Case study: Grid-scale energy storage economics & procurement — a startup-to-enterprise scale story

When Form Energy announced in 2021 that its iron-air battery technology could deliver 100 hours of storage at one-tenth the cost of lithium-ion systems, the claim was met with equal parts excitement and skepticism. By early 2026, the company had secured over $800 million in total funding, broken ground on a 760,000-square-foot manufacturing facility in Weirton, West Virginia, and signed its first commercial deployment agreement with Great River Energy in Minnesota for a 1.5 MW / 150 MWh system. Form Energy's trajectory from a five-person MIT spinout to a company valued at over $1.2 billion illustrates how grid-scale energy storage economics are being reshaped by startups willing to pursue chemistries that incumbent battery manufacturers have overlooked (Form Energy, 2025).

Why It Matters

The US grid-scale energy storage market reached 16.1 GW of installed capacity by the end of 2025, a fourfold increase from 2022 levels. Yet the Department of Energy estimates that achieving an 80% clean electricity grid by 2030 will require 225 to 460 GW of energy storage capacity, with at least 100 GW needing durations of 8 hours or longer (DOE, 2025). Lithium-ion batteries dominate the current installed base at over 95% market share, but their cost structure makes deployments beyond 4 hours economically challenging. At durations of 8 to 12 hours, lithium-ion levelized cost of storage (LCOS) ranges from $200 to $350 per MWh, while applications requiring 24 to 100+ hours are essentially uneconomic at $500 to $1,200 per MWh (Lazard, 2025).

This duration gap creates a massive market opening for alternative storage technologies. BloombergNEF projects the long-duration energy storage (LDES) market will reach $3 to $6 billion in annual deployments by 2030, driven by renewable portfolio standards, reliability mandates, and capacity market reforms that increasingly value multi-day storage (BloombergNEF, 2025). Startups like Form Energy, ESS Inc., Ambri, and Malta Inc. are racing to capture this opportunity with iron-air, iron flow, liquid metal, and molten salt technologies respectively.

Key Concepts

Levelized cost of storage (LCOS) is the per-MWh cost of storing and discharging energy over a system's lifetime, accounting for capital expenditure, operations and maintenance, charging costs, round-trip efficiency, degradation, and end-of-life value. LCOS is the primary metric utilities and independent power producers use to evaluate competing storage bids. For grid-scale projects, target LCOS ranges from $50 to $150 per MWh for 4-hour systems and $100 to $250 per MWh for 8+ hour systems to be competitive with natural gas peaker plants.

Capacity markets are wholesale electricity market mechanisms that compensate generators and storage providers for being available to deliver power during peak demand periods. PJM Interconnection, the largest US capacity market covering 13 states, modified its capacity market rules in 2024 to allow 10-hour storage resources to qualify as capacity resources, expanding the addressable market for LDES technologies by an estimated $2 billion annually.

Iron-air battery chemistry uses reversible rusting: during discharge, iron anodes oxidize (rust) while absorbing oxygen from the air, and during charge, the process reverses, reducing iron oxide back to metallic iron and releasing oxygen. The key advantage is that iron is the fourth most abundant element in the Earth's crust, costing approximately $0.05 per kg versus $24 per kg for lithium carbonate, fundamentally changing the cost trajectory at multi-day durations.

What's Working

Form Energy's scaling strategy has combined several elements that distinguish it from previous LDES ventures. The company secured its initial product-market fit by targeting a specific use case: multi-day backup for utilities facing winter weather reliability risks. Great River Energy, a Minnesota cooperative serving 1.7 million customers, signed the first commercial agreement in 2023 after the 2021 Winter Storm Uri exposed the vulnerability of gas-dependent grids. The project, scheduled for commissioning in late 2026, will provide 100 hours of continuous discharge capacity at a contracted price that Great River Energy has described as "competitive with a new natural gas peaker on a capacity basis" (Great River Energy, 2025).

Manufacturing localization has been another strategic advantage. Form Energy's Weirton facility, supported by $150 million in Department of Energy Loan Programs Office commitments and $290 million in tax credit eligibility under the Inflation Reduction Act's Section 45X Advanced Manufacturing Production Credit, will produce 500 MW of battery modules annually at full capacity. The choice of a former steel mill site provides access to existing industrial infrastructure, a skilled manufacturing workforce, and proximity to iron feedstock suppliers. Production costs at scale are projected at $20 to $30 per kWh of storage capacity, compared to $150 to $200 per kWh for lithium-ion grid systems.

The company's procurement strategy has also evolved effectively. Early-stage agreements with Xcel Energy in Colorado and Georgia Power provided revenue visibility that supported Series E fundraising. By 2025, Form Energy had signed letters of intent or development agreements with eight utilities across six states, representing a pipeline of approximately 5 GW of potential deployments through 2030.

ESS Inc., a publicly traded iron flow battery manufacturer based in Wilsonville, Oregon, offers a parallel scaling narrative. ESS went public via SPAC merger in 2021 at a $1.07 billion valuation and has since shipped over 30 Energy Warehouse units (each 75 kW / 500 kWh) to customers including Enel Green Power, Sacramento Municipal Utility District, and SB Energy. The company's proprietary iron-chloride electrolyte uses only earth-abundant materials, with a projected 25-year operational life and zero capacity degradation, addressing two of the most significant limitations of lithium-ion technology.

What's Not Working

Round-trip efficiency remains the primary technical limitation for most LDES technologies. Form Energy's iron-air system achieves approximately 45% round-trip efficiency, meaning that for every 100 kWh of electricity used during charging, only 45 kWh is recovered during discharge. By comparison, lithium-ion systems achieve 85 to 92% round-trip efficiency. For applications where storage is cycled daily, this efficiency penalty makes iron-air uncompetitive. The technology's economic advantage only materializes at durations of 24 hours or longer, where the low cost per kWh of capacity overcomes the energy loss.

Interconnection queue delays threaten to slow deployment timelines across all storage technologies. The Lawrence Berkeley National Laboratory reported in 2025 that the average time from interconnection request to commercial operation for storage projects in the US was 5.1 years, up from 3.2 years in 2020. Over 2,600 GW of storage capacity sat in interconnection queues nationally, with withdrawal rates exceeding 70% due to costly network upgrade requirements and procedural delays (LBNL, 2025). Form Energy's Great River Energy project has navigated this challenge by co-locating with existing generation assets that have established grid connections, but this approach limits site selection flexibility.

Revenue uncertainty in wholesale markets continues to challenge project financing for LDES. Unlike lithium-ion systems that can stack revenue from energy arbitrage, frequency regulation, and capacity markets through daily cycling, multi-day storage systems derive value primarily from capacity and reliability services that are called upon infrequently. Existing capacity market structures in most US regions do not adequately compensate the insurance-like value of multi-day storage. PJM's 2024 reforms are a step forward, but ISO-NE, MISO, and SPP have yet to implement comparable rules. Without contracted utility offtake or capacity payments, securing non-recourse project financing for LDES at debt-to-equity ratios comparable to lithium-ion (typically 70:30 to 80:20) remains difficult.

Supply chain risks, while lower than lithium-ion's exposure to Chinese processing of critical minerals, are not negligible. Form Energy's iron-air chemistry requires high-purity iron powder and specialized membrane materials. The company has indicated that securing domestic iron powder supply at the required specifications and volumes has been "one of our most challenging scale-up tasks" (Form Energy CEO Mateo Jaramillo, CleanTech Forum, 2025). ESS Inc. faced similar challenges with electrode manufacturing quality control during its 2023 production ramp, resulting in shipment delays and warranty claims that contributed to a 42% stock price decline over six months.

Key Players

Established companies: NextEra Energy (largest US utility-scale storage developer with 5.4 GW installed), Fluence Energy (Siemens/AES joint venture providing storage technology and services across 50 markets), and AES Corporation (early mover in grid storage with 4.2 GW global portfolio).

Startups: Form Energy (iron-air batteries targeting 100-hour duration at sub-$20/kWh), ESS Inc. (iron flow batteries for 4 to 12-hour commercial/industrial applications), Ambri (liquid metal batteries using calcium and antimony electrodes for 4 to 24-hour grid applications), and Malta Inc. (electro-thermal storage using molten salt and chilled liquid for 10+ hour duration).

Investors: Breakthrough Energy Ventures (led Form Energy Series D and E), TPG Rise Climate (invested in multiple LDES platforms), and the DOE Loan Programs Office (committed $9.2 billion to grid storage projects since 2022).

Metric	Form Energy (Iron-Air)	ESS Inc. (Iron Flow)	Lithium-Ion (LFP)
Duration Sweet Spot	24-100+ hours	4-12 hours	1-4 hours
Round-Trip Efficiency	~45%	~65%	85-92%
Projected LCOS (at target duration)	$5-10/kWh capacity	$50-80/kWh capacity	$150-200/kWh capacity
Cycle Life	5,000+ cycles	20,000+ cycles	4,000-8,000 cycles
Calendar Life	25+ years	25+ years	15-20 years
Supply Chain Risk	Low (iron, air)	Low (iron, salt)	High (lithium, cobalt)
Commercial Readiness	First deployments 2026-2027	Shipping since 2022	Mature, at scale

Action Checklist

• Evaluate multi-day storage requirements by modeling renewable curtailment and reliability gaps under 2030 resource plans using 20+ years of weather data
• Issue technology-neutral RFPs for storage durations of 8 hours and above that allow non-lithium technologies to compete on LCOS and lifecycle value
• Engage with PJM, MISO, or relevant ISO/RTO on capacity market accreditation pathways for LDES resources exceeding 4-hour duration
• Assess IRA Section 45X manufacturing credits and DOE LPO loan eligibility for storage procurement decisions, as domestic manufacturing qualification can reduce effective costs by 15 to 25%
• Conduct site selection analysis for LDES co-location with existing grid interconnection points to avoid 3 to 5-year queue delays
• Develop procurement evaluation frameworks that weight supply chain risk, degradation profiles, and end-of-life costs alongside upfront capital cost

FAQ

Q: How does iron-air storage compete with lithium-ion on cost when its efficiency is so much lower? A: The comparison depends entirely on duration. For applications requiring 1 to 4 hours of storage, lithium-ion's higher efficiency and lower per-cycle cost make it the clear winner. At 4 to 8 hours, the two technologies are roughly competitive depending on cycling frequency. Beyond 24 hours, iron-air's dramatically lower cost per kWh of storage capacity ($20 to $30 versus $150 to $200 for lithium-ion) overwhelms the efficiency disadvantage. A 100-hour lithium-ion system would cost $15,000 to $20,000 per kW of capacity, while Form Energy targets $3,000 to $5,000 per kW, making the economic case overwhelming for multi-day reliability applications.

Q: What revenue streams are available for grid-scale storage developers in US markets? A: Grid-scale storage can access multiple revenue streams: energy arbitrage (buying low, selling high, worth $30 to $80 per kW-year in most markets), frequency regulation ($15 to $40 per kW-year), capacity market payments ($40 to $120 per kW-year depending on region), resource adequacy contracts with utilities ($60 to $150 per kW-year), and transmission deferral agreements (project-specific, potentially $200+ per kW-year). Lithium-ion systems typically stack 3 to 4 of these streams through daily cycling, while LDES technologies rely more heavily on capacity and resource adequacy payments. The most financeable projects combine a long-term utility offtake agreement covering 60 to 80% of revenue with merchant exposure to energy and ancillary service markets for the remainder.

Q: What are the biggest risks for utilities considering first-mover LDES procurement? A: The primary risks are technology performance uncertainty, manufacturer viability, and stranded asset exposure. Performance risk can be mitigated through phased procurement with performance guarantees, independent engineering review, and contractual protections including liquidated damages for underperformance. Manufacturer viability risk is addressed through parent company guarantees (where applicable), escrow arrangements for long-term warranty obligations, and diversifying across multiple LDES technology providers. Stranded asset risk is mitigated by selecting technologies with long calendar lives (25+ years) and ensuring procurement contracts include provisions for technology refresh or repowering at end of initial contract terms.

Q: How do interconnection queue reforms affect storage project economics? A: FERC Order 2023, finalized in mid-2024, introduced cluster-based interconnection studies and "first-ready, first-served" principles intended to clear queue backlogs. Early results show mixed progress: PJM processed 260 GW of queue entries in its first transition cycle but still projects 3 to 4-year timelines for new entrants. For storage developers, co-location with existing interconnection points, battery-to-battery augmentation of existing storage sites, and hybrid configurations paired with solar or wind projects that already hold queue positions offer faster paths to commercial operation than standalone greenfield applications.

Sources

• Form Energy. (2025). Weirton Manufacturing Facility: Progress Update and Production Timeline. Somerville, MA: Form Energy Inc.
• US Department of Energy. (2025). National Transmission Needs Study: Storage Requirements for Grid Reliability. Washington, DC: DOE Office of Electricity.
• Lazard. (2025). Lazard's Levelized Cost of Storage Analysis, Version 9.0. New York, NY: Lazard Ltd.
• BloombergNEF. (2025). Long-Duration Energy Storage Market Outlook 2025-2035. New York, NY: Bloomberg LP.
• Great River Energy. (2025). Multi-Day Energy Storage Project: Development Update. Maple Grove, MN: Great River Energy.
• Lawrence Berkeley National Laboratory. (2025). Queued Up 2025: Characteristics of Power Plants Seeking Interconnection. Berkeley, CA: LBNL.
• ESS Inc. (2025). Annual Report 2024: Operational Performance and Deployment Pipeline. Wilsonville, OR: ESS Tech Inc.
• Wood Mackenzie. (2025). US Energy Storage Monitor: Q4 2025 Executive Summary. Edinburgh: Wood Mackenzie Ltd.