Long-duration energy storage (LDES): the 20 most-asked questions, answered

The International Energy Agency estimates that achieving net-zero electricity systems by 2050 will require between 85 and 140 TWh of long-duration energy storage globally, yet deployed LDES capacity at the end of 2025 stood at roughly 1.5 TWh, nearly all of it pumped hydroelectric storage built decades ago. This gap between what grids need and what exists today represents one of the largest unsolved infrastructure challenges in the energy transition. For founders, investors, and energy professionals navigating this space, the questions are urgent and the answers are evolving rapidly. This FAQ addresses the 20 questions most frequently raised about LDES technology, economics, and deployment in 2026.

Why It Matters

As wind and solar generation grows past 30% penetration in major electricity markets, short-duration lithium-ion batteries (typically 2 to 4 hours of discharge) become insufficient to maintain grid reliability. Multi-day weather events, seasonal variation in solar output, and extended low-wind periods create storage needs measured in days and weeks, not hours. California's August 2025 heat dome event demonstrated this constraint when five consecutive days of above-average demand and below-average wind generation exhausted 4-hour battery reserves within the first evening peak, forcing emergency natural gas generation.

The EU's revised Electricity Market Design Regulation, adopted in early 2025, explicitly recognizes LDES as a distinct asset class eligible for capacity remuneration mechanisms and long-term contracts. The United States Department of Energy's Long Duration Energy Storage Shot aims to reduce costs to $0.05 per kWh of stored energy by 2030, a 90% reduction from 2020 levels. China's 14th Five-Year Plan targets 100 GW of non-pumped-hydro energy storage by 2030, with provincial mandates requiring renewable energy projects to include storage of 4 hours or longer.

For founders building LDES technologies and investors evaluating this sector, understanding the technical landscape, competitive dynamics, and policy frameworks is essential for making sound decisions in a market expected to exceed $50 billion annually by 2035 according to McKinsey's energy storage practice.

Key Concepts

Long-duration energy storage refers to technologies capable of storing energy and discharging it over periods of 10 hours or more, with some definitions extending to multi-day or seasonal storage (100+ hours). The critical distinction from short-duration storage is economic: LDES systems must achieve very low cost per unit of stored energy ($/kWh) even if their power capacity cost ($/kW) is higher.

Round-trip efficiency measures the percentage of energy input that can be recovered as useful output. Lithium-ion batteries achieve 85 to 92% round-trip efficiency. Most LDES technologies operate at lower efficiencies: compressed air energy storage (CAES) at 55 to 70%, iron-air batteries at 45 to 50%, and green hydrogen at 30 to 40%. Lower efficiency is acceptable when the energy being stored would otherwise be curtailed.

Levelized cost of storage (LCOS) captures the total cost of storing and delivering one unit of energy over a system's lifetime, incorporating capital costs, operating expenses, efficiency losses, and degradation. LCOS is the primary metric for comparing LDES technologies on an economic basis, and it falls dramatically as discharge duration increases beyond 8 hours, where lithium-ion costs escalate linearly while LDES costs grow marginally.

Curtailment occurs when renewable generation must be reduced because supply exceeds demand and storage capacity. Germany curtailed 8.7 TWh of wind and solar energy in 2024, enough to power 2.5 million homes for a year. LDES directly addresses curtailment by absorbing excess generation for later use.

LDES Technology Comparison

Metric	Iron-Air	Flow Batteries	Compressed Air (CAES)	Liquid Air (LAES)	Green Hydrogen	Pumped Hydro
Discharge Duration	100+ hrs	4-12+ hrs	8-24+ hrs	4-24+ hrs	24-168+ hrs	6-24+ hrs
Round-Trip Efficiency	45-50%	65-80%	55-70%	50-60%	30-40%	75-85%
Capital Cost ($/kWh)	$10-20 (target)	$150-350	$50-100	$200-350	$15-30 (storage)	$50-200
Technology Readiness	Pilot	Commercial	Commercial	Demo	Commercial (components)	Mature
Siting Constraints	Minimal	Minimal	Geological	Minimal	Moderate	Severe
Lifespan (years)	20-30 (projected)	20-25	30-40+	25-30	20-30	50-100

The 20 Most-Asked Questions, Answered

1. What qualifies as long-duration energy storage?

The US Department of Energy defines LDES as systems capable of storing energy for 10 or more hours at a cost competitive with alternatives. The LDES Council, an industry coalition of over 60 members, uses a broader definition of storage durations from 8 hours to seasonal (weeks or months). In practice, the market segments into three tiers: medium-duration (8 to 24 hours), multi-day (24 to 168 hours), and seasonal (168+ hours). Each tier serves different grid needs and favors different technologies.

2. Why can lithium-ion batteries not serve as long-duration storage?

Lithium-ion battery costs scale nearly linearly with duration because adding more hours requires proportionally more cells. A 4-hour lithium-ion system at $200 per kWh costs $800 per kW of power capacity. Extending to 100 hours would cost $20,000 per kW, making it economically impractical. LDES technologies decouple energy capacity from power capacity, meaning the marginal cost of adding storage duration is far lower than the cost of the power conversion equipment.

3. What are the leading LDES technologies in 2026?

Five technology families dominate the LDES landscape. Iron-air batteries (Form Energy) store energy in the reversible oxidation of iron. Vanadium redox flow batteries (Invinity Energy Systems, CellCube) store energy in liquid electrolyte tanks. Compressed air energy storage (Hydrostor) stores energy by compressing air in underground caverns. Liquid air energy storage (Highview Power) liquefies and stores air at cryogenic temperatures. Green hydrogen stores energy in the chemical bonds of hydrogen produced via electrolysis. Pumped hydro remains the incumbent but faces severe geographic and permitting constraints for new construction.

4. What is Form Energy's iron-air battery, and how does it work?

Form Energy's system uses reversible rusting: during charging, iron pellets are reduced to metallic iron; during discharge, the iron oxidizes (rusts) by absorbing oxygen from the air, releasing electrons. The raw materials are iron, water, and air, all globally abundant and inexpensive. The company targets system costs below $20 per kWh for 100-hour discharge duration. Form Energy broke ground on its first manufacturing facility in Weirton, West Virginia in 2023 and has announced utility contracts exceeding 10 GWh with partners including Great River Energy, Xcel Energy, and Georgia Power.

5. How do flow batteries compare to lithium-ion for grid storage?

Flow batteries store energy in liquid electrolytes housed in external tanks, separating energy capacity (tank size) from power capacity (cell stack size). This architecture enables independent scaling of duration, making flow batteries cost-effective at 6 to 12+ hours. Vanadium redox flow batteries, the most mature chemistry, offer 20,000+ cycle life with zero degradation in energy capacity because the electrolyte does not degrade. The tradeoffs include lower energy density (20 to 35 Wh/L versus 200 to 400 Wh/L for lithium-ion), lower round-trip efficiency (65 to 80% versus 85 to 92%), and higher upfront costs for shorter durations.

6. What is the role of compressed air energy storage?

CAES systems compress air during periods of excess generation and store it in underground caverns, depleted gas fields, or purpose-built lined rock caverns. When power is needed, the compressed air is expanded through a turbine. Advanced adiabatic CAES (A-CAES) captures and stores the heat of compression, improving round-trip efficiency to 60 to 70%. Hydrostor, the leading developer, has projects totaling over 4 GW in development across North America, including the 500 MW Willow Rock project in California. CAES is cost-competitive for 8 to 24-hour durations but requires suitable geology.

7. Can green hydrogen serve as seasonal energy storage?

Green hydrogen produced via electrolysis is the only commercially available technology capable of true seasonal storage at scale. Hydrogen can be stored in salt caverns for months with minimal losses and converted back to electricity via fuel cells or gas turbines. The primary limitation is round-trip efficiency: electrolysis at 70 to 80% efficiency multiplied by fuel cell or turbine efficiency of 40 to 60% yields system round-trip efficiency of only 30 to 40%. This means 60 to 70% of stored energy is lost. For seasonal applications where the alternative is curtailing renewable generation entirely, this loss is acceptable.

8. How much LDES does the grid actually need?

The National Renewable Energy Laboratory (NREL) estimates that the US grid will need 5 to 8 TWh of storage capacity beyond 4-hour lithium-ion to reach 90% clean electricity, with 100 to 200 GW of LDES power capacity. The European Commission's modelling suggests the EU needs 30 to 60 TWh of seasonal and multi-day storage by 2050. These requirements increase sharply as variable renewable penetration exceeds 60 to 70% of total generation, the threshold where curtailment and multi-day supply gaps become structurally significant.

9. What does LDES cost per kWh of stored energy?

Costs vary significantly by technology and duration. At 100-hour discharge, Form Energy targets $20 per kWh for iron-air systems. Compressed air ranges from $50 to $100 per kWh depending on cavern availability. Flow batteries cost $150 to $350 per kWh at 10-hour duration but the marginal cost of additional hours is only the electrolyte ($20 to $80 per kWh for vanadium). Pumped hydro costs $50 to $200 per kWh but new greenfield projects in Europe and North America are at the upper end due to civil works and environmental permitting.

10. What policy mechanisms support LDES deployment in the EU?

The EU's revised Electricity Market Design explicitly allows capacity remuneration mechanisms for storage, enabling LDES to receive reliability payments. The Innovation Fund has allocated EUR 450 million to energy storage projects in its 2024 and 2025 funding rounds. Several member states offer additional support: Spain's Storage Strategy targets 20 GW by 2030 with auctions for long-duration assets, Germany's amended Energy Industry Act allows network operators to procure storage services, and the Netherlands includes LDES in its SDE++ subsidy scheme for renewable energy technologies.

11. How does the US Inflation Reduction Act affect LDES?

The IRA's Investment Tax Credit (Section 48) provides a 30% tax credit for standalone energy storage projects, with an additional 10% for domestic content and 10% for projects in energy communities. This applies to all storage durations, making it technology-neutral. The DOE's LDES Shot initiative complements the IRA with $505 million in demonstration project funding. The combination of ITC and DOE funding has catalyzed project announcements exceeding 25 GW of LDES capacity in the US, though the majority remain in early development stages.

12. What is the LDES Council, and what does it do?

The Long Duration Energy Storage Council is a CEO-led organization founded in 2021 at COP26, comprising over 60 members including technology developers, utilities, investors, and industrial offtakers. Members include Form Energy, ESS Inc., Hydrostor, EDF, Breakthrough Energy, and Vattenfall. The Council publishes market sizing reports, advocates for policy frameworks that recognize LDES as distinct from short-duration storage, and facilitates dialogue between technology developers and potential customers. Its 2025 report projected that LDES deployment must reach 1.5 to 2.5 TW globally by 2040 to maintain grid reliability at renewable penetration levels above 60%.

13. How does pumped hydro compare to newer LDES technologies?

Pumped hydro accounts for over 95% of installed energy storage capacity globally (approximately 160 GW and 1.4 TWh). It is technically mature, highly efficient (75 to 85% round-trip), and extremely long-lived (50 to 100+ years). The limitation is siting: pumped hydro requires specific topography (elevation differential, water availability) and faces lengthy permitting timelines of 7 to 15 years in Europe and North America. New approaches like underground pumped hydro (using abandoned mines) and seawater pumped hydro are being explored but remain at early stages. For greenfield LDES projects, newer technologies offer faster permitting, flexible siting, and competitive economics at durations beyond 10 hours.

14. What is the current state of LDES manufacturing capacity?

LDES manufacturing is nascent compared to lithium-ion, which has over 2.6 TWh of annual cell production capacity. Form Energy's West Virginia plant will produce iron-air systems upon completion. ESS Inc. manufactures iron flow batteries at its Wilsonville, Oregon facility, targeting 3 GWh of annual capacity by 2027. Invinity Energy Systems manufactures vanadium flow batteries in Canada and the UK. Hydrostor's compressed air systems use established turbomachinery supply chains. The LDES sector's manufacturing maturity is roughly where lithium-ion was in 2012 to 2014: proven technology with limited production scale, requiring significant capital investment to reach cost targets.

15. What are the main risks of investing in LDES technologies?

Technology risk varies by maturity: flow batteries and CAES are commercially proven, while iron-air remains in pilot stage. Market risk stems from uncertain revenue streams, as most electricity markets do not yet compensate multi-day storage adequately. Policy risk is significant because LDES business cases depend heavily on capacity payments, carbon pricing, or direct subsidies that may change with political cycles. Execution risk includes manufacturing scale-up challenges, supply chain constraints (vanadium for flow batteries, salt caverns for CAES and hydrogen), and interconnection queue delays averaging 4 to 5 years in the US.

16. How does LDES reduce renewable energy curtailment?

Curtailment occurs when renewable generation exceeds grid demand and storage capacity simultaneously. In 2024, Ireland curtailed 11% of its available wind generation, and California curtailed 2.4 million MWh of solar. LDES absorbs this surplus energy for discharge during extended periods of low renewable output. Modeling by the LDES Council shows that deploying 100 GW of LDES globally by 2030 could prevent curtailment of 150 to 200 TWh of clean energy annually, equivalent to the electricity consumption of France.

17. What revenue streams can LDES access?

LDES can stack multiple revenue streams: energy arbitrage (buying low, selling high across multi-day price spreads), capacity payments for resource adequacy (ensuring sufficient generation is available during peak periods), ancillary services (frequency response, voltage support), transmission and distribution deferral (avoiding costly grid upgrades), and renewable energy firming (guaranteeing dispatchable clean energy delivery). The relative value of each stream varies by market design. In the EU, capacity remuneration mechanisms in France, Italy, the UK, and Ireland provide the most bankable revenue for LDES.

18. What role does LDES play in industrial decarbonization?

Industrial facilities with continuous power requirements (data centers, manufacturing, chemical processing) increasingly seek 24/7 carbon-free energy matching rather than annual average renewable procurement. LDES enables industrial consumers to match their electricity consumption with clean energy around the clock by storing surplus daytime solar or nighttime wind for use during gaps. Google, Microsoft, and Nucor Steel have announced procurement interest in LDES-backed clean energy contracts. The EU Corporate Sustainability Reporting Directive's forthcoming guidance on energy procurement quality is expected to accelerate this trend.

19. How does LDES interact with grid planning and transmission?

LDES can substitute for or complement transmission infrastructure. Strategically sited LDES reduces peak power flows across constrained transmission corridors, deferring or avoiding costly upgrades. In regions with transmission bottlenecks, LDES captures locally generated renewable energy that would otherwise be curtailed due to export constraints. The UK's National Grid ESO has incorporated LDES into its Future Energy Scenarios as a critical tool for managing constraints between Scottish wind generation and English demand centers.

20. What should founders and investors prioritize in the LDES space in 2026?

Founders should focus on technologies that address the 10 to 100-hour duration gap where no dominant technology exists, prioritize sites with favorable permitting pathways and grid interconnection, and pursue early revenue through utility demonstration contracts and DOE or EU Innovation Fund grants. Investors should evaluate LDES opportunities against three criteria: technology readiness (proven at pilot scale or above), cost trajectory (credible pathway to $0.05 per kWh LCOS by 2030), and policy environment (jurisdictions with explicit LDES procurement mechanisms). The highest-conviction near-term opportunities are in markets with high renewable penetration and explicit capacity market frameworks, including the UK, Australia, California, and the Nordics.

What's Working

Iron-air pilot projects are validating performance claims. Form Energy's pilot installations with Great River Energy in Minnesota and Georgia Power are providing real-world operational data on 100-hour iron-air systems. Early results confirm discharge at rated capacity over multi-day cycles with degradation rates consistent with 20-year design life projections. These pilots are critical for establishing the performance track record that utility procurement and project finance require.

Flow batteries are achieving commercial traction in Europe and Asia-Pacific. Invinity Energy Systems delivered a 7.2 MWh vanadium flow battery to the UK's largest battery storage project at the Oxford Energy Superhub. In China, Rongke Power commissioned a 400 MWh vanadium flow battery installation in Dalian, the largest single flow battery project globally. These deployments demonstrate that flow batteries can operate reliably at scale for 10+ hour durations with minimal degradation over thousands of cycles.

Policy frameworks are beginning to differentiate LDES from short-duration storage. California's SB 1314 established a separate procurement mandate for resources capable of providing 8+ hours of storage, and the CPUC ordered 2 GW of LDES procurement by 2032. The UK's Review of Electricity Market Arrangements proposed technology-specific auctions for long-duration flexibility. These policy innovations are essential because generic storage procurement tends to select the lowest-cost 2 to 4-hour lithium-ion systems, leaving the multi-day storage gap unaddressed.

What's Not Working

Revenue certainty remains the binding constraint on project finance. Most electricity markets do not adequately compensate the reliability value that LDES provides during rare but critical multi-day events. Capacity markets typically pay based on 4-hour availability, undervaluing longer-duration assets. Without long-term contracts or regulatory mandates, LDES projects struggle to secure the 15 to 20-year revenue commitments needed for debt financing.

Vanadium supply and pricing create headwinds for flow batteries. Vanadium prices fluctuated between $25 and $45 per kilogram in 2024 and 2025, introducing significant cost uncertainty. Over 55% of global vanadium production is concentrated in China and Russia, creating supply chain risk. Zinc-bromine and iron-chromium flow battery alternatives aim to mitigate this dependence, but they are at earlier stages of commercial deployment.

Permitting and interconnection timelines undermine deployment targets. LDES projects face the same interconnection queue bottlenecks as other generation and storage assets. In the US, the average wait time in interconnection queues exceeds 4 years, with 2,600 GWh of storage capacity pending as of mid-2025 according to Lawrence Berkeley National Laboratory. European timelines are shorter but still typically require 2 to 4 years from application to energization for large-scale projects.

Key Players

Established Companies

• Form Energy: developing 100-hour iron-air battery systems with utility contracts exceeding 10 GWh and a manufacturing facility under construction in Weirton, West Virginia
• Hydrostor: advanced compressed air energy storage developer with over 4 GW in development across North America, including the 500 MW Willow Rock project in California
• Invinity Energy Systems: manufactures commercial-scale vanadium flow batteries deployed across the UK, North America, and Australia for 4 to 12-hour applications
• EDF: major European utility investing in LDES through its storage division, with pumped hydro and compressed air projects in France and the UK

Startups

• ESS Inc.: manufactures iron flow batteries using earth-abundant materials at its Oregon facility, targeting industrial and utility customers requiring 4 to 12-hour storage
• Highview Power: develops liquid air energy storage (cryogenic) systems with a 50 MW/250 MWh facility under construction in the UK
• Energy Dome: Italian startup commercializing CO2 battery technology using supercritical CO2 as the working fluid, with a 20 MW/200 MWh demonstration plant completed in Sardinia in 2024
• Malta Inc.: developing molten salt-based pumped heat energy storage with backing from Breakthrough Energy Ventures

Investors and Funders

• Breakthrough Energy Ventures: portfolio includes Form Energy, Malta Inc., and other LDES developers, with over $2 billion deployed across climate technology
• US Department of Energy: committed $505 million to LDES demonstration projects through the LDES Shot initiative and Bipartisan Infrastructure Law
• Prelude Ventures: early-stage climate technology investor with positions in multiple LDES companies including ESS Inc.
• TPG Rise Climate: growth-stage fund investing in energy storage and grid infrastructure at scale

Action Checklist

• Assess whether your grid interconnection or service territory faces multi-day reliability gaps that LDES could address
• Evaluate LDES technology options against site-specific factors including duration requirements, siting constraints, and available revenue streams
• Map available policy support including IRA tax credits, EU Innovation Fund, and state or member state procurement mandates
• Engage with LDES developers for indicative pricing and delivery timelines, recognizing that 2 to 4-year lead times are typical for first-of-kind projects
• Explore capacity market participation and long-term contract structures that provide revenue certainty for LDES assets
• Monitor interconnection queue reforms and seek projects with expedited grid connection pathways
• Include LDES in corporate energy procurement strategies for 24/7 carbon-free energy matching
• Join the LDES Council or equivalent industry groups to access market intelligence and policy advocacy efforts

FAQ

Q: How is LDES different from regular battery storage? A: Regular battery storage (lithium-ion) is optimized for 2 to 4-hour discharge, providing services like peak shaving and frequency regulation. LDES technologies are designed for 10 to 100+ hours of discharge, addressing multi-day weather events, seasonal variation, and grid reliability during extended periods of low renewable output. The key economic difference is that LDES technologies decouple energy and power costs, making the marginal cost of adding storage duration much lower than adding lithium-ion cells.

Q: When will LDES reach cost parity with natural gas peaker plants? A: At current cost trajectories, several LDES technologies are projected to reach cost parity with new-build gas peakers ($150 to $250 per kW per year for capacity) by 2028 to 2032. Form Energy's iron-air system targets $20 per kWh, which at 100-hour duration translates to capacity costs competitive with peakers. Compressed air systems from Hydrostor already claim cost competitiveness for 8 to 12-hour duration applications. Carbon pricing above EUR 80 per tonne accelerates this crossover by increasing the operating cost of gas peakers.

Q: What is the biggest technical risk for LDES technologies? A: For iron-air batteries, the primary risk is demonstrating consistent performance and acceptable degradation over 20+ year lifetimes, as field data currently spans only 2 to 3 years. For flow batteries, vanadium supply chain concentration and electrolyte degradation management are key concerns. For compressed air, geological risk (cavern integrity, air leakage) must be mitigated through extensive site characterization. For hydrogen, electrolyzer and fuel cell durability under cycling conditions remains a concern, with current systems achieving 60,000 to 80,000 operating hours before major overhauls.

Q: Should EU-based founders focus on a specific LDES technology? A: EU founders should consider the regulatory and geographic context. Flow batteries align well with the EU's Critical Raw Materials Act if non-vanadium chemistries (iron, zinc-bromine) are used. Compressed air is viable in countries with suitable geology (Germany, the Netherlands, Denmark, the UK). Green hydrogen benefits from the EU's Hydrogen Strategy and REPowerEU targets. Iron-air is promising but depends on US-based Form Energy's technology transfer or European competitors emerging. The strongest near-term commercial opportunity is in markets with explicit LDES procurement mandates or capacity mechanisms that value duration.

Sources

• International Energy Agency. (2025). World Energy Outlook 2025: Energy Storage Requirements for Net-Zero Pathways. Paris: IEA Publications.
• Long Duration Energy Storage Council. (2025). The Path to 1.5 TW: Global LDES Deployment Roadmap and Market Sizing. Geneva: LDES Council.
• National Renewable Energy Laboratory. (2025). Storage Futures Study: The Role of Long-Duration Storage in Deep Decarbonization. Golden, CO: NREL.
• Lawrence Berkeley National Laboratory. (2025). Queued Up: Characteristics of Power Plants Seeking Interconnection in the US. Berkeley, CA: LBNL.
• McKinsey & Company. (2025). The Long-Duration Energy Storage Market: Technology Landscape and Investment Outlook. New York: McKinsey Energy Insights.
• European Commission. (2025). Revised Electricity Market Design: Implementation Guidance for Energy Storage. Brussels: European Commission.
• BloombergNEF. (2025). Long-Duration Energy Storage Market Outlook 2026-2035. New York: Bloomberg LP.