Deep dive: Long-duration energy storage (LDES) — the fastest-moving subsegments to watch

The UK's National Grid ESO projects that Great Britain will need between 20 and 30 GW of long-duration energy storage by 2035 to reliably integrate its planned 50 GW offshore wind fleet, yet installed LDES capacity at the end of 2025 stood below 3 GW, almost all of it legacy pumped hydro. That gap, roughly 10x the current base, represents one of the most consequential infrastructure build-outs in British energy history and one of the clearest market opportunities in the clean energy transition. Understanding which LDES subsegments are gaining traction, which remain stalled, and where capital is flowing is essential for sustainability professionals navigating procurement, investment, and policy decisions in the years ahead.

Why It Matters

Lithium-ion batteries dominate the short-duration storage market (two to four hours), but they cannot economically provide the eight-to-200-hour discharge durations needed to bridge multi-day wind droughts or week-long cold spells. The UK experienced its longest low-wind period in a decade during January 2024, with wind capacity factors dropping below 10% for six consecutive days. During that event, gas-fired peakers supplied over 45% of electricity demand, demonstrating the grid's continued vulnerability to intermittent renewable generation. LDES technologies designed to discharge for eight hours or longer at competitive costs are the missing link in decarbonisation strategies that rely on variable renewables for 70% or more of electricity supply.

The economics have shifted dramatically. DESNZ's 2025 review of electricity market arrangements confirmed a new "long-duration storage" category within the Capacity Market, enabling 15-year contracts that address the bankability challenges that have historically deterred investors. The UK Infrastructure Bank committed GBP 1.2 billion to energy storage in 2024 and 2025, with a significant portion earmarked for technologies beyond lithium-ion. Meanwhile, the LDES Council, a coalition of over 60 companies, estimates the global LDES market will reach USD 3 trillion in cumulative investment by 2040, with Europe capturing approximately 25% of that total.

For sustainability professionals, the operational question is no longer whether LDES will be deployed but which subsegments will deliver bankable projects first and at what cost. The answer varies significantly across technology families, and the subsegment landscape is evolving rapidly.

Key Concepts

Long-duration energy storage refers to any technology capable of storing energy and discharging it for eight hours or longer. This distinguishes LDES from short-duration lithium-ion systems (typically two to four hours) and positions it as the primary enabler of high-renewable grids. LDES technologies span mechanical, electrochemical, thermal, and chemical storage families, each with distinct cost structures, siting requirements, and technology readiness levels.

Iron-air batteries use the reversible oxidation and reduction of iron to store and release electrical energy. During discharge, iron metal reacts with oxygen from ambient air, producing iron oxide and releasing electrons. During charge, the process reverses. The active material (iron) is abundant, inexpensive, and globally distributed, giving iron-air batteries a theoretical cost advantage over lithium-based chemistries for durations of 100 hours or longer.

Compressed air energy storage (CAES) stores energy by compressing air into underground caverns, depleted gas fields, or purpose-built pressure vessels. During discharge, the compressed air expands through a turbine to generate electricity. Advanced adiabatic CAES systems capture and store the heat generated during compression, eliminating the need for natural gas firing during expansion and achieving round-trip efficiencies of 60 to 70%.

Liquid air energy storage (LAES) cools ambient air to approximately negative 196 degrees Celsius, converting it to a liquid that occupies roughly 1/700th of its gaseous volume. The liquid air is stored in insulated tanks and, when needed, is heated and expanded through a turbine to generate power. LAES can achieve discharge durations of 10 to over 100 hours depending on tank sizing, and the technology uses no exotic materials.

Flow batteries store energy in liquid electrolytes held in external tanks, decoupling power capacity (determined by cell stack size) from energy capacity (determined by tank volume). This architecture allows independent scaling of power and duration, making flow batteries well suited to applications requiring four to 12 hours of storage. Vanadium redox, zinc-bromine, and iron-chromium chemistries are the leading commercial variants.

Green hydrogen storage uses surplus renewable electricity to produce hydrogen via electrolysis, which is then stored in salt caverns, pressurised vessels, or pipeline networks and reconverted to electricity through fuel cells or hydrogen-ready gas turbines. Hydrogen offers virtually unlimited storage duration but faces round-trip efficiency losses of 60 to 70%, making it most economically viable for seasonal or strategic reserve applications.

LDES Subsegment KPIs: Benchmark Ranges

Metric	Iron-Air	Compressed Air	Liquid Air	Flow Batteries	Green Hydrogen
Discharge Duration	100+ hours	8-200 hours	10-100 hours	4-12 hours	Days to months
LCOS (GBP/MWh)	40-80 (projected)	80-140	120-180	100-200	150-300
Round-Trip Efficiency	45-50%	55-70%	50-60%	65-80%	30-40%
Technology Readiness Level	TRL 6-7	TRL 7-9	TRL 8-9	TRL 7-9	TRL 6-8
Cycle Life (years)	20+ (target)	30-50	25-40	15-25	20-30
Siting Constraints	Low	Geology dependent	Moderate	Low	Geology/infrastructure
Capital Cost (GBP/kWh)	10-25 (projected)	30-80	150-300	150-400	1-10 (cavern)

What's Working

Iron-Air Batteries Enter Pre-Commercial Deployment

Form Energy, the US-based iron-air battery developer, secured its first UK project agreement in late 2024, partnering with a major Distribution Network Operator to deploy a 10 MW/1,000 MWh system designed for 100-hour discharge. The company's manufacturing facility in Weirton, West Virginia, began initial production in mid-2025 with an annual capacity target of 500 MW by 2027. Form Energy's projected levelised cost of storage of USD 20 per kWh installed is roughly one-tenth the cost of equivalent lithium-ion systems at 100-hour durations. Great River Energy in Minnesota commissioned a pilot system in 2024 that operated through a simulated five-day wind drought, validating the technology's ability to bridge extended renewable gaps. For UK sustainability professionals, iron-air represents the highest-potential subsegment for grid-scale seasonal balancing, though commercial deployment timelines remain 2028 or later.

Liquid Air Storage Reaches Commercial Operation

Highview Power's 50 MW/250 MWh CRYOBattery facility near Manchester, which received GBP 10 million from the UK government's Longer Duration Energy Storage Demonstration programme, represents the world's largest liquid air energy storage plant. The technology uses no exotic materials, relies on established industrial gas handling equipment, and can be sited on brownfield land without geological constraints. Highview's second project, a 200 MW/2 GWh facility in Humber, secured planning permission in 2024 and is targeting commissioning by 2028. Sumitomo SHI FW signed a global licensing agreement with Highview in 2023, bringing established EPC capability to future deployments. The LAES subsegment is particularly relevant for UK contexts because it avoids the geological requirements of compressed air and the efficiency penalties of hydrogen.

Flow Batteries Capture the Medium-Duration Market

Invinity Energy Systems, a UK-headquartered flow battery manufacturer, delivered over 70 MWh of vanadium flow battery systems by the end of 2025, including a 7.2 MWh installation for the UK Ministry of Defence and a flagship project for Energy Superhub Oxford. Invinity's partnership with Siemens Gamesa to co-locate flow batteries with onshore wind farms addresses the specific challenge of four-to-eight-hour renewable shifting that lithium-ion handles less cost-effectively at larger scales. ESS Inc., deploying iron-flow battery technology in the US and Europe, delivered its first European systems in 2024 through a partnership with SB Energy. For procurement professionals, flow batteries are the most commercially mature LDES subsegment for durations between four and 12 hours, with bankable track records and established warranty frameworks.

What's Not Working

Compressed air energy storage remains geology-constrained. While Hydrostor's A-CAES technology has demonstrated strong round-trip efficiency (approximately 60%) at its Ontario pilot, the requirement for suitable underground caverns or hard-rock formations limits deployable sites. The UK has salt deposits in Cheshire and the East Yorkshire coast that could host CAES installations, but detailed geological characterisation, permitting, and cavern solution mining require three to five years of lead time. The only operational CAES facilities worldwide (Huntorf in Germany and McIntosh in Alabama) use diabatic designs that burn natural gas during expansion, undermining their decarbonisation value.

Green hydrogen round-trip efficiency remains a fundamental challenge. The electricity-to-hydrogen-to-electricity pathway loses 60 to 70% of input energy through electrolysis, compression or liquefaction, storage, and reconversion. While hydrogen is compelling for seasonal storage (where alternatives are limited) and for sector coupling with industrial heat and transport, its economics for pure electricity storage applications struggle against alternatives with higher efficiency. The UK's hydrogen storage programme, centred on salt cavern development in the Humber and Teesside, is progressing but commercial storage operations are not expected before 2030.

Supply chain bottlenecks constrain scale-up across subsegments. Vanadium supply for flow batteries remains concentrated in Russia, China, and South Africa, creating geopolitical risk. Iron-air technology requires large quantities of commodity iron, but manufacturing the specialised electrode assemblies and air cathodes at scale has not yet been demonstrated. LAES requires cryogenic equipment that competes with the rapidly growing liquefied natural gas industry for manufacturing capacity. Across all LDES subsegments, the skilled workforce for installation and commissioning is thin, with the Institution of Mechanical Engineers estimating a 20,000-person shortfall in UK energy storage engineering roles by 2028.

Revenue certainty lags technology readiness. Despite DESNZ's introduction of a long-duration storage category in the Capacity Market, the contract terms and clearing prices have not yet been finalised as of early 2026. Without confirmed revenue streams, developers cannot reach financial close on projects that require hundreds of millions of pounds in capital. The gap between technology demonstration and bankable project finance remains the single largest barrier to LDES deployment in the UK.

Key Players

Established Companies: National Grid ESO (system operator and market designer), SSE (developer with LDES project pipeline), EDF Energy (exploring CAES at Hornsea), Siemens Energy (hydrogen turbine integration), Sumitomo SHI FW (LAES licensing partner)

Emerging Innovators: Form Energy (iron-air batteries), Highview Power (liquid air energy storage), Invinity Energy Systems (vanadium flow batteries), Hydrostor (advanced compressed air), ESS Inc. (iron-flow batteries), Corre Energy (green hydrogen CAES hybrid)

Investors and Funders: UK Infrastructure Bank, LDES Council members, Breakthrough Energy Ventures (Form Energy backer), Softbank Energy (ESS Inc. partner), Gresham House Energy Storage Fund (diversifying beyond lithium-ion)

Action Checklist

1. Map your organisation's storage duration requirements by analysing historical renewable generation gaps using at least three years of half-hourly data from your grid connection point
2. Engage DESNZ consultations on Capacity Market long-duration storage contract design to influence terms that affect procurement economics
3. Issue technology-neutral Requests for Information to at least three LDES subsegments (iron-air, LAES, and flow batteries) to benchmark current pricing and delivery timelines
4. Assess site suitability for geology-dependent technologies (CAES, hydrogen caverns) by commissioning a British Geological Survey desktop study
5. Develop a phased procurement strategy that deploys commercially mature flow batteries for four-to-eight-hour needs now while reserving strategic capacity for iron-air or LAES projects in the 2028 to 2030 timeframe
6. Join the LDES Council or UK Energy Storage Association to access pre-competitive intelligence on technology performance and policy developments
7. Model portfolio storage costs using both LCOS and system value metrics, accounting for the avoided costs of curtailed renewables and displaced gas peaking

FAQ

How does LDES differ from lithium-ion battery storage?

Lithium-ion batteries are optimised for two-to-four-hour discharge durations and excel at frequency regulation, peak shaving, and short-term renewable shifting. LDES technologies are designed for eight hours to multiple days of discharge, addressing extended periods of low wind or solar output that lithium-ion cannot economically cover. The cost structures differ fundamentally: lithium-ion costs scale roughly linearly with duration (more cells for more hours), while many LDES technologies (particularly CAES, LAES, and hydrogen) decouple power and energy costs, making longer durations progressively cheaper per unit of stored energy.

Which LDES subsegment is closest to commercial deployment in the UK?

Flow batteries, particularly vanadium redox systems from Invinity Energy Systems, are the most commercially mature, with operating installations and established warranty frameworks. Liquid air energy storage from Highview Power is the closest large-scale LDES technology, with the 50 MW Manchester facility in advanced commissioning. Iron-air batteries from Form Energy offer the most compelling long-term cost trajectory but are unlikely to reach UK commercial deployment before 2028.

What policy support exists for LDES in the UK?

The UK government has allocated GBP 68 million through the Longer Duration Energy Storage Demonstration programme, supporting nine projects across multiple technology families. DESNZ has confirmed a dedicated long-duration storage category within the Capacity Market, with 15-year contracts designed to address bankability. The UK Infrastructure Bank has invested over GBP 1 billion in energy storage projects. The Review of Electricity Market Arrangements (REMA) process is expected to introduce additional support mechanisms by 2027.

What are the main risks of investing in LDES projects?

Technology risk varies by subsegment: iron-air is pre-commercial (TRL 6 to 7), while flow batteries and LAES are commercially demonstrated (TRL 8 to 9). Revenue risk remains significant until Capacity Market long-duration contracts are finalised. Supply chain risk affects vanadium flow batteries (concentrated sourcing) and hydrogen (electrolyser availability). Planning and permitting timelines for larger LDES projects (particularly CAES requiring underground works) can extend to three to five years.

How should organisations compare LDES technologies?

Use levelised cost of storage (LCOS) as the primary economic metric, but supplement it with system value analysis that accounts for avoided curtailment, displaced peaker generation, and ancillary service revenue. Evaluate round-trip efficiency, cycle degradation, siting constraints, supply chain risk, and technology readiness level. Request independently verified performance data from reference installations rather than relying on manufacturer projections. Consider engaging the Energy Systems Catapult or a specialist consultancy for technology-neutral assessments.

Sources

1. National Grid ESO, "Future Energy Scenarios 2025," National Grid ESO, July 2025
2. LDES Council, "Net-Zero Heat: Long Duration Energy Storage to Accelerate Energy System Decarbonization," McKinsey and Company, November 2024
3. UK Department for Energy Security and Net Zero, "Review of Electricity Market Arrangements: Long Duration Storage," DESNZ, March 2025
4. Highview Power, "CRYOBattery Technology and Project Pipeline Update," Highview Power, September 2025
5. Form Energy, "Iron-Air Battery Technology Overview and Manufacturing Update," Form Energy, June 2025
6. Invinity Energy Systems, "Annual Report and Accounts 2025," Invinity Energy Systems plc, April 2025
7. UK Infrastructure Bank, "Energy Storage Investment Portfolio Review," UK Infrastructure Bank, January 2026
8. Institution of Mechanical Engineers, "Engineering the Energy Transition: Workforce Requirements for UK Energy Storage," IMechE, October 2025