Battery storage is being funded and built faster than most people can track, and Brooks Sherman spends a lot of his research time asking which of these technologies are ready for the grid and which are still working through key questions. He walks through what he’s seeing in sodium-ion, iron-air, and flow chemistries, and why the gap between a promising lab result and a bankable project is where most of the real risk sits.
Grid-scale battery storage is no longer a niche category. According to the U.S. Energy Information Administration, developers and utilities added a record 15 gigawatts of utility-scale battery storage to the U.S. grid in 2025 and planned to add even more in 2026, with battery storage now accounting for more than a quarter of all new generating capacity coming online.
As storage investment accelerates, companies are promoting a growing range of battery chemistries, each with different claims about cost, performance, duration, and scalability. Sorting through those claims has become a challenge for investors, utilities, and other decision-makers.
Brooks Sherman holds an MBA in Sustainable Innovation from the University of Vermont’s Grossman School of Business, where his capstone research examined next-generation battery-storage markets and the fit of different technologies in grid-scale and distributed applications.
Sherman has not deployed these systems himself; his perspective is based on research and case-study analysis. “In my research, what stood out wasn’t any single chemistry winning,” he says. “It was how differently these technologies can fail if the financing or the timeline doesn’t match what they need.”
The Storage Boom Doesn’t Move at One Speed
Part of what makes this moment difficult to evaluate is that “battery storage” now covers a wide range of technologies at different stages of commercial maturity, often discussed under the same broad label. Lithium-ion still dominates deployment, but sodium-ion, iron-air, and flow batteries are emerging as potential complements, each with different proposed advantages: lower material costs, longer-duration performance, reduced reliance on particular minerals, or a potentially stronger fit for multi-day storage needs.
“We are still working through what ‘ready’ means across these chemistries, because it is not one bar,” Sherman says. “A battery that’s ready for a four-hour application isn’t necessarily close to ready for a hundred-hour application, even if the underlying pitch sounds similar.”
That distinction matters because the U.S. Department of Energy has set an explicit cost target for the long-duration category specifically: a 90% reduction from the 2020 lithium-ion cost baseline, aiming for roughly five cents per kilowatt-hour by 2030. A technology that clears that bar solves a different problem than one that’s simply cheaper lithium-ion, and Sherman observes the two get conflated in coverage more often than they should.
What Natron’s Shutdown Says About Timing
Sodium-ion is a useful case study in why funding timelines and technology timelines don’t always move together. Natron Energy had been positioned as an important early commercial player in the sector, including plans for a $1.4 billion sodium-ion factory in North Carolina that would have supported roughly 1,000 jobs. In September 2025, the company ceased operations. Reporting on the shutdown noted that funding pressure outpaced the company’s ability to scale production, even though the underlying chemistry had real commercial interest behind it.
“In the case studies I looked at, a technology can be technically sound and still not survive its own funding runway,” Sherman says. “That’s not a knock on sodium-ion as a chemistry. It’s a reminder that the capital and the manufacturing have to move together, or the story can end before the technology gets a fair test.”
Sherman is careful to note that one company’s shutdown isn’t a verdict on the whole category. Sodium-ion projects and manufacturers elsewhere are continuing to scale, and there is still broad interest in the chemistry, particularly as a lower-cost, lower-mineral-dependency alternative to lithium-ion. What’s changed is how closely investors and utilities are now looking at a company’s manufacturing readiness before treating its cost claims as settled.
Iron-Air and the Case for Longer Duration
If sodium-ion illustrates the risks created when a financing timeline outruns commercial scale, iron-air technology provides a different case: a battery chemistry designed for a distinctly longer-duration role. Form Energy’s iron-air system is designed to discharge for up to 100 hours, targeting multi-day gaps in renewable generation rather than the daily cycling applications served by lithium-ion systems. After years of pilot work, the company began delivering its first commercial batteries in the fall of 2025 to a Minnesota utility project.
Drawing on his storage-market research, Sherman points to iron-air as an example of a technology matching its rollout to its actual manufacturing capacity. “It’s not moving forward simply because someone announced a factory,” he says. “It’s moving because the production line and project pipeline are keeping pace with the announcements.”
Flow batteries belong in the same broader long-duration conversation, but their tradeoffs differ. They can offer long cycle life and flexible energy-duration sizing, although project economics, materials, manufacturing scale, system complexity, and commercial track record vary widely by chemistry and vendor. Treating flow batteries as interchangeable with either sodium-ion or iron-air obscures the different applications each technology may be trying to serve.
“If a system can provide reliable power across a multi-day stretch with limited wind or sun, you’re not comparing it only to a four-hour battery anymore,” he says. “You’re comparing it to what utilities already use gas plants or transmission upgrades for.”
Why the Grid Can Be the Bottleneck
Even a battery that clears every cost and performance target still has to connect to the grid, and that step has become its own source of delay. According to Lawrence Berkeley National Laboratory’s interconnection queue tracking, only 13% of the capacity that entered U.S. interconnection queues between 2000 and 2020 had reached commercial operation by the end of 2025, while roughly three-quarters of that capacity was withdrawn along the way.
“We are working through how much of the storage story is really about the technology versus the queue it’s sitting in,” Sherman says. “A battery can hit every target on paper and still spend years waiting for a grid study. That’s a policy and process problem more than a chemistry problem, and it’s easy to attribute the delay to the wrong part of the system.”
He sees this as part of what makes “emerging” technologies difficult to evaluate before the market settles: cost curves and demonstration projects attract attention, while interconnection timelines, permitting, and financing structures quietly decide which projects ultimately get built. A cheaper battery doesn’t help much if it is stuck behind a multi-year grid study alongside gas, solar, and everything else in line.
Separating Signal From Noise
Sherman’s approach is not about predicting a winning chemistry. It is closer to a diligence checklist: has the company demonstrated manufacturing at meaningful scale, not just a pilot; does its funding timeline reasonably match its production and project-development timeline; and is the use case it’s targeting one where its specific strengths, duration, cost, or material availability matter most.
In his research, the technologies that appeared most durable weren’t necessarily the most efficient ones on paper. “They were the ones where the company’s claims about cost and timeline lined up with what was happening on the manufacturing floor. That gap is where most of the disappointment in this space comes from,” Sherman says.
He also points to the shifting economics of storage as a reason this sorting matters more now than it did a few years ago. “At this point, the cost conversation has moved past whether storage pencils out in general,” Sherman says. “In a lot of markets, it already does. The harder question is which specific technology fits which specific gap, and that’s where the marketing can move ahead of the manufacturing.”
A Field Still Being Sorted Out
None of this requires declaring winners in advance. Sodium-ion’s challenges do not erase its potential cost and supply-chain advantages. Iron-air’s early deployments do not guarantee successful scaling. Flow batteries may be compelling in selected long-duration applications, but their prospects depend on the individual technology, vendor, and market context.
Sherman’s interest, by his own framing, is in the pattern rather than the prediction. What he keeps coming back to is that the companies worth watching are those whose public claims about performance, cost, manufacturing, and project timing correspond closely to what they can demonstrate in production and deployment.
“Treating a battery-storage claim as credible simply because it sounds credible is an easy way to misjudge it,” he says. “The technologies are moving quickly, and that is not unusual in energy. But the diligence has to keep up with the pace of the announcements, not just the pace of the deployments.”
For now, that diligence means reading the manufacturing data, tracking project milestones and interconnection conditions, and comparing what a company says against what it is actually building. Before the market settles, the most useful question is not which emerging battery will win. It is whether its commercial pathway is as credible as its technical promise.
Published Originally on — https://www.technology.org/2026/09/10/brooks-sherman-on-evaluating-emerging-battery-technologies-before-the-market-settles/
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