The search for long-duration energy storage

The stationary energy storage business that Mateo Jaramillo started while working for Tesla was gaining momentum. At the end of 2016, the company had installed one of the world’s largest lithium-ion battery systems for a utility in California. But Jaramillo felt that weaning the electrical grid off fossil fuels would require a cheaper form of energy storage.

Although lithium-ion batteries excel at delivering short bursts of electricity, they were too expensive for long- duration storage. As solar and wind farms proliferated, he predicted, utilities would need batteries cheap enough to supply electricity for multiple days during cloudy spells or wind lulls.

Jaramillo left Tesla and in 2017 started searching for technologies that could solve this problem. He was working with a scientist at Stanford University on a multiday battery when he learned about a group from the Massachusetts Institute of Technology pursuing a similar goal. Jaramillo flew to Boston to meet with them. The two teams decided to merge and start a company called Form Energy.

At their Somerville, Massachusetts, laboratory, Form scientists started testing all kinds of technologies. Near the end of 2018, they settled on an iron-air battery, which releases energy by reacting iron with oxygen in a process similar to rusting. The firm says its battery can supply electricity for at least 100 h.

“That’s the duration of weather events that really cause problems for the grid,” Jaramillo says. “Getting through one tight day is manageable. Getting through three or four in a row, that’s when things start to break.”

Since Form’s launch in 2017, private investors and government agencies have poured more than $1 billion into the firm’s iron-air battery. In September, Form received a $150 million grant from the US Department of Energy (DOE) to fund its battery-manufacturing plant in West Virginia, which is slated to reach a production capacity of 500 MW by 2028. And the company has announced 141.5 MW of battery projects. Competing long-duration storage technologies, such as flow batteries and other metal-air batteries, have also attracted billions in investment and government support.

As Form has progressed, the number of utility-scale lithium-ion battery projects has skyrocketed. But the market for long-duration energy storage is only just starting to materialize, and many utilities are hesitant to jump from lithium-ion systems that last a few hours to multiday batteries like Form’s. Compared with fossil fuels, long-duration batteries are still relatively expensive, prompting many utilities to meet sustained surges of electricity demand by firing up gas-powered standby turbines rather than drawing from batteries.

To respond to the impacts of climate change, US utilities are charting a path toward decarbonization, but many of those targets are decades away. Meanwhile, the Donald J. Trump administration is pushing for policies that embrace fossil fuels rather than renewable energy. In this environment, some Form competitors say it could take years before utilities are ready for multiday batteries. They’re planning to take gradual steps by selling shorter-duration batteries in the near term.

Jaramillo and other proponents of multiday batteries say the tipping point for these technologies will come soon, just as it did for solar power and lithium-ion batteries. They argue that multiday batteries offer the cheapest way to build a fossil fuel–free electricity system. Most importantly, Jaramillo says, the batteries will ensure that a grid powered by renewable energy can always provide electricity when people need it.

“Having cost-effective multiday duration storage enables . . . a much more reliable grid while driving deep decarbonization,” he says. “You have a more reliable, overall lower-cost grid.”

Lithium’s rise

Lithium-ion batteries became the default technology for storing renewable energy partly because companies were already mass-producing them for electric vehicles. Still, they have proven to be capable workhorses.

Connecting batteries to the electrical grid allows utilities to shift energy generated by the midday sun to the high-demand hours of the evening, when TVs, dishwashers, and microwaves turn on in droves. They also balance electricity supply with demand, a critical function that maintains the power grid at the correct frequency to protect against blackouts or infrastructure damage.

Paired with renewable energy, these batteries can generate healthy profits by charging when electricity prices are low and discharging when they are high. And in many cases, the ability of lithium-ion batteries to respond nearly instantaneously makes them better for fine-tuning the grid’s frequency than gas-fired power plants, which take longer to fire up.

As a result, utility-scale battery installations in the US jumped from about 0.7 GW of power capacity in 2017 to more than 16 GW by the end of 2023, according to data from the US Energy Information Administration. Nearly all of these projects use lithium-ion batteries.

Today, most lithium-ion battery systems provide power for only a few hours at a time, but the technology continues to get cheaper and better, says John-Joseph Marie, an energy storage analyst at the Faraday Institution who recently authored a report on stationary batteries. Production and engineering improvements are allowing some companies to plan lithium-ion storage projects that could, in the coming years, discharge up to 8 h of energy, about 4 times as long as an average battery in 2023. “That’s made it really difficult for anything else to really compete,” Marie says. “It’s a constantly moving goalpost.”

Combining lithium-ion batteries with the generation of huge amounts of renewable electricity plus lots of new transmission lines to move that energy could go a long way toward decarbonizing the power grid, but building that infrastructure would be incredibly expensive.

A 2023 DOE report estimated that the US would need 225–460 GW of long-duration energy storage—defined in the report as 10–160 h of battery duration—to build a fully decarbonized electricity grid by 2060. Starting from essentially zero, that would require $330 billion in new investment, which is $10 billion–$20 billion cheaper than not using long-duration storage. The Long Duration Energy Storage Council, a group that advocates on behalf of companies developing these technologies, estimates that the amount of long-duration energy storage could reach 1.5–2.5 TW by 2040.

“We cannot rely on lithium ion for all energy storage applications,” Marie says. “You will need more long-duration energy storage. I think that’s where you could see some of these other battery chemistries really playing a key role.”

The iron age

One wall in Form’s laboratory in Massachusetts hosts a dozen battery cells in rectangular plastic panels, each about the size of a residential windowpane. Each cell has a water-based electrolyte, a negatively charged anode made of iron powder, and a positively charged air cathode that pumps oxygen into the electrolyte.

Form envisions that 30 of these cells will be combined into modules about the size of a side-by-side washing machine and dryer. Those modules would be packed into shipping container–sized enclosures. A full-sized battery could include dozens of shipping containers spread out over a few hectares. The giant batteries are designed for utilities trying to stabilize their electricity supply, not homeowners, hospitals, or even big industrial sites trying to save on energy costs.

To charge the battery, electricity converts iron hydroxide at the anode into metallic iron, releasing hydroxide ions. The hydroxide ions migrate to the air cathode on the other side of the battery where they form water and oxygen. The oxygen bubbles out of the battery. During discharge, the process is reversed. Pumping oxygen into the water-based electrolyte generates hydroxide ions. At the anode, the hydroxide ions react with iron to form iron hydroxide, and electrons flow out of the battery.

The simple, inexpensive components of this system are what make the technology so attractive. But it also comes with trade-offs.

For iron-air batteries, the catch is efficiency. Scientists at NASA first developed the batteries in the 1960s, and during the oil crisis of the 1970s, firms including Matsushita Electric Industrial, Siemens, and Westinghouse Electric considered commercializing the technology for electric cars. But they never moved far beyond the laboratory, because the batteries discharged a fraction of the electricity that went in.

During charging, some of the electricity going into the battery splits water from the electrolyte into hydrogen. And during discharge, even more energy is lost when oxygen is reduced into hydroxide ions.

Form’s battery returns about 40% of the energy used to charge it, an improvement over early iron-air efforts. Lithium-ion batteries often reach 90% efficiency or higher. But Jaramillo argues that it’s worth sacrificing efficiency for a system that costs 10% of a lithium-ion battery. “How much efficiency do you want to pay for if the problem you’re solving is one of multiday duration capacity?” he asks.

The company expects that customers will use iron-air batteries to sop up ultracheap electricity that would normally go to waste. About 3% of renewable energy is wasted when solar and wind farms stop delivering electricity to the grid either because transmission lines are congested or because there’s ample supply. Renewable energy waste can even reach 9% in places with lots of wind and solar, such as California. “If you have renewable fuel . . . then your fuel is very low cost, and you should care less about the efficiency,” Jaramillo says.

But some experts are skeptical that existing electricity markets offer viable ways to justify the cost of multiday batteries—or that they’re needed at all to decarbonize the electrical grid.

“One hundred hours is really out there,” says Shawn Wasim, an energy industry analyst who recently left the research firm E Source. “There’s going to have to be completely new programs created for that. . . . There’s no market set up for it right now.”

Companies often cycle lithium-ion batteries every day or even multiple times per day to maximize the amount of electricity they can sell. The main purpose of a 100 h battery is to ensure grid reliability by serving as a backup source of energy, which might mean they’re fully discharged only a few times a year, when weather strains the electricity grid.

Many battery operators receive payments for simply being connected to the grid, but those payments top out after a few hours, so they don’t provide much incentive for long-duration storage. Wasim argues that it will be hard to justify building long-duration batteries that cycle so infrequently without better mechanisms to compensate battery operators for reliability.

Varnika Agarwal, an energy storage analyst with the research firm Rho Motion, agrees that 100 h might be overkill. She says these batteries could find a niche, but it will likely be smaller than that for short-duration batteries. “The technologies that are going to have the major market share are going to range from 4 to 10 h duration space,” she says. “That’s where your lithium-ion and flow batteries fit in.”

Form says short-duration batteries complement its technology. But unlike lithium-ion batteries, Jaramillo says, the value of Form’s batteries isn’t from the amount of electricity they crank out. He says utilities are interested in them because they make it possible to build fewer power plants and transmission lines without sacrificing reliability. Form’s target customers are integrated utilities that run power plants, string transmission lines, and distribute to customers. Jaramillo says a 100 h battery is often the cheapest way for such firms to ensure they can fulfill their obligations, even if the battery is used only occasionally.

“They are the ones that have the ultimate responsibility that the grid is reliable and stable,” he says. “They put their own internal price on reliability.”

The promise of flow

Before Form set out to commercialize iron-air batteries, other companies hoped to smooth the intermittency of renewable energy with flow batteries.

Flow batteries store electricity in two tanks of electrolyte solution. To dispatch electricity, the two electrolytes are pumped into a membrane-separated chamber. Electrons flow through a circuit out of the negative electrolyte into the positive electrolyte, and ions from the more positively charged solution move across the membrane to balance the charge. Reversing the process charges the battery.

Flow batteries have been around for decades, and there are dozens of chemistries. Increasing the amount of energy storage is as simple as switching to bigger electrolyte tanks, so they can be configured to discharge for short or long durations. Many companies developing flow batteries are targeting durations between those typical of lithium-ion and metal-air batteries, or between 10 and 24 h.

The most-mature flow batteries are made with vanadium-based electrolytes, but vanadium is expensive. A 2024 report from the research firm BloombergNEF found that flow batteries are more expensive than lithium-ion batteries. So companies are looking for cheaper options.

Eugene Beh, founder of the flow-battery start-up Quino Energy, is betting that an electrolyte composed of organic quinones will make the batteries more economical. Quino’s raw material is a cheap orange-brown dye made from coal tar or petroleum aromatics. “It goes into an electrolyzer . . . we give it a little tickle, and it gets converted into the final product,” Beh says. “That has allowed us to move down the cost curve very rapidly.”

Historically, the problem with organic flow batteries was that constantly donating and accepting electrons caused unwanted side reactions that degraded the electrolyte. Beh says Quino’s electrolyte degrades more slowly than do other organic materials. The company can also regenerate degraded electrolyte using a special discharge cycle.

Moreover, Beh says, the organic electrolyte doesn’t catalyze the formation of hydrogen. As in iron-air batteries, hydrogen formation in flow batteries lowers efficiency and depletes the electrolyte’s ability to store electricity in future cycles. “Organics are just really bad at making hydrogen,” Beh says.

Michael Marshak, founder of the flow-battery start-up Otoro Energy, studied organic flow batteries in the same Harvard University chemistry laboratory where Quino’s electrolyte was born. But he says the technology’s low voltage limits its utility. At Otoro, he’s reviving a flow battery chemistry that uses iron- and chromium-based electrolytes.

Like the founders of Form, Marshak likes the price of iron. But previous iron-chromium flow batteries were also plagued by low voltage and low power. Otoro’s innovation is to bind an organic chelate to chromium. Marshak says the result is a void for the chromium ions to expand into when they accept electrons. That increases the speed of electron transfer, boosting voltage and power.

The chelate can also block water from binding to chromium ions, allowing the battery to operate at higher voltages without forming hydrogen. “I did my PhD in some water-splitting and hydrogen stuff,” Marshak says. “I applied basically the opposite. How do we prevent molecules from making hydrogen?”

ESS Tech, which is developing an iron-based flow battery, is tackling the problem of hydrogen formation in a different way. Hugh McDermott, who oversees sales at ESS, says the company’s system includes a step that reincorporates the hydrogen into the electrolyte after it flows through the power module.

Most flow batteries can achieve efficiencies of 50–80%, less than those of lithium-ion batteries but more than those of metal-air batteries. Taking issue with Form’s view of the market, Marshak says efficiency will be a key characteristic for long-duration batteries. He argues that, like lower-efficiency metal-air batteries, higher-efficiency flow batteries can increase resiliency by bridging long periods of low generation of renewable energy, but they can also economically go through short daily cycles to help customers shave energy costs.

Flow batteries have their own challenges, though. Many flow battery companies are targeting less than a day of energy storage, a duration that lithium-ion batteries could also cover. Marie, the Faraday Institution analyst, says it will be hard for flow batteries to catch up to lithium-ion batteries because the systems are inherently complex, and they don’t benefit from advances in other industries.

“Those performance advantages for the lithium-ion batteries have come from the automotive industry,” he says. “Flow just hasn’t had that similar breakthrough.”

Marshak says Otoro plans to build batteries that discharge for about 10 h, but the system could be configured for longer durations. Like the analysts questioning Form’s approach, Marshak doesn’t see a good way for customers to get paid for long-duration energy storage, so he thinks it’s wise to take smaller steps until utility customers are more prepared to use multiday batteries. “There’s a lot of utilities that I’ve talked to who don’t know who would use a 100 h battery,” he says.

All in the timing

While adding long-duration batteries to the grid brings major benefits, companies developing them acknowledge that getting the timing right is tricky.

Several firms have already stumbled. The start-up Ambri raised $215 million to develop a liquid-metal battery capable of delivering up to 24 h of energy but went bankrupt last year. The zinc-air battery developer NantEnergy laid off half its workforce in 2019, according to local media. The vanadium flow battery companies Imergy Power Systems and UniEnergy Technologies have also gone out of business.

These companies faltered in part because they launched their technologies before utilities were ready to adopt them, according to Charlie Parker, who leads the battery industry advisory firm Ratel Consulting. Parker knows this firsthand because he previously led business development at VionX Energy, a vanadium flow battery company that fell on hard times and was sold to the vanadium miner Largo. “It was great technology but ahead of the market that it was intended for,” he says.

Jaramillo says Form’s agreements with customers show that the energy industry is ready to adopt multiday storage. The company is taking a big swing—an approach that could yield big rewards and big cuts to electricity’s carbon footprint—by focusing on superlong-duration batteries for customers that need lots of energy. An 8 h flow battery at a hospital might replace a backup diesel generator. Form’s batteries would function more like a backup power plant.

But James Larsen, CEO of the multiday zinc-air battery start-up e-Zinc, says he believes that the market for long-duration batteries will develop more slowly. He expects that his company’s technology will first be deployed as a medium-duration backup power source for individual customers or for remote, off-grid applications like mines. He anticipates that large-scale adoption of multiday batteries by utilities is at least 5 years away.

“We know that this is a tidal wave coming, but our strategy is to . . . establish ourselves in the market, build up our credibility and experience, such that we’re positioned for this ultimate grid-scale market,” Larsen says.

In the US, the election of Trump only adds to this uncertainty. Some of the second Trump administration’s early moves have been hostile to renewable energy projects. Form, Otoro, ESS, and other long-duration storage companies have received funding from the DOE or the National Science Foundation. But given the layoffs and attempts to freeze grants at US agencies, government backed-projects are at risk.

Some long-duration battery projects are beginning to move forward, mostly at a small scale. The US EIA lists 13 flow and metal-air battery projects planned in the US over the next 2 years. Marshak says Otoro is building a pilot plant for one of the largest utilities in the US. ESS has already installed a 2 MW flow battery for a utility in Sacramento, California, and has received state-level funding to add an additional 3.6 MW battery.

In August, Great River Energy, a utility in Minnesota, broke ground on the first pilot-scale demonstration of Form’s technology. Zac Ruzycki, director of resource planning at Great River, says the project will help him plan for the company’s future, but he says it could take a long time to fully prove the technology’s value. “Ten years from now, if we can have a 100 MW long-duration resource that can dispatch for 100 h, that’s a really valuable resource,” Ruzycki says.

Given the threat of climate change, McDermott, with the iron flow battery firm ESS, says now is not the time for utilities to hesitate. He says utilities need to start piloting technologies so they’ll be ready to commit to bigger, more ambitious projects in the coming years.

“The urgency of getting started now should trump anybody waiting for perfection,” he says. “You’re already behind the eight ball.”