TL;DR:

  • Lithium-ion batteries are excellent for 2–4 hour grid storage but become uneconomical at longer durations — the grid needs 10–100+ hour storage to handle multi-day renewable droughts
  • Iron-air, vanadium redox flow, and liquid air energy storage are the leading technologies addressing this gap, each with distinct cost profiles and use cases
  • Commercial projects are now operating in the UK and US, bringing costs down from demonstration-scale pricing toward grid viability

Solar and wind generation have a problem that’s become more visible as their share of the grid grows: they stop generating when the sun sets and the wind drops. For short mismatches — a few hours of evening peak demand — lithium-ion batteries are an effective solution, and costs have fallen dramatically. But as renewable penetration approaches 70–80% in some grids, a different problem emerges: multi-day low-generation periods. A calm, cloudy week in February. A summer heatwave with no wind across an entire continent.

For these scenarios, the grid needs storage measured in days, not hours. Lithium-ion becomes prohibitively expensive at these durations — not because the technology doesn’t work, but because the cost scales linearly with energy capacity. Long-duration energy storage (LDES) technologies are designed to break that cost scaling.

The Duration-Cost Problem

The economics of energy storage split cleanly into two components: power capacity (how fast you can charge and discharge, measured in MW) and energy capacity (how much total energy you can store, measured in MWh). For lithium-ion, both scale together — a battery with twice the energy capacity costs roughly twice as much.

For storage that needs to cover 100 hours rather than 4 hours, this means a 25x increase in cost for the energy component alone. At these durations, the energy cost dominates the economics, and lithium-ion simply cannot compete with alternatives that have cheap energy storage but potentially higher power conversion costs.

The key metric for LDES is levelised cost of storage (LCOS) at 10–100 hour durations. All three major LDES technologies aim to achieve costs below £30–50/MWh at these timescales, compared to £80–150/MWh for lithium-ion at the same duration.

Iron-Air Batteries

Iron-air batteries use one of the cheapest and most abundant materials on earth — iron — as the energy storage medium. The chemistry is essentially reverse rusting: charging converts iron oxide back to iron metal, releasing oxygen into the air; discharging lets the iron rust again, capturing the energy released.

The appeal: iron is cheap (roughly £0.15/kg), abundant everywhere, and non-toxic. The theoretical LCOS for iron-air at 100-hour durations is below £20/MWh — potentially the cheapest form of electrical energy storage at these timescales.

The challenge: iron-air batteries have a relatively low round-trip efficiency (approximately 50–60%, compared to 85–90% for lithium-ion). This matters less for seasonal or multi-day storage where cheap, abundant renewable energy would otherwise be curtailed — if you’re storing surplus wind at near-zero marginal cost, a 55% round-trip efficiency is acceptable.

Commercial status: Form Energy (US) is the furthest advanced, having secured a contract with Georgia Power for a 15 MW / 1,500 MWh installation — 100 hours of duration — operational from 2024. The company is building out manufacturing capacity and targeting further utility contracts in 2026. No UK commercial deployments have been announced, but National Grid ESO has included iron-air in its long-duration storage procurement framework.

Vanadium Redox Flow Batteries

Flow batteries store energy in liquid electrolyte tanks rather than in solid electrode materials. The electrolyte is pumped through a cell stack during charge and discharge, with the power and energy components fully decoupled: a larger tank gives more energy storage; a larger cell stack gives more power. This decoupling is the core economic advantage at longer durations.

Vanadium redox flow batteries (VRFBs) use vanadium in both the positive and negative electrolyte — avoiding cross-contamination issues that affect other flow chemistries — and can be cycled indefinitely without capacity degradation. The electrolyte itself never degrades and retains its value (vanadium can be recovered and reused at end of life).

Round-trip efficiency: 65–80%, improving with newer stack designs.

Cost profile: At 4-hour duration, VRFBs are more expensive than lithium-ion. At 12-hour duration, they’re roughly comparable. Beyond 12 hours, they become increasingly cost-competitive as only the tank size (cheap) needs to scale rather than the cell stack (expensive).

Commercial status: Multiple utility-scale VRFB installations are operating globally. In the UK, Invinity Energy Systems (Edinburgh-based) has deployed VRFB systems at several commercial sites including an installation at Pivot Power’s battery energy storage site in Oxfordshire. The Scottish Government’s Orkney LDES pilot includes VRFB technology for island grid stabilisation.

Vanadium supply: The main concern is vanadium supply concentration — approximately 60% comes from China and Russia. UK and European developers are investigating alternative vanadium sources and recycling pathways to reduce supply chain exposure.

Liquid Air Energy Storage (LAES)

Liquid air energy storage works by using surplus electricity to compress and cool air until it liquefies (at around -196°C), then storing the liquid in insulated tanks. When electricity is needed, the liquid air is allowed to warm and expand, driving turbines to generate power. The tanks are essentially giant thermos flasks — cheap at scale, with no special materials requirements.

The appeal: the technology uses entirely conventional industrial equipment (compressors, heat exchangers, expansion turbines), which means it can be built with existing manufacturing supply chains. The storage medium — liquid air — is free and universally available. Plant lifetime is expected to exceed 30 years with minimal degradation.

Round-trip efficiency: 50–70%, with improvements available by capturing waste heat from nearby industrial processes to warm the liquid air during discharge (boosting efficiency to around 70%).

Commercial status: Highview Power (UK) has commissioned the world’s first commercial LAES plant in Carrington, Greater Manchester — a 50 MW / 250 MWh facility that became fully operational in 2024. A second, larger facility (300 MW / 2,500 MWh) has been announced for the Humber industrial cluster, targeting commissioning in 2027. Highview has positioned LAES as particularly suited to industrial cluster sites where waste heat is available and large footprints are accessible.

Grid Applications and When Each Technology Fits

These three technologies address different grid needs:

Multi-day weather event storage: All three technologies can cover 24–100+ hours, making them suitable for the “wind drought” scenario. Iron-air has the most favourable long-run economics if efficiency losses can be absorbed.

Industrial site backup: VRFBs are increasingly used for large industrial sites and microgrids requiring 8–24 hours of backup, particularly where cycle life and space constraints make lithium-ion impractical.

Co-location with industrial waste heat: LAES benefits substantially from nearby waste heat sources — data centres, industrial plants, power stations — making Highview’s targeting of industrial clusters strategically sound.

Seasonal storage: None of these technologies is yet economic for full seasonal storage (winter surplus stored until summer), which requires multi-month durations. Hydrogen and synthetic fuels remain the primary candidates for that application.

UK Policy Context

The UK government’s Review of Electricity Market Arrangements (REMA) process explicitly identified long-duration storage as a gap in current market incentives. Existing capacity market contracts favour dispatchable generation over storage, and the 15-year contract length available for storage projects is considered insufficient for LDES capital recovery (projects typically need 20–25 years).

National Grid ESO’s 2026 LDES tender, which opened in Q1 2026, offers enhanced contract terms for projects demonstrating at least 8 hours of duration. First contracts are expected to be awarded in late 2026. This represents the first targeted policy support specifically designed to bring LDES projects to commercial scale in the UK rather than relying on general capacity market participation.

For households and small businesses, LDES is an infrastructure story rather than a direct consumer technology — the benefit will show up in lower wholesale prices and greater grid stability as renewable curtailment (currently costing consumers hundreds of millions of pounds annually) is reduced. The economics of long-duration storage, done right, improve energy bills for everyone connected to the grid.