 2.5 megawatts, Lewin said. That’s far smaller than the hundreds of megawatts of capacity that can come from a single gas-fired power plant. But what microgrid projects lack in size they make up for in speed of construction, and many smaller-scale backup power projects will do more to meet demand than big power plants that take five or more years to build, he said. That’s especially true if the microgrids are located at data centers themselves.
To be clear, data centers aren’t the target of the Texas Backup Power Package Program. Instead, the fund is set up to help sites that can’t otherwise afford on-site backup power, explained Joel Yu, senior vice president of policy and external affairs at Enchanted Rock. The Houston-based microgrid operator runs 500 megawatts’ worth of projects at grocery stores, truck stops, and other large power customers in Texas. Enchanted Rock has also deployed gas-fired generators at water utilities and irrigation districts, including Houston’s Northeast Water Purification Plant.
“The $1.8 billion is a huge amount of money, and more ambitious than programs we’ve seen in other jurisdictions,” Yu said. “But it’s very much in line with state policy to improve resilience at critical facilities since Winter Storm Uri,” which knocked out power to more than 4.5 million people for up to a week in February 2021, leading to the deaths of an estimated 200 people and more than $100 billion in property damages.
Enchanted Rock’s existing customers tend to be larger entities that can secure financing and clearly quantify the financial value of backup power generation, Yu said. The $1.8 billion microgrid program “unlocks opportunities for customers who aren’t as sophisticated, and don’t have the wherewithal to pay that extra cost,” he said.
Assisted living facilities are particularly good candidates for state-funded microgrids, given how deadly power outages can be to older adults or medically compromised people. Alexa Schoeman, deputy of the state’s long-term care ombudsman’s office, told the Public Utility Commission of Texas in a March statement that the more than 80,000 residents of assisted living facilities in the state are at risk from extended power outages, and that “operators have cited cost as the reason they are not able to install life-saving backup power at their locations.”
Yu declined to name any customers that Enchanted Rock is working with to take advantage of the fund. “But there’s been a lot of interest from critical facilities that might want to make use of this. We’ve talked to folks in nursing homes, assisted living industries, and low-income housing, and other critical infrastructure, trying to get into the program.”
Enchanted Rock has joined other backup generation providers including Bloom Energy, Base Power, Cummins, Generac, Mainspring Energy, and Power Secure in what Yu called an “informal group of like-minded companies.” Dubbed Grid Resilience in Texas, or GRIT for short, the coalition is working with the Electric Reliability Council of Texas and the Public Utility Commission on the $1.8 billion microgrid program, he said.
Most of these companies focus on gas-fueled power generation systems, whether those are reciprocating engines like those Enchanted Rock uses, linear generators from Mainspring, or fuel cells from Bloom Energy. Others specialize in battery backup systems, as with startup Base Power, or combine solar, batteries, and energy control systems with generators, as with Generac.
The legislation creating the Texas Backup Power Package Program allows projects to tap up to $500 of state funding per kilowatt of generation capacity installed, and requires solar, batteries, and either fossil gas or propane-fueled generation, Yu said. But it “isn’t prescriptive about what proportions are in the mix,” he added.
Different combinations could offer more favorable economics for different types of customers. Some may find that lots of solar panels are useful for lowering day-to-day utility bills, while others may want to maximize gas-fueled generation to cover multiday winter outages, when solar-charged batteries are less useful.
The legislation creating the program does limit projects from actively playing in the grid operator’s market programs, Yu added, meaning microgrid owners will face restrictions on selling the power they generate or the grid-balancing services they can provide to the market.
Still, that “does leave some room for customers to leverage the assets for behind-the-meter value,” such as using solar to offset utility power purchases, Yu said. “That’s going to be very important to making the economics work.”
A new state law will require Ohio utilities and regulators to consider how technology might offer cost-effective options for improving the state’s aging electric grid.
Ohio’s grid, like those in many states, faces rising repair and maintenance costs, growing demand from data centers and other new customers, and increased risks as climate change fuels more frequent severe weather and outages. House Bill 15, signed last month by Republican Gov. Mike DeWine, calls for a focus on software and hardware solutions to boost the safety, reliability, efficiency, and capacity of existing infrastructure.
Clean energy advocates are hopeful the investments will also allow the grid to accommodate more renewable energy and battery storage projects, which can suffer costs and delays related to transmission bottlenecks.
“This is a really, really great inclusion in the bill,” said Chris Tavenor, an attorney at the Ohio Environmental Council, an advocacy group.
Advanced transmission technologies that utilities must contemplate under HB 15 include things like sensors that allow lines to safely carry more electricity when conditions are favorable, a concept known as dynamic line rating. Digital controllers can remotely adjust the amount of power flowing through different parts of the grid, while topology optimization software can reroute power around congested areas, like a navigation app for electricity.
A key benefit of these technologies is that they can be used with existing infrastructure. When wires do need to be replaced, advanced conductors provide an energy-saving option. Those conductors use carbon composites or other materials to carry more electricity with less loss of that energy, compared to traditional wires of similar diameter.
A high-tech approach can create space on the grid for more renewable energy to come online. That would lessen the need to run expensive, polluting coal-fired power plants, said Rob Kelter, a senior attorney with the Environmental Law & Policy Center, a legal advocacy organization based in the Midwest.
Besides helping to mitigate climate change, less pollution would help people’s health as well, Tavenor said.
Under HB 15, owners of high-voltage power lines must file annual reports showing which advanced transmission technologies they considered as part of their five-year forecasts. Those companies will also need to identify areas of the grid with congestion, and compare the cost of addressing it with traditional versus advanced technologies.
The reports will be available to the public, and interested parties may ask the Public Utilities Commission of Ohio to hold a hearing on whether utilities properly reported transmission information and whether they should be able to recover costs from customers.
The Ohio Power Siting Board must also require companies to consider technology solutions before it approves any new transmission projects. Companies would have to file reports and expert testimony to support any decision to forego advanced technologies in favor of conventional projects, Kelter said.
Advocacy groups and other stakeholders “would have a chance to similarly argue that those technologies are available and that they’re cost-effective, and that they would be able to alleviate congestion and delay the need for new transmission lines,” Kelter added.
The law requires the Public Utilities Commission of Ohio to study the costs and benefits of the various technologies, including how to streamline their deployment. That report will be due by March 1 next year.
Some Ohio utilities have already been exploring the potential for advanced transmission technologies. In 2023, AES installed 42 dynamic-line-rating sensors at towers along five transmission lines owned by its Ohio and Indiana utilities. The companies shared early results last year showing that installing the sensors was cheaper and faster than replacing power lines, and using the sensors increased the system’s electricity-carrying capacity.
American Transmission Systems, a subsidiary of FirstEnergy, is planning to spend nearly $900 million on dozens of transmission projects across Ohio in the coming years. “We are currently reviewing House Bill 15 and exploring how its provisions around advanced transmission technologies could be integrated into our planning to strengthen the power grid for Ohio customers,” said FirstEnergy spokesperson Lauren Siburkis.
Many of the law’s potential benefits hinge on how the Ohio Power Siting Board and Public Utilities Commission of Ohio implement its terms when making decisions on siting and electric rates, Tavenor noted.
The law’s advanced technology provisions only apply to high-voltage parts of the grid that move electricity over long distances. It doesn’t require utilities to consider high-tech approaches to improving the local distribution lines that deliver electricity to homes and businesses.
So, for example, AEP Ohio won’t need to consider advanced transmission technologies in its latest rate case filed on May 30, spokesperson Laura Arenschield said. That’s because AEP wants to use the 2.14% increase in base rates to pay for improvements to its local distribution system, not the AEP transmission network.
Similarly, the new law won’t address grid inequities affecting disadvantaged communities in FirstEnergy’s Ohio territory, which the Interstate Renewable Energy Council described in a report released earlier this year.
Even so, investments that use existing system capacity more effectively can still promote equity by reducing the need to build all-new transmission lines. Siting such infrastructure “can be incredibly invasive and inequitable, harming both communities and ecosystems,” said report author Shay Banton, who is a regulatory program engineer and energy justice policy advocate at the Interstate Renewable Energy Council.
Building less brand-new transmission can also save consumers money. Ohioans have generally paid for transmission maintenance and upgrades through a “rider” on their bills. For the average AEP Ohio consumer, that extra charge is roughly $40 per month. HB 15, however, aims to get rid of single-issue riders, so in the future, utilities will instead have to consider transmission costs through rate cases that consider all utility costs and expenses and are heavily scrutinized by regulators. That could also lead to lower costs or at least smaller increases.
“Ohio utility consumers already are burdened by billions in utility transmission projects,” said Maureen Willis, who represents the interests of Ohio’s utility customers in her role as the state’s consumers’ counsel. “By adopting advanced transmission technology, these costs can be reduced, staving off unnecessary ‘gold-plating’ by utilities, giving consumers more bang for the buck. We strongly advocate for this approach to transmission spending.”
A pesky question has long stalled efforts to expand U.S. power grids in the face of growing demand and surging renewable energy: Who should pay for the upgrades?
An under-the-radar breakthrough in Massachusetts may finally provide a template for answering that question.
Over the past year or so, the state’s largest utilities and regulators have approved plans for dividing grid costs between customers and the companies that build solar arrays.
It’s been a long time coming. The plans in question have gone through numerous iterations since utilities, regulators, and solar developers started working on them about six years ago, making progress hard to track. And the name they settled on — “Capital Investment Projects,” or CIPs — isn’t exactly an attention grabber.
But behind the staid name lies a significant advance for a state striving to fairly allocate the costs of shifting to clean energy, said Kate Tohme, director of interconnection policy at Massachusetts-based community solar developer New Leaf Energy. In fact, advocates working on similar efforts in states from New York to California are “all trying to use the Massachusetts framework as a model,” she said.
The roughly $334 million in CIP grid projects from utilities Eversource and National Grid that have been approved or are being considered by regulators are doing something rare in the world of regulated utilities. Instead of forcing distributed solar and battery projects to pay up-front for grid improvements that allow them to connect to the utility system, the CIPs spread those costs onto customers’ future utility bills. Under the old system, clean energy projects regularly died on the vine because up-front grid costs were prohibitively high.
That doesn’t mean developers are getting a free ride, however. They’ll still have to pay a portion of those costs back as they’re connected to the grid, reducing the burden on customers over time. And every project in question had to prove to regulators that the grid improvements at large also deliver customer benefits, whether through improved grid reliability, enabling access to cheaper community solar power, or both.
Massachusetts can’t avoid these kinds of grid investments if it’s to meet its clean energy and electrification goals, according to Tohme, a former official at the state Department of Public Utilities who was directly involved in some of the earliest CIP work. The state has committed to cutting emissions 50% below 1990 levels by 2030, which will require building lots of renewable energy and electrifying vehicles and home heating.
“In the short term, it’s going to increase our costs,” Tohme said. But “once the grid is modernized and we get distributed energy interconnected, it’s going to drastically decrease our electricity costs” by replacing expensive fossil-fueled power with cheaper renewable energy and batteries.
The landmark plan emerged as a response to what might be seen as a clean-energy success story — Massachusetts had too much community solar trying to get onto an overly crowded grid.
The launch of the Solar Massachusetts Renewable Target program in 2018 had created lucrative incentives for community solar developers, spurring a rush of applications to connect to utility distribution grids. As available capacity was used up, the cost of upgrading those grids to accommodate more solar power started to rise.
“For a while, the cost to interconnect was tens of thousands of dollars, something a project could absorb,” said Mike Porcaro, director of innovative grid solutions at National Grid, one of the state’s largest utilities. “But eventually the modifications grew so large — hundreds of thousands or millions of dollars — that it was hard for projects to move forward.”
National Grid was encountering the same kind of interconnection backlog and upgrade cost challenges that have tied up utility-scale solar and wind projects on high-voltage transmission grids across the country. The main difference is that community solar projects connect to lower-voltage grids that carry power from big substations to end customers. Similar backlogs have dogged other states with lots of community solar, including Minnesota and New York.
One of the best-established ways to relieve interconnection stresses is for utilities and grid operators to stop painstakingly studying each project one at a time and batch them instead. Such “group” or “cluster” studies of multiple projects seeking interconnection in a particular region allow utilities to conduct a speedier and more holistic assessment of the impacts they’ll cause and upgrades that will solve them.
It also allows grid-upgrade costs to be shared among the projects in the cluster, rather than foisting them on whichever project engineers determined would push that part of the grid over its existing capacity limit, thus triggering an upgrade, Porcaro said.
But the approach has its limits. “You’re still sharing the costs among that group,” he said — and forcing projects to pay even a portion of those costs up front can still make them too expensive to move forward.
To deal with that disconnect, the Department of Public Utilities launched its “provisional system planning program,” the precursor to the CIPs, in 2021. The idea, Porcaro said, was to allow utilities to move faster on solving the fundamental problem for all of those community solar projects — a grid that wasn’t being built out quickly enough to match the exploding demand for capacity.
National Grid and other utilities already plan ahead to accommodate growing electricity demand from customers or to serve big new developments like housing subdivisions or factories, Porcaro noted. The goal of the provisional system planning approach was to find a way to similarly pay in advance for proactive grid investments to bring community solar projects online.
“The review and discovery to get these CIPs approved was no small feat,” Porcaro said. “It wasn’t a quick decision.”
In late 2022, the Department of Public Utilities approved its first test case for CIPs — a cluster of projects put forward by utility Eversource, known as the “Marion-Fairhaven Study Group” after two of the Southeastern Massachusetts towns in the area being considered for upgrades.
Eversource estimated at the time that it would cost about $116 million in distribution grid upgrades to enable roughly 140 megawatts of community solar to connect to the grid. To avoid the chicken-and-egg problem of requiring projects to pay up front for the upgrades — something they couldn’t afford to do — Eversource proposed charging them about $370 per kilowatt of solar they connected once the grid work was done.
The risk of this approach is that some of the projects involved in the group study would end up dropping out, leaving customers on the hook for their unpaid share, Lavelle Freeman, Eversource’s vice president of distribution system planning, told Canary Media in a 2023 interview. That put the burden on Eversource to plan a grid upgrade that didn’t just make room for the solar projects but benefited customers as well.
Fortunately, the same kinds of upgrades that expand capacity for community solar also improve customer reliability and provide headroom for growing electrical loads.
“We’re also improving the substations, adding new capacity, adding new transformers and feeders, making the system more robust,” Freeman said. “We developed a very rigorous algorithm to calculate the reliability benefits,” which ended up showing a roughly 50-50 split in the benefits between customers and solar developers. “That went a long way toward convincing regulators that the cost-allocation principle would work.”
To be clear, there are significant risks to committing utility customers’ money to building out grid infrastructure to serve the needs of community solar projects. In Massachusetts, the state Attorney General’s Office is tasked with protecting utility customers’ interests in regulatory proceedings like these.
A senior official at the Attorney General’s Office who was involved with the CIP process told Canary Media that the office “took serious issue” with how Eversource first proposed splitting grid-upgrade costs. “Not only were ratepayers paying more than they should have, it created a lot of risk for ratepayers,” said the person, who was granted anonymity to discuss matters outside the official regulatory process.
On the other hand, the official said, “being able to have more homegrown generation is going to be important for Massachusetts. It is a cost risk. But how do we minimize those cost risks to ratepayers, and maximize those benefits to ratepayers, as we bring this solar online?”
These concerns from the Attorney General’s Office pushed the finalized version of CIP to shift more of the cost of new grid investments onto community solar projects as opposed to utility customers. That’s not ideal from the perspective of solar developers, obviously, but it’s far better than being stuck with the unaffordable upgrade costs they faced before.
Having a known per-kilowatt cost locked in well in advance is also helpful, said Mike Judge, currently undersecretary of energy for the Massachusetts Executive Office of Energy and Environmental Affairs, who spoke to Canary Media in 2023 when he was vice president of policy for the trade group Coalition for Community Solar Access.
Developers often need to secure interconnection rights before they can secure the financing and start signing up subscribers that allow them to move forward with projects, he said.
“There’s so much value for a developer to know I’m going to pay $370 a kilowatt to connect,” Judge said. “You’re not waiting a year, year and a half for a utility to come back with study results to say, it’s $5 million — and you have to cancel your project.”
The model that Eversource established for the Marion-Fairhaven project is largely mirrored in the 10 other CIPs that it and National Grid have submitted to regulators. All told, Eversource has identified six groups with more than 250 MW of community solar or battery storage capacity. Porcaro said that National Grid has five CIPs that will enable about 300 MW of new projects — “that’s huge.”
Massachusetts isn’t the only state working on policies that aim to spur grid expansion while keeping customers’ power costs in check, Tohme said. Similar efforts are now underway in states including California, Colorado, Maryland, Minnesota, and New York.
But to Tohme’s knowledge, no other state has accomplished what Massachusetts has with its CIP structure. New York is closest, she said, with a cost-sharing framework that allows community solar developers to split up the costs of necessary upgrades rather than bearing them alone. But that still doesn’t include the same “build in advance, pay later” structure that the CIPs have, she said.
At the same time, Tohme pointed out, the CIPs remain a response to a problem that’s been hounding the state for years now: projects stuck behind an inadequately upgraded grid. The next logical step is to figure out where grid upgrades should be made before that kind of situation happens again.
That’s one of the goals laid out for the state’s three major investor-owned utilities under a sprawling grid-modernization mandate created as part of a major energy and climate law passed in 2022. It’s called the Electric Sector Modernization Plans process, and the Department of Public Utilities is now reviewing the proposals submitted by utilities last year to determine next steps, Porcaro said.
CIPs are a part of that broader plan, he said. But the modernization plans are “going above that and saying, ‘plan for everything’ — for everyone having an EV, and electrifying their homes, and specific goals for how much energy storage we need. It’s a tall order.”
Given how long it took to figure out CIPs, clean energy developers have reason to worry that this even more sweeping and complicated planning task could take even longer. Clean-energy industry group Advanced Energy United has urged state regulators to keep doing CIPs while it undertakes this broader new effort.
Porcaro highlighted other work that can help get more clean energy connected even before the grid gets built out. He pointed to National Grid’s Active Resource Integration pilot, launching this year, which is looking at ways community solar and battery projects can connect to grids that can safely absorb their power output during all but a handful of hours of the year. If those solar farms can curtail their output during those hours, they could connect years ahead of utility grid upgrades.
These kinds of “flexible interconnection” structures, as they’re generally known, could help “get us through now to when the full system could be built, or to get through certain areas where you don’t need a full buildout,” Porcaro said.
Meanwhile, the clock is ticking on building out a grid that can support Massachusetts’ clean energy and electrification ambitions. Later this year, the Department of Public Utilities is expected to issue its ground rules on how utilities should start to calculate the fair sharing of costs between their customers and the community solar and battery projects trying to connect to their grids under the Electric Sector Modernization Plans, Tohme said.
Once that’s done, utilities and other stakeholder groups will bring cost-sharing proposals to the regulator and start to hash them out, she said. ”So we have a long way to go before we have proactive proposals.”
But just because it’s going to be hard doesn’t mean it isn’t worth doing, she said. “We have to modernize our grid. Right now we’re doing it anyway — we’re just reacting. We’re just doing it non-strategically. And that’s just as expensive,” Tohme said — if not more so.
See more from Canary Media’s “Chart of the week” column.
California is throwing away a lot of solar power.
The state curtailed 3,400 gigawatt-hours of utility-scale renewable electricity last year, 93% of which was produced by solar panels, per a U.S. Energy Information Administration analysis of data from California’s grid operator.
When the sun shines bright and the breeze blows hard, solar panels and wind turbines often produce more power than the grid needs or can handle. In those moments, the grid operator will order power plant owners to reduce their output. That’s called curtailment, and it’s common in places like California that have lots of renewables.
It’s no surprise that California is having to curtail power as it adds more solar to the grid — but curtailments are rising faster in the state than renewable generation capacity is growing. Last year, curtailments jumped by 29% compared with 2023, while California added only about 12% more utility-scale solar capacity.
Curtailments are at their highest in California during the spring, when the sun is strong enough to generate a lot of solar power but mild weather keeps air-conditioning use, and thus electricity demand, in check.
With power demand rising around the country thanks in large part to the rapid rollout of AI data centers, and with California behind on climate goals, it’s important for the state to try and reduce curtailments and use more of the clean power it’s already capable of generating.
There are a few ways to do that. California can continue to push buildings, vehicles, and industrial operations to electrify, creating more demand to soak up what is now surplus solar. It can support the construction of interstate transmission lines that would allow it to export more power to states with less solar generation.
The state can also build lots and lots of batteries to store extra solar produced during the day for use in the evening. In fact, it’s already doing that. It has installed more utility-scale storage than any other state, and the sector has grown rapidly in recent years: California had a total of 13.2 GW of utility-scale storage online as of last month, far more than the nearly 8 GW it had at the end of 2023.
In order to stop wasting clean electricity, California will need to sustain that battery boom in the face of significant federal policy headwinds — and place some bets on other, more elusive solutions like transmission and long-duration energy storage.
One of the biggest grid batteries in California almost resumed operations Sunday following the cataclysmic Moss Landing fire in January.
The San Francisco Bay Area’s power grid used to draw on two battery storage plants in the quiet seaside town of Moss Landing. Texas-based power company Vistra built the nation’s largest standalone grid battery on the grounds of an old gas power plant there, and utility Pacific Gas and Electric Co. built and owns the Elkhorn project next door.
A roaring fire engulfed Vistra’s historic turbine hall in January, wrecking rows of lithium-ion batteries that delivered 300 megawatts of instantaneous grid power. That site is still in shambles. PG&E’s battery plant suffered far less disruption: Hot ash blew over the fenceline from Vistra’s property, posing an environmental hazard and potentially clogging batteries’ thermal management systems. But after several months of remediation, cleaning, and testing, PG&E attempted to flip the switch Sunday to reconnect Elkhorn to the grid. But the utility ran into a problem.
“On June 1 we began methodically returning the batteries to service as a part of the planned return to service, and in the process a clamp failure and coolant leak was identified in one of the 256 megapacks onsite,” the company said in a statement Monday evening. “We are working to remediate the issue and out of an abundance of caution we are deferring the facility’s return to service until a later date.”
PG&E has not released any more details on how long it will take to restore the facility. It noted that the testing and discovery of the malfunctioning unit led to no injuries, smoke, or fire.
Had the operation succeeded, it would have returned 182.5 megawatts/730 megawatt-hours of storage capacity to the power-hungry Silicon Valley grid corridor right before the region’s first major heat wave of the summer.
“The concern was lower in the winter months, with demand lower,” said Dave Gabbard, vice president of power generation at PG&E, in an interview Thursday. “It will be critical to have assets like Elkhorn available as we get into the peak summer months.”
Indeed, California has been building grid batteries at a record pace, to store the state’s nation-leading solar generation and deliver it during crucial hours, like after sunset. The tech is displacing some gas-fired power generation in the state. California’s battery fleet passed 15.7 gigawatts installed per a May tally, which Gov. Gavin Newsom’s office touted as “an unprecedented milestone.” The governor, a Democrat, did not specify why the 15.7-GW threshold merits particular attention, but it does mean California has added more than 5 GW since it crossed the 10-GW mark a year prior.
“The pace of construction for large-scale energy storage in California is phenomenal, the kind of accomplishment that was beyond our wildest dreams a few years ago,” said Scott Murtishaw, executive director of the California Energy Storage Alliance.
The state’s battery buildout is plowing ahead. But Vistra’s fiery failure sparked deep community concerns about battery safety in California and beyond, as Moss Landing residents were forced to evacuate for several days and plumes of smoke loomed over surrounding estuaries and farmlands. In April, Vistra rescinded an application to build a 600-MW battery in Morro Bay, two hours down the coast from Moss Landing, following significant local resistance that intensified after the January fire.
Even before the unsuccessful restart, the plan to revive Elkhorn had rekindled concerns among community leaders who are still grappling with the fallout from the largest-ever battery fire in the U.S., and quite possibly the world. The Monterey County Board of Supervisors had asked to keep both battery plants offline until the Vistra investigation was completed and acted upon.
“Restarting operations before investigations are complete and before stronger emergency protocols are in place is disappointing and deeply troubling,” Monterey County Supervisor Glenn Church posted on Facebook after learning of PG&E’s plans in early May.
Crucially, PG&E’s battery layout, completed in 2022, mitigates the hazards that took out the neighboring Vistra plant, which was completed two years earlier.
Officials have not yet pinpointed the cause of Vistra’s fire, but it became so destructive because it spread through the densely packed rows of batteries in the old turbine hall, igniting more and more fuel as it grew. By contrast, PG&E’s Elkhorn plant spans 256 individual Tesla Megapack containers spaced over the property.
“We have a completely different design,” Gabbard said. “We have compartmentalized our design so that fire propagation won’t occur to adjacent units.”
That industry-wide preference for separate, containerized systems doesn’t eliminate the chance of battery fires, but it does limit the potential severity. One container might burn, but the fire can’t reach all the other batteries. A fire could knock a facility offline temporarily, but it would only eliminate a small percentage of its capacity, Murtishaw said. That stands in contrast to Moss Landing’s failure, or the all-or-nothing issues that can occur when a gas-burning turbine malfunctions.
“The technology and standards have changed considerably since the first big batteries,” like Vistra’s, Murtishaw said. “Facilities coming online now are being constructed with newer technologies meeting newer standards. Risk of runaway incidents has decreased dramatically relative to the amount of storage being deployed.”
That compartmentalization strategy worked out when Elkhorn suffered its own battery fire in 2022 — the result of water seeping into a unit through an improperly installed roof, Gabbard said. The single unit burned in a contained fashion and did not spread to any other batteries. PG&E restarted the facility three months later, after implementing recommendations from an independent investigation into the cause.
Since that incident, PG&E installed air quality monitoring onsite and upgraded the battery enclosures to automatically discharge stored energy if abnormal behavior is detected, Gabbard said. PG&E additionally updated its emergency action plan and instituted annual exercises with the North County Fire Protection District.
When Vistra’s plant burned up in January, Elkhorn’s thermal imaging cameras spotted it and automatically severed the connection to the grid, halting the flow of high-voltage power out of the site. PG&E also made the air quality data available to emergency response teams.
The utility then kept Elkhorn offline for the subsequent months to allow for environmental remediation of the soot to keep it out of local waterways, Gabbard said. Workers also cleaned the Megapacks “outside and inside,” he noted. The main concern was that the ash could have intruded into the systems that cool batteries during operations. Staff pressure-washed all those components and tested their functionality to get the site ready for operations.
Another 10 gigawatts of storage are already under contract for California’s regulated utilities and community choice aggregators over the next four years, Murtishaw said. That would put the state over 25 gigawatts, well on its way to the current goal of 52 gigawatts by 2045, stemming from the state’s clean energy law SB 100.
To achieve that goal, the Moss Landing calamity needs to remain an outlier event. There’s good reason to believe that will be the case. For one thing, the industry has all but abandoned Vistra’s strategy of packing huge amounts of batteries into a single building.
California now has 214 grid-scale batteries, and only about 10 of them reside in a building, Murtishaw noted. Those are subject to inspection by the California Public Utilities Commission under a recently expanded authority, he added; in the meantime, owners have stepped up safety measures in response to the Moss Landing news.
Small-scale batteries in homes and businesses also count for California’s top-line storage goal. They depend on the same core battery technologies as the large-scale storage projects, but as mass-produced consumer items, they go through a different gauntlet of tests before they reach customers.
“The home batteries are tested inside and out, up and down — they undergo rigorous safety testing and certification to standards,” said Brad Heavner, executive director of the California Solar and Storage Association, which advocates for rooftop solar and battery installers.
In the state Legislature, Sen. John Laird, a Democrat from the Moss Landing area, introduced a bill in March to systematize coordination between battery owners and local emergency responders, and to fix a timing mismatch so California’s fire codes match the latest standards set by the National Fire Protection Association. Murtishaw said the California Energy Storage Alliance supports the measure, which passed out of the Senate last week.
A correction was made on June 3, 2025: This story initially stated that PG&E restarted its Elkhorn battery facility on June 1. The story has been updated to reflect that the company initiated the restart process on June 1 but halted the process due to equipment issues. The story also originally said the utility installed heat-sensing cameras at Elkhorn after the January Moss Landing fire; those cameras had actually been part of the facility since it was built.
Federal regulators have rejected a controversial plan to fast-track new gas-fired power plants onto the grid that spans 15 states from Louisiana to North Dakota, handing a victory to critics who feared it could derail the region’s clean energy buildout and worsen the reliability problems it was meant to address.
Friday’s 2-1 decision from the Federal Energy Regulatory Commission found that the Expedited Resource Addition Study (ERAS) plan put forward by the Midcontinent Independent System Operator failed to meet the standards for a “just and reasonable” way to solve MISO’s forecast grid shortfall of 4.7 gigawatts by 2028.
Like grid operators across the country, MISO suffers from a clogged interconnection process, preventing it from building enough new power-generation capacity to replace closing coal plants, meet fast-growing demand for electricity, and keep the grid up and running during winter cold snaps and summer heat waves.
MISO filed the ERAS proposal as an emergency measure meant to alleviate this problem — but only for fossil-gas power plants. The plan allowed utilities to receive interconnection agreements for “shovel-ready” gas power plants in less than 90 days. For the most part, the only projects eligible for this treatment would have been those built by vertically integrated utilities, a further point of criticism from energy experts who viewed the plan as circumventing the region’s competitive energy market.
Meanwhile, yearslong wait times would still be in store for the hundreds of gigawatts’ worth of projects in MISO’s existing queue, the majority of which are solar, wind, and battery installations.
But FERC’s decision found some key deficiencies in the ERAS plan. First, it “places no limit on the number of projects that could be entered in the ERAS process,” the commission’s opinion states, which “could result in an ERAS queue with processing times for interconnection requests that are too lengthy to meet MISO’s stated resource adequacy and reliability needs.” That could also cause the ERAS queue to become just as backed up as MISO’s existing queue for competitively proposed generation and energy storage projects.
These factors differentiated MISO’s ERAS plan from other fast-track interconnection proposals recently approved by FERC, such as one from grid operator PJM Interconnection that set a one-time window for up to 50 projects to apply for fast-track consideration, the decision notes. That process “reasonably balanced the need to address PJM’s resource adequacy challenges with the need to avoid an influx of projects that could overwhelm PJM’s interconnection process and lead to further delays.”
FERC’s decision dismissed MISO’s proposal “without prejudice,” meaning the grid operator may resubmit a revised emergency fast-track plan in the future. MISO spokesperson Brandon Morris said the grid operator “worked closely and collaboratively with stakeholders to develop ERAS as a temporary process that will enable urgent generation projects to be built more quickly. We will continue to engage with stakeholders as we evaluate options.”
Many utilities and state utility regulators in MISO’s territory backed ERAS, but a handful of state regulators, consumer advocacy groups, clean energy industry groups, and eight former FERC commissioners opposed it.
FERC commissioners David Rosner, a Democrat, and Lindsay See, a Republican, voted for Friday’s decision. Republican Chair Mark Christie voted against the rejection, and Commissioner Judy Chang, a Democrat, did not participate.
Christie noted in a separate dissent that he did not disagree with the majority’s critique but that he had been willing “to extend to both the states and MISO a trust that they would implement the ERAS proposal in a manner that would promote the construction of badly needed generation capacity that serves resource adequacy and reliability.”
Clean energy groups praised the decision.
“FERC’s role as an independent agency is to protect consumers, and ensure reliable affordable energy,” Christine Powell, deputy managing attorney for Earthjustice’s clean energy program, wrote in a statement. “The best way to do that is to let clean energy compete fairly and openly.”
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.
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