Case study: Long-duration energy storage (LDES) — a leading company's implementation and lessons learned

As renewable energy penetration crosses the 40% threshold in major electricity markets, the grid faces a structural problem that lithium-ion batteries alone cannot solve: what happens when the sun does not shine and the wind does not blow for 12, 48, or even 168 consecutive hours? Long-duration energy storage (LDES), defined as systems capable of discharging for 10 hours or more, has emerged as the critical missing piece in the decarbonization puzzle. Form Energy's deployment of iron-air battery systems in partnership with Great River Energy in Minnesota offers one of the most instructive real-world case studies of how LDES technology moves from laboratory promise to grid-scale reality, revealing both the transformative potential and the hard operational lessons that shape this nascent industry.

Why It Matters

The US Department of Energy estimates that achieving an 80% clean electricity grid by 2035 will require between 225 and 460 GW of LDES capacity, representing a market opportunity exceeding $330 billion. As of early 2026, total deployed LDES capacity in the United States stands at approximately 1.2 GW, indicating an enormous gap between current capabilities and grid requirements. Pumped hydro storage accounts for roughly 93% of existing long-duration capacity, but geographic and permitting constraints limit new development. This reality has catalyzed investment in alternative LDES technologies including iron-air batteries, flow batteries, compressed air energy storage, and thermal storage systems.

The urgency extends beyond grid reliability. CAISO data from 2025 shows that California curtailed approximately 3.2 TWh of solar generation due to oversupply during midday hours, while simultaneously ramping up natural gas peakers during evening peaks. This pattern, replicated in ERCOT, SPP, and MISO territories, demonstrates that without cost-effective long-duration storage, renewable curtailment will accelerate and fossil fuel backup will persist. Every GW of LDES deployed directly displaces gas peaker capacity and captures otherwise wasted clean energy.

For utilities, independent power producers, and corporate energy buyers, understanding how leading LDES deployments actually perform in the field is essential for making capital allocation decisions that will shape grid infrastructure for decades.

Background and Decision Process

Form Energy was founded in 2017 by a team including MIT professors Yet-Ming Chiang and Mateo Jaramillo, a former Tesla executive who led the development of the Powerwall and Powerpack programs. The company focused on iron-air battery chemistry, a technology concept dating to the 1970s that uses the reversible oxidation of iron (rusting and de-rusting) to store and release electrical energy. The fundamental appeal of the chemistry lies in its raw materials: iron is the fourth most abundant element in Earth's crust, and the electrolyte is a water-based solution, eliminating the supply chain risks associated with lithium, cobalt, and nickel.

Great River Energy (GRE), a wholesale power cooperative serving 28 member cooperatives across Minnesota, began evaluating LDES technologies in 2020 as part of its transition plan to reduce carbon emissions 80% below 2005 levels by 2030. GRE's generation portfolio included 2.5 GW of capacity, with coal accounting for roughly 40% and wind providing 30%. The cooperative faced a specific challenge: Minnesota's wind generation peaks during spring and fall shoulder seasons, but reliability events driven by extreme cold winter weather require firm capacity precisely when wind generation is least predictable. Traditional lithium-ion batteries, with typical durations of 2 to 4 hours, could not bridge multiday weather events.

GRE's evaluation process spanned 18 months and assessed seven LDES technologies across five criteria: levelized cost of storage (LCOS), round-trip efficiency, scalability, supply chain risk, and technology readiness. Iron-air chemistry offered the lowest projected LCOS at $20 to $30 per kWh for 100 hours of duration, compared to $150 to $250 per kWh for lithium-ion at equivalent durations. The tradeoff was lower round-trip efficiency (approximately 45% for iron-air versus 85 to 90% for lithium-ion), which GRE's analysis showed was acceptable given the low marginal cost of curtailed wind energy that would otherwise be wasted.

In November 2021, GRE and Form Energy announced plans for a 1.5 MW / 150 MWh iron-air battery pilot at GRE's Cambridge, Minnesota site, with commissioning targeted for late 2023. The project would test the technology under real grid conditions, including Minnesota's temperature extremes ranging from negative 30 degrees Fahrenheit in winter to over 100 degrees Fahrenheit in summer.

Implementation and Execution

The deployment unfolded in three phases, each revealing challenges that laboratory testing could not fully anticipate.

Phase 1: Site Preparation and Manufacturing Scale-Up (2022)

Form Energy broke ground on its first commercial-scale manufacturing facility in Weirton, West Virginia, in a former Weirton Steel mill. The choice of location was strategic: it provided access to existing industrial infrastructure, a skilled manufacturing workforce from the steel industry, and eligibility for Inflation Reduction Act (IRA) Section 45X advanced manufacturing production credits worth approximately $35 per kWh of battery capacity produced domestically. However, converting a steel mill to a battery factory required $760 million in capital expenditure and 14 months of construction, pushing timelines beyond initial projections.

Simultaneously, site preparation at Cambridge involved designing thermal management systems capable of maintaining iron-air cells within their operating temperature range of 0 to 45 degrees Celsius, a nontrivial engineering challenge given Minnesota's climate. The team developed an insulated enclosure system with auxiliary heating and cooling that added approximately 15% to the system's installed cost but proved essential for performance.

Phase 2: Installation and Commissioning (2023 to 2024)

The 1.5 MW system comprised approximately 50 modular battery units, each containing thousands of individual iron-air cells arranged in series and parallel configurations. Installation proceeded from March through September 2023, with commissioning beginning in October. Three significant challenges emerged during this phase.

First, the iron-air cells exhibited higher self-discharge rates than laboratory testing had predicted, losing approximately 1.5% of stored energy per day compared to the expected 0.5%. This reduced effective storage duration from the theoretical 100 hours to approximately 65 to 70 hours before self-discharge losses became economically significant. Form Energy attributed the discrepancy to temperature variations within the enclosures and implemented firmware updates and improved thermal uniformity that reduced self-discharge to approximately 0.8% per day by mid-2024.

Second, the water management subsystem, responsible for maintaining electrolyte concentration and humidity levels within the cells, required more frequent intervention than anticipated. Maintenance cycles that were designed for monthly intervals needed to occur every two weeks during the first year, adding to operational costs and requiring additional trained personnel on site.

Third, grid interconnection delays pushed full commercial operation from late 2023 to March 2024. MISO's interconnection queue, already processing over 2,500 projects representing 450 GW of capacity, created bottlenecks in impact studies and upgrade requirements that added five months to the project timeline.

Phase 3: Grid Operations and Performance Validation (2024 to Present)

Since achieving commercial operation, the Form Energy system has completed over 180 full charge-discharge cycles through early 2026. Key performance metrics include:

Metric	Target	Achieved (Year 1)	Achieved (Year 2)
Discharge Duration	100 hours	65-70 hours	75-80 hours
Round-Trip Efficiency	45%	38%	42%
Availability	95%	87%	93%
Self-Discharge Rate	0.5%/day	1.5%/day	0.8%/day
LCOS (per cycle)	$25/MWh	$38/MWh	$29/MWh

The system demonstrated its value during two critical grid events. In January 2025, a polar vortex event pushed MISO emergency operating procedures to Level 2 for 72 consecutive hours. The Form Energy system discharged continuously for 58 hours, providing firm capacity that displaced approximately 87 MWh of natural gas generation. In July 2025, a multiday heat wave coincided with low wind conditions, and the system provided 44 hours of continuous discharge during peak demand periods.

Measured Results and Economic Impact

GRE's internal analysis calculated the system's first-year value at approximately $1.2 million, comprising capacity payments under MISO's seasonal resource adequacy construct ($340,000), energy arbitrage revenues ($280,000), avoided curtailment value ($180,000), and avoided gas peaker dispatch costs ($400,000). Against an all-in installed cost of approximately $12 million (including site preparation and interconnection), this implies a simple payback period of roughly 10 years, which GRE considers acceptable given the 25-year expected system life and the trajectory of improving performance metrics.

The IRA's Section 48 Investment Tax Credit provided a 30% credit on eligible installed costs, with an additional 10% bonus for meeting domestic content requirements. After tax credits, GRE's effective cost basis dropped to approximately $7.2 million, improving the payback period to roughly 6 years.

Form Energy has used operational data from the GRE deployment to refine its second-generation cell design, which targets 45% round-trip efficiency and 0.3% daily self-discharge. The company announced in late 2025 that it had secured 10 GWh of advanced orders from utilities including Xcel Energy, Southern Company, and Dominion Energy, with systems expected to ship from the Weirton facility beginning in 2027.

Lessons Learned

1. Laboratory performance does not equal field performance, and the gap matters. The difference between lab-tested self-discharge rates and actual field performance cost GRE approximately 30 hours of effective duration in the first year. Any organization deploying novel LDES technology should budget for a 20 to 30% performance gap in Year 1 and structure contracts with technology providers to include performance guarantees with financial penalties and improvement milestones.

2. Thermal management is a system-level challenge, not a component-level one. Iron-air batteries are more temperature-sensitive than lithium-ion systems, and the cost and complexity of thermal management in extreme climates should not be underestimated. GRE's 15% cost adder for thermal enclosures proved justified, and deployments in temperate climates may achieve significantly better economics.

3. Interconnection timelines dominate project schedules. MISO's interconnection queue added five months to the project timeline, a delay that would have been longer without GRE's existing grid infrastructure at the Cambridge site. Developers pursuing greenfield LDES projects should anticipate 3 to 5 year interconnection timelines in congested ISOs and consider co-locating with existing generation assets to leverage established points of interconnection.

4. Round-trip efficiency matters less than expected when the input energy is cheap or free. GRE's analysis showed that iron-air's 42% round-trip efficiency is economically competitive with lithium-ion's 88% efficiency when the input energy comes from curtailed wind at near-zero marginal cost. The economic calculus shifts when LDES charges from grid power at wholesale prices, making the application profile (surplus renewable capture versus grid arbitrage) a critical design consideration.

5. Workforce development requires lead time. Operating iron-air batteries requires skills that overlap with but differ from both conventional power plant operations and lithium-ion battery maintenance. GRE invested 6 months and approximately $200,000 in training programs for 12 operations staff, covering electrochemistry fundamentals, water management systems, and safety protocols specific to iron-air technology.

Key Players

Form Energy leads iron-air battery commercialization with its Weirton manufacturing facility targeting 4 GWh annual capacity by 2028. Backed by over $1 billion in funding from investors including Breakthrough Energy Ventures, ArcelorMittal, and the US Department of Energy.

ESS Inc. commercializes iron flow battery technology with 4 to 12 hour duration systems, with deployments across the US, Europe, and Australia. Their Energy Warehouse product targets commercial and industrial applications.

Invinity Energy Systems produces vanadium redox flow batteries for 4 to 8 hour applications, with over 80 MWh deployed globally and a growing presence in California and the UK markets.

Hydrostor develops advanced compressed air energy storage (A-CAES) systems targeting 8 to 24 hour durations, with projects under development in California and Australia totaling over 4 GW.

Malta Inc. (a subsidiary of Alphabet) develops electro-thermal energy storage systems using molten salt and chilled antifreeze, targeting 10 or more hours of duration at grid scale.

Action Checklist

• Assess your grid territory's specific LDES need by analyzing renewable curtailment data, capacity shortfalls during extreme weather, and forward capacity market pricing
• Evaluate LDES technology options against your climate profile, recognizing that thermal management requirements vary significantly between iron-air, flow, and compressed air systems
• Model LDES economics using curtailed renewable energy as the charging source rather than wholesale grid power to capture the true value proposition
• Budget for a 20 to 30% performance gap between vendor specifications and first-year field performance, with contractual improvement milestones
• Initiate interconnection applications 3 to 5 years ahead of target commercial operation dates, and prioritize sites with existing grid infrastructure
• Develop workforce training programs covering technology-specific operations, maintenance, and safety protocols at least 6 months before commissioning
• Structure offtake or capacity agreements to capture stacked value streams including capacity payments, energy arbitrage, curtailment avoidance, and ancillary services
• Monitor IRA Section 48 and 45X credit eligibility requirements to maximize federal incentive capture

FAQ

Q: What is the realistic cost per kWh for long-duration energy storage in 2026? A: Installed costs vary significantly by technology and duration. Iron-air batteries target $20 to $30 per kWh for 100-hour systems at scale, though first-of-kind projects like GRE's came in at approximately $80 per kWh on an all-in basis before tax credits. Vanadium flow batteries range from $250 to $400 per kWh for 4 to 8 hour systems. Compressed air energy storage targets $50 to $100 per kWh for 8 to 24 hour configurations. These costs are expected to decline 30 to 50% by 2030 as manufacturing scales and operational learning accumulates.

Q: How does round-trip efficiency affect the economics of LDES? A: Round-trip efficiency (the percentage of input energy recovered on discharge) ranges from 40 to 50% for iron-air to 70 to 80% for flow batteries and 60 to 70% for compressed air. Lower efficiency is economically acceptable when the charging energy source has near-zero marginal cost, such as curtailed wind or solar. When charging from grid power at wholesale rates, efficiency losses directly impact operating costs and can make low-efficiency technologies uncompetitive for energy arbitrage applications.

Q: What duration of storage is needed to achieve a fully renewable grid? A: Princeton University's Net-Zero America study found that a 95% clean electricity grid requires storage durations spanning from 4 hours (daily cycling) to 100 or more hours (multiday and seasonal bridging). The optimal portfolio includes approximately 200 GW of 4 to 8 hour lithium-ion storage and 100 to 200 GW of 10 to 100+ hour LDES. The exact mix depends on geography, renewable resource profiles, and the extent of transmission buildout.

Q: Are there safety concerns specific to LDES technologies? A: Each LDES technology presents distinct safety profiles. Iron-air batteries pose minimal fire or explosion risk since the electrolyte is water-based and the cathode material is iron. Flow batteries use acidic or basic electrolytes requiring chemical handling protocols but also pose low fire risk. Compressed air systems involve high-pressure vessels requiring compliance with ASME standards. None of the leading LDES technologies present the thermal runaway risks associated with lithium-ion batteries, which is a meaningful safety advantage for grid-scale deployments.

Sources

• US Department of Energy. (2025). Long-Duration Energy Storage: Pathways to Commercial Liftoff. Washington, DC: DOE Liftoff Reports.
• Form Energy. (2025). Iron-Air Battery Technology: Performance Data from Great River Energy Deployment. Somerville, MA: Form Energy Technical Reports.
• National Renewable Energy Laboratory. (2025). Storage Futures Study: The Role of Long-Duration Energy Storage in Decarbonized Grids. Golden, CO: NREL.
• BloombergNEF. (2026). Long-Duration Energy Storage Market Outlook, Q1 2026. New York: Bloomberg LP.
• Midcontinent Independent System Operator. (2025). MISO Interconnection Queue Analysis and Capacity Planning Report. Carmel, IN: MISO.
• Princeton University. (2024). Net-Zero America: Potential Pathways, Infrastructure, and Impacts, Final Report Update. Princeton, NJ: Princeton University Press.
• California Independent System Operator. (2025). Annual Curtailment Report: Renewable Generation Oversupply Analysis. Folsom, CA: CAISO.