Reliability and long-duration capacity with non-battery energy storage
Takeaways from episode 3: Reliability and long-duration capacity with non-battery energy storage
A recap of the third CLEAResult Energetics webinar from our flexible grid technologies series, featuring David Voss (Energy Consultant), Chase de Leon (Process Heating Engineer), and Ookie Ma (Senior SME), moderated by Kiran Srivastava.
Quick summary: Batteries alone can't carry long-duration energy storage
Batteries have become the face of energy storage, but they were never built to do everything. Batteries are best suited for short-duration storage, typically a few hours of demand smoothing, not for carrying a facility through a full day, a multi-day weather event, or a full season. Thermal storage and hydrogen storage fill that gap, offering longer discharge durations, lower material costs, and, in the case of hydrogen, storage that lasts for months with minimal loss. These technologies were the focus of "Built to Last: Reliability and Long Duration Capacity with Non-Battery Energy Storage," the third session in CLEAResult's flexible grid technologies webinar series. Read the recap below — you don't need to have watched the webinar to follow along.
Meet the panel: three perspectives on non-battery energy storage
Kiran Srivastava, a director at CLEAResult Energetics, the company's sustainability consulting practice, moderated the discussion, joined by three experts who each brought a different angle on non-battery storage: Chase De Leon, an industrial process heating engineer who supports the U.S. Department of Energy's Industrial Technologies Office; David Voss, an energy transition consultant with 32 years of experience in hydrogen, alternative fuels, and turbomachinery, including two decades at Solar Turbines; and Ookie Ma, a senior subject matter expert with more than 16 years in energy research, including a decade at the Department of Energy, who now leads techno-economic analysis with Oak Ridge National Laboratory.
The policy and incentive landscape driving long-duration storage in 2026
Srivastava opened by pointing to policy momentum building around long-duration storage. California regulators have authorized the procurement of up to one gigawatt of long-duration storage, with projects required to deliver at least 12 hours of capacity to strengthen reliability and help the grid absorb more solar and wind. South Dakota regulators approved a new pricing program supporting a five-gigawatt-hour, multi-day thermal storage system that delivers clean heat to a biorefinery. At the federal level, the clean hydrogen production tax credit offers up to $3 per kilogram for eligible projects that begin construction before 2028. The message, Srivastava said, is simple: Batteries aren't the only answer, and hydrogen and thermal storage can do things batteries can't.
How thermal energy storage works
De Leon opened with a primer on how thermal storage works and why it's gaining traction. Systems store energy as sensible heat (raising the temperature of a medium such as firebrick, graphite, concrete, or molten salt), latent heat (using a phase change, which can pack two to three times more energy into the same footprint), or through reversible thermochemical reactions, a still-emerging approach that could eventually allow storage at room temperature.
The appeal is largely economic and physical. Thermal storage systems built from inexpensive materials like sand, rock, or brick degrade far less over time than batteries and are commonly rated for 30 or more years of service. De Leon cited research suggesting California would need roughly 30 gigawatts of storage capacity just to reach 50% renewable penetration on its grid. Lithium-ion batteries, priced around $334 per kilowatt-hour in 2024, aren't expected to fall below $100 to $150 per kilowatt-hour even in optimistic 2050 projections. Thermal storage is already running $20 to $50 per kilowatt-hour, with some providers claiming costs under $10.
That cost advantage matters as demand grows. De Leon pointed to ICF projections of a 21% jump in electricity demand and a 14% rise in peak demand by 2030, alongside electricity bills that are already up more than 30% since 2019. As a real-world example, he described a system Rondo Energy commissioned this year with Holmes Western Oil in Taft, California, where a 20-megawatt, off-grid solar array charges a Rondo heat battery with 100 megawatt-hours of storage to deliver steam around the clock.
Hydrogen storage and turbomachinery storage: supporting seasonal and long-duration power
Voss picked up where De Leon left off, noting that “long duration” means different things to different people, ranging from eight to 12 hours to a full season. For commercial and industrial customers, he focused on two approaches: hydrogen and turbomachinery-based storage.
A typical zero-emission hydrogen system uses an electrolyzer to convert water and electricity into hydrogen, stores it, then runs it back through a fuel cell to regenerate electricity and water. Because gaseous hydrogen can be stored for months with minimal loss, it's well-suited to seasonal storage, and its modularity (systems can be built in roughly 100-megawatt blocks) allows for distributed deployment. The tradeoffs are real: round-trip efficiency runs 40% to 50%, compared with 85% to 92% for batteries, and capital costs remain high. Large projects, such as the ACES project in Utah, require underground caverns rather than tanks once storage volumes reach hundreds of megawatts.
Turbomachinery-based storage, which pairs turbines and compressors with low-cost media like rock or water, offers some grid benefits batteries can't, including the fast-response advantages of spinning generation. Voss noted growing interest from data center developers who need power quickly and can't wait years for new gas turbine capacity or grid interconnection. Both technologies share hurdles familiar to any emerging market: limited operating history, no standardized testing protocols, and few incentives that compensate for long-duration performance.
Case study: modeling electric thermal storage at an industrial refinery
Ma closed the technical presentations with a detailed case study modeling thermal storage at a condensate refinery with both steam and power needs. His team compared a standard fuel-fired boiler against an electric thermal storage system charged when power prices dipped below natural gas prices, which happened about 25% of the year.
The sizing math matters. To capture the cheapest hours, the system would need to charge roughly four times faster than it discharges; breaking even required a 1.7-to-1 ratio. For this refinery, about 80 hours of storage and a 3-to-1 charge-to-discharge ratio proved most favorable, though the results are highly dependent on local market conditions. Operationally, adding storage pushed the refinery's peak load from nine megawatts to 72 megawatts and cut its load factor from nearly 100% to about 40%, since the system fills low-price valleys rather than shaving peak demand the way batteries typically do.
The economics illustrate why this remains an emerging space. Equipment alone penciled out to a six-year payback, with about $1.5 million in annual energy savings against $9 million in incremental costs. Once interconnection costs for the added load (potentially $6 million to $12 million) and installation and engineering costs are included, payback stretches toward 20 years. Ma noted that as more zero-marginal-cost resources like wind, solar, and nuclear enter the grid and decouple power prices from gas prices, the economics could shift meaningfully in thermal storage's favor.
Common questions about deploying hydrogen and thermal energy storage
The Q&A ran long as attendees pressed the panel for real-world specifics. Questions included:
• How do conventional utility demand charges affect the economics of charging thermal storage, and are better tariff models available?
• Where is hydrogen energy storage being deployed today in the U.S. or elsewhere?
• Are there publicly available databases that track long-duration energy storage projects and technologies?
• Which companies can help design and implement thermal or hydrogen storage systems?
• Is borehole thermal energy storage gaining traction for building heating and cooling, and how close is it to broad adoption?
• Where in the country, and in which sectors, is non-battery storage being deployed most successfully today?
• Beyond cost, what should a facility weigh when choosing between hydrogen storage and thermal storage?
• What surprised the panel most about integrating thermal storage into a real industrial facility?
Answers ranged from a tariff model that Antora Energy and Otter Tail Power built in South Dakota to align demand charges with the grid benefit thermal storage provides, to a simple rule of thumb from Voss: keep energy in its native form, since thermal loads favor thermal storage and electricity-only loads favor hydrogen.
Want the panel's complete, unedited answers? Watch the on-demand recording, or schedule a call with a CLEAResult Energetics expert to talk through which non-battery storage option fits your facility.
CLEAResult Energetics will continue the flexible grid technologies series next month with a session on battery energy storage. Attendees can watch for registration details and follow CLEAResult Energetics on LinkedIn for updates.