Trend analysis: Long-duration energy storage (LDES) — where the value pools are (and who captures them)

The global long-duration energy storage (LDES) market reached $1.8 billion in deployed project value in 2025, and BloombergNEF projects it will exceed $50 billion by 2040 as grids worldwide confront the mismatch between variable renewable generation and round-the-clock electricity demand. Yet not all segments of LDES are growing at the same pace, and value capture is concentrating in a handful of technology categories and business models. Understanding where the economic returns actually accumulate is essential for founders, investors, and utilities making capital allocation decisions in this fast-moving sector.

Why It Matters

Lithium-ion batteries dominate short-duration storage (two to four hours), but they cannot economically address the multi-day and seasonal storage gaps that emerge when renewables exceed 60% of grid capacity. The International Energy Agency estimates that reaching net-zero emissions by 2050 will require 1.5 to 2.5 terawatt-hours of long-duration storage capacity globally, a roughly 100-fold increase from current levels (IEA, 2024). Without LDES, grid operators face three costly alternatives: building excess renewable capacity, maintaining fossil fuel peaker plants, or accepting curtailment rates that can exceed 20% in high-renewable grids.

The urgency is accelerating. California curtailed 2.4 million megawatt-hours of renewable energy in 2024, a 30% increase from 2023 (CAISO, 2025). In Germany, negative wholesale electricity prices occurred during 301 hours in 2024, reflecting structural oversupply that only storage can absorb (Fraunhofer ISE, 2025). LDES is no longer a research curiosity; it is becoming a grid necessity, and the value pools are forming around specific technology readiness levels, use cases, and contract structures.

Key Concepts

Duration classification matters for economics. The LDES Council defines long-duration storage as systems capable of discharging for eight hours or more, but economic dynamics differ sharply across duration bands. Eight-to-twelve-hour systems compete with lithium-ion on cost per kilowatt-hour and target transmission congestion relief and renewable firming. Twenty-four-to-one-hundred-hour systems address multi-day weather events and earn premiums for capacity adequacy. Seasonal storage (hundreds of hours and above) remains largely pre-commercial but attracts strategic investment from utilities facing winter reliability mandates.

Value pools concentrate around four use cases. First, renewable energy time-shifting allows asset owners to capture peak pricing spreads rather than selling into midday surplus. Second, transmission and distribution deferral enables utilities to delay or avoid $1 million to $5 million per mile in new line construction. Third, capacity adequacy contracts from grid operators pay for guaranteed dispatchable capacity during stress events. Fourth, ancillary services such as frequency regulation and voltage support generate revenue, though at lower margins than capacity contracts.

Technology risk determines contract structure. Proven technologies such as pumped hydro and compressed air energy storage (CAES) secure 20-to-30-year tolling agreements. Emerging technologies like iron-air batteries and liquid-air energy storage compete for 10-to-15-year contracts with performance guarantees. Pre-commercial technologies such as hydrogen-to-power and thermophotovoltaic systems typically operate under demonstration agreements or cost-plus frameworks.

What's Working

Iron-air batteries are capturing the 100-hour sweet spot. Form Energy's iron-air battery technology, targeting costs below $20 per kilowatt-hour of storage capacity, has secured over 10 gigawatt-hours in announced projects across the United States. The company's first commercial-scale facility, a 10-megawatt/1,000-megawatt-hour system for Great River Energy in Minnesota, began construction in 2025 and targets commissioning in 2027 (Form Energy, 2025). The economics are compelling: at $20/kWh, a 100-hour iron-air system costs roughly $2,000 per kilowatt of capacity, compared to $15,000 or more for an equivalent lithium-ion installation at current pricing. Xcel Energy, Southern Company, and Georgia Power have all signed agreements with Form Energy, signaling utility confidence in the technology's bankability.

Compressed air energy storage is proving commercial viability at scale. Hydrostor, a Canadian company, has advanced its Advanced Compressed Air Energy Storage (A-CAES) technology to commercial deployment. The company's 500-megawatt Willow Rock project in Kern County, California, secured a 25-year tolling agreement and is expected to deliver electricity at a levelized cost below $100 per megawatt-hour for eight-to-twelve-hour discharge durations (Hydrostor, 2025). Unlike traditional CAES, which requires natural gas for reheat, A-CAES uses stored thermal energy, achieving round-trip efficiencies of 60% to 65%. Hydrostor raised $250 million in growth funding from Goldman Sachs Asset Management and the Canada Infrastructure Bank, bringing total capital raised above $400 million.

Flow batteries are winning in the four-to-twelve-hour segment with cost parity approaching. ESS Inc. and Invinity Energy Systems have deployed vanadium and iron flow batteries targeting commercial and industrial customers as well as utility-scale projects. ESS Inc.'s iron flow battery technology, which uses low-cost iron salt and water electrolytes, eliminates the supply chain risks associated with vanadium. The company delivered its Energy Center product to Munich Re's insured storage portfolio in 2024, a milestone that demonstrates bankability through insurance backing (ESS Inc., 2024). Invinity secured a 30-megawatt-hour contract with the UK's Pivot Power, backed by EDF Renewables, for grid-connected storage integrated with EV charging infrastructure.

What's Not Working

Green hydrogen for power-to-gas-to-power remains too expensive. Round-trip efficiency for hydrogen-based storage sits between 30% and 40%, meaning more than half the stored energy is lost in conversion. Combined with electrolyzer capital costs of $600 to $1,200 per kilowatt and fuel cell stack replacement costs every 40,000 to 80,000 hours, the levelized cost of hydrogen-based storage exceeds $250 per megawatt-hour for most configurations (IRENA, 2025). While hydrogen has strategic value for seasonal storage and sector coupling, pure power-to-power applications struggle to compete with mechanical and electrochemical alternatives. Projects like the HyFlexPower demonstrator in France showed technical feasibility but confirmed economic challenges at current hydrogen production costs.

Gravity-based storage systems face scalability and siting constraints. Energy Vault's gravity-based system attracted significant attention and went public via SPAC in 2022, but commercial deployment has been slower than projected. The company pivoted to hybrid systems incorporating lithium-ion batteries alongside its gravity-based technology. Gravitricity, which uses weights in mine shafts, has completed a 250-kilowatt demonstrator but has not yet secured a full-scale commercial contract. The core issue is energy density: gravity systems require massive physical infrastructure to store meaningful energy quantities, making them site-constrained and capital-intensive per unit of storage.

Permitting timelines threaten project economics across all LDES technologies. Large LDES installations face three-to-seven-year permitting cycles in the United States and EU, driven by environmental impact assessments, grid interconnection queues, and local opposition. The Lawrence Berkeley National Laboratory found that the average interconnection queue wait time in the US reached 5 years in 2024, with withdrawal rates exceeding 80% (LBNL, 2025). Projects that secure permits and interconnection agreements hold significant competitive advantages, creating a barrier that favors incumbents with existing grid connections and land rights.

Bankability gaps slow first-of-a-kind deployments. Lenders and project finance institutions apply conservative assumptions to unproven technologies, requiring performance guarantees, technology insurance, and revenue certainty that early-stage LDES companies struggle to provide. The cost of capital for novel LDES technologies runs 300 to 500 basis points higher than for established technologies like pumped hydro, adding 15% to 25% to project costs. The US Department of Energy's Loan Programs Office has stepped in with conditional loan guarantees, but private capital markets remain cautious without multi-year operational track records.

Key Players

Established Leaders

NextEra Energy: Largest renewable energy developer in North America, investing in utility-scale LDES to complement its 30-gigawatt wind and solar portfolio. Partnered with multiple LDES technology providers for pilot deployments.

EDF Renewables: European utility with significant storage ambitions, backing flow battery and CAES projects across the UK and France. Committed to 10 gigawatts of storage capacity by 2035.

Dominion Energy: Virginia-based utility exploring iron-air and flow battery technologies for grid reliability in its integrated resource plan, targeting 2,700 megawatts of storage by 2035.

Emerging Startups

Form Energy: Iron-air battery developer with $800 million+ in total funding. Targeting sub-$20/kWh storage costs for 100-hour systems. Backed by Breakthrough Energy Ventures and ArcelorMittal.

Hydrostor: Advanced compressed air energy storage with 500+ megawatts in development pipeline. Raised $250 million from Goldman Sachs Asset Management.

ESS Inc.: Iron flow battery manufacturer publicly listed on NYSE. Targeting commercial, industrial, and utility-scale applications with 4-to-12-hour duration systems.

Malta Inc.: Electro-thermal storage using molten salt and antifreeze, spun out of Google X. Raised $78 million in Series B funding for 100-megawatt-class systems.

Key Investors and Funders

Breakthrough Energy Ventures: Bill Gates-led fund with investments across LDES technologies including Form Energy and Antora Energy.

Goldman Sachs Asset Management: Lead investor in Hydrostor's growth round, signaling infrastructure-grade confidence in A-CAES technology.

US Department of Energy Loan Programs Office: Providing conditional loan guarantees for first-of-a-kind LDES deployments, de-risking commercial scale-up.

Metric	8-12 Hour Systems	24-100 Hour Systems	Seasonal (100+ Hours)
Installed cost ($/kWh)	$150-300	$20-80	$1-15 (hydrogen)
Round-trip efficiency	65-85%	40-65%	25-45%
Technology readiness	TRL 7-9	TRL 5-8	TRL 3-6
Typical contract length	10-20 years	15-25 years	Demonstration phase
Revenue stack depth	2-3 streams	3-4 streams	1-2 streams
Primary value driver	Arbitrage + ancillary	Capacity + deferral	Reliability insurance
Market leaders	ESS, Invinity, Hydrostor	Form Energy, Malta	Plug Power, Linde

Action Checklist

1. Map your grid's duration gap: Analyze renewable curtailment data and capacity shortfall forecasts for your target market. Duration needs above eight hours indicate LDES opportunity; below eight hours, lithium-ion likely remains more economic.

2. Assess technology readiness against contract requirements: Match the technology readiness level of your chosen LDES solution to the contract structures available. TRL 7+ technologies can secure long-term tolling agreements; TRL 4-6 technologies should target demonstration or cost-plus contracts.

3. Secure interconnection early: File interconnection requests 3-5 years before planned commercial operation. Consider acquiring brownfield sites with existing grid connections to bypass queue delays.

4. Stack revenue streams for bankability: Structure projects to capture two or more revenue sources (capacity payments, energy arbitrage, ancillary services, T&D deferral). Single-revenue models rarely achieve investment-grade returns for novel LDES.

5. Engage insurance and guarantee providers: Work with specialty insurers like Munich Re and Swiss Re that offer technology performance insurance for LDES. Insurance-backed performance guarantees can reduce financing costs by 100-200 basis points.

6. Track policy incentives actively: Monitor US Investment Tax Credit eligibility for standalone storage (now permanent under IRA), EU Innovation Fund allocations, and state-level storage mandates. Policy shifts can change project economics by 20-30%.

7. Build operational track record data: Even small pilot installations generate performance data that dramatically improves bankability. Publish degradation rates, round-trip efficiency under real conditions, and availability metrics to differentiate from competitors.

FAQ

Which LDES technology has the lowest cost per kilowatt-hour? For durations of 100 hours, iron-air batteries from Form Energy target costs below $20/kWh, which would be the lowest among electrochemical options. For 8-12 hour durations, advanced compressed air energy storage from Hydrostor targets $50-80/kWh. Pumped hydro remains the lowest-cost proven technology at $50-150/kWh but requires specific geography.

How does LDES compare to overbuilding renewables plus curtailment? Modeling by the LDES Council shows that deploying LDES alongside renewables reduces total system costs by 10-20% compared to overbuilding renewables alone. The savings come from reduced curtailment, avoided transmission upgrades, and lower peaker plant utilization. At 80%+ renewable penetration, LDES becomes essential rather than optional.

What revenue streams can LDES projects access? LDES projects typically stack capacity payments (the largest revenue source, often 40-60% of total), energy arbitrage (20-30%), ancillary services such as frequency regulation (10-15%), and transmission/distribution deferral payments where available. Multi-use projects with three or more revenue streams achieve returns 200-400 basis points above single-use installations.

When will LDES reach cost parity with natural gas peaker plants? BloombergNEF projects that LDES technologies in the 8-24 hour range will reach cost parity with new gas peakers by 2028-2030 in most markets, assuming continued cost declines of 10-15% annually. For 100-hour systems, cost parity with combined-cycle gas plus carbon pricing is projected by 2032-2035, depending on carbon price trajectories.

Is pumped hydro still relevant given newer LDES technologies? Pumped hydro accounts for over 95% of global energy storage capacity and remains the most proven, lowest-risk LDES technology. New closed-loop pumped hydro designs reduce environmental impact and expand available sites. However, 8-15-year construction timelines limit pumped hydro's ability to meet near-term grid needs, creating space for faster-deploying alternatives.

Sources

1. International Energy Agency. "Energy Storage Outlook 2024: Long-Duration Technologies for Net Zero." IEA, 2024.
2. BloombergNEF. "Long-Duration Energy Storage: Market Outlook and Cost Projections 2025-2040." BNEF, 2025.
3. LDES Council. "Net-zero Power: Long Duration Energy Storage for a Renewable Grid." McKinsey & Company for LDES Council, 2024.
4. California Independent System Operator. "2024 Annual Report on Market Issues and Performance." CAISO, 2025.
5. Fraunhofer Institute for Solar Energy Systems. "Energy Charts: Electricity Generation and Spot Prices in Germany 2024." Fraunhofer ISE, 2025.
6. Lawrence Berkeley National Laboratory. "Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection." LBNL, 2025.
7. International Renewable Energy Agency. "Green Hydrogen Cost Reduction: Scaling Up Electrolysers to Meet the 1.5C Climate Goal." IRENA, 2025.
8. US Department of Energy. "Long Duration Energy Storage Shot: Progress Report." DOE, 2024.