Deep dive: Long-duration energy storage (LDES) — what's working, what's not, and what's next

Form Energy announced in late 2025 that its 100-hour iron-air battery system had completed a full year of continuous grid-connected operation at a utility-scale pilot in Minnesota, delivering energy at a levelized cost of $27 per MWh for storage durations exceeding 72 hours (Form Energy, 2025). That single milestone validated a technology pathway that lithium-ion chemistry cannot economically reach, and it reshaped how grid planners across the Asia-Pacific region model their 2030 to 2040 decarbonization scenarios. The global LDES market reached $3.8 billion in deployed capacity in 2025, growing at 42% year-over-year, with the Asia-Pacific region accounting for 54% of new project announcements (LDES Council, 2026). For engineers designing grids that must operate reliably with 80% or more renewable penetration, understanding which LDES subsegments are accelerating and which remain stalled is critical for technology selection and project planning.

Why It Matters

Lithium-ion batteries dominate short-duration storage (2 to 4 hours) but become prohibitively expensive for durations exceeding 8 hours. The International Energy Agency estimates that achieving global net-zero by 2050 requires 1.5 to 2.5 TW of energy storage capacity, with 85 to 140 TWh of storage energy, the vast majority of which must be long-duration: 10 hours to multiple days and even seasonal timescales (IEA, 2025). Without LDES, grids relying heavily on variable renewables face reliability gaps during multi-day low-wind and low-solar events, commonly referred to as "dunkelflauten" in European planning terminology but equally relevant to monsoon-season solar reductions across South and Southeast Asia.

The economics of curtailment make the case urgent. Australia curtailed 1.9 TWh of renewable generation in 2025, representing $140 million in lost revenue and wasted clean energy (Australian Energy Market Operator, 2025). China's western provinces curtailed over 7% of wind generation due to insufficient storage and transmission capacity. LDES deployed at scale could capture 60 to 80% of curtailed energy, converting a system liability into a grid asset.

Policy frameworks are catching up. China's 14th Five-Year Plan for energy storage allocates $12 billion specifically for LDES demonstration and commercialization. India's Green Hydrogen and Energy Storage Mission includes a 10 GW LDES procurement target by 2030. Australia's Capacity Investment Scheme explicitly includes LDES eligibility for projects offering 8 or more hours of discharge duration. Japan's Grid Transformation Roadmap targets 30 GWh of non-lithium storage by 2035.

Key Concepts

Long-duration energy storage is generally defined as systems capable of storing and discharging energy for 10 or more hours at rated power, though some definitions start at 8 hours. The critical distinction from short-duration storage is not merely the number of hours but the cost structure: LDES technologies must achieve low energy capacity costs ($/kWh) even if their power capacity costs ($/kW) are higher than lithium-ion. For a 100-hour storage system, energy capacity cost must fall below $10 to $20 per kWh to be competitive, compared to $150 to $250 per kWh for lithium-ion cells.

Mechanical LDES encompasses pumped hydro storage (PHS), compressed air energy storage (CAES), liquid air energy storage (LAES), and gravity-based systems. Pumped hydro remains the dominant deployed LDES technology globally, representing over 95% of installed long-duration capacity. New mechanical technologies seek to replicate pumped hydro's economics without requiring specific geological or topographical conditions.

Electrochemical LDES includes iron-air batteries, zinc-bromine flow batteries, vanadium redox flow batteries (VRFB), and organic flow batteries. These systems decouple energy capacity from power capacity: adding more electrolyte or reactant material increases storage duration without requiring additional power conversion equipment. This architecture gives flow batteries a structural cost advantage at durations exceeding 8 to 10 hours.

Thermal energy storage uses heated or cooled media (molten salt, crusite, sand, or phase-change materials) to store energy as heat. Thermal LDES is particularly relevant for industrial applications where stored heat can be directly utilized, avoiding the round-trip efficiency losses of electricity-to-heat-to-electricity conversion.

Round-trip efficiency (RTE) measures the percentage of energy recovered from storage relative to energy input. Lithium-ion achieves 85 to 92% RTE, while LDES technologies range from 40 to 75% depending on the pathway. For multi-day storage applications, the absolute cost of energy stored matters more than RTE, since the alternative is curtailment (0% utilization of generated energy).

What's Working

Pumped Hydro Storage Expansion in Asia-Pacific

Pumped hydro remains the most bankable LDES technology, and the Asia-Pacific region is driving a massive buildout. China added 18 GW of new pumped hydro capacity in 2025 alone, bringing its national total to over 70 GW, and has 120 GW under construction or in advanced planning (China National Energy Administration, 2025). The Fengning Pumped Storage Power Station in Hebei Province, commissioned in 2023 with 3.6 GW capacity and 40 GWh of storage, operates at a round-trip efficiency of 78% and provides critical flexibility services to the Jing-Jin-Ji power grid. Its construction cost of $76 per kWh of storage capacity sets a benchmark that emerging LDES technologies must approach to compete.

Australia's Snowy 2.0 project, despite construction delays and cost overruns reaching A$12 billion (up from an original estimate of A$5.1 billion), represents 2 GW and 350 GWh of storage capacity that will fundamentally reshape the National Electricity Market's ability to integrate renewables. India has 10 GW of pumped hydro under construction across 8 states, with the 1.5 GW Tehri Pumped Storage Plant in Uttarakhand expected to deliver energy at $35 per MWh for 12-hour discharge cycles.

Iron-Air Battery Commercialization

Iron-air technology has emerged as the most credible electrochemical pathway for multi-day storage. Form Energy's iron-air system uses the reversible rusting of iron: during discharge, iron pellets oxidize (rust) and release electrons; during charge, the process reverses. The raw materials (iron and air) are abundant and inexpensive, enabling energy capacity costs projected at $6 to $10 per kWh at scale, roughly one-tenth the cost of lithium-ion.

Form Energy broke ground on its first commercial manufacturing facility in Weirton, West Virginia, with 1 GW annual production capacity. The company has secured contracts with Xcel Energy (1.3 GWh in Minnesota) and Georgia Power (15 MW / 1.5 GWh). In the Asia-Pacific context, POSCO of South Korea announced a licensing agreement with Form Energy to manufacture iron-air batteries for the Korean and Southeast Asian markets, targeting production start in 2027. The technology's 100-hour discharge capability specifically addresses the multi-day wind lull and monsoon cloud cover scenarios that challenge grid reliability across the region.

Flow Battery Deployments for Industrial and Grid Applications

Vanadium redox flow batteries (VRFBs) have achieved commercial deployment at meaningful scale across the Asia-Pacific region. Dalian Rongke Power's 400 MWh vanadium flow battery in Dalian, China, the world's largest flow battery installation, completed commissioning in 2024 and provides 8-hour discharge to Liaoning's provincial grid. Operational data from 18 months of operation shows 99.4% availability, degradation of less than 0.1% per year, and a round-trip efficiency of 72%.

In Australia, Invinity Energy Systems deployed a 2 MWh VRFB at a remote mining operation in Western Australia, replacing diesel generators for overnight power supply and achieving a payback period of 4.5 years through avoided fuel costs of A$0.38 per kWh. The system's 25-year design life with no capacity degradation gives it a levelized cost advantage over lithium-ion for applications requiring 6 or more hours of daily cycling.

Zinc-bromine flow batteries from Gelion Technologies (Australia) have entered commercial production, targeting the 4 to 12 hour duration market for commercial and industrial customers. Their non-flammable chemistry and ability to operate in ambient temperatures up to 50 degrees Celsius make them well-suited for deployments across tropical Asia-Pacific markets.

What's Not Working

Compressed Air Energy Storage Scale-Up

Compressed air energy storage has struggled to move beyond demonstration projects despite decades of development. Only two large-scale CAES plants operate globally: the Huntorf plant in Germany (1978) and the McIntosh plant in Alabama (1991), both using solution-mined salt caverns. The technology requires specific geological formations (salt caverns, depleted gas reservoirs, or hard-rock caverns) that are not universally available. Advanced adiabatic CAES (A-CAES), which stores and reuses compression heat to improve round-trip efficiency from 42 to 54% (diabatic) to 65 to 70% (adiabatic), has faced engineering challenges at scale. Hydrostor's A-CAES project in Broken Hill, Australia, originally announced in 2021, has experienced repeated delays and cost revisions, with commissioning now expected in 2028. The capital cost for A-CAES remains at $250 to $350 per kWh, significantly above the target of $100 to $150 per kWh needed for broad competitiveness.

Gravity-Based Storage Systems

Gravity storage startups have attracted significant attention and venture capital but have not demonstrated commercial viability. Energy Vault's first commercial gravity storage system, a 100 MWh installation using composite blocks lifted and lowered by cranes, reported a round-trip efficiency of only 55 to 60%, well below the 75 to 80% claimed in investor presentations. The system's complex mechanical components (cranes, winches, and block-handling systems) create maintenance burdens that increase operating costs to $15 to $25 per MWh, undermining the technology's cost advantage over lithium-ion at durations below 12 hours. Gravitricity, which uses mine shafts to raise and lower heavy weights, has completed only a 250 kW demonstrator in Edinburgh and has not secured funding for a full-scale commercial project. The Asia-Pacific region, despite significant mining infrastructure that could theoretically host gravity storage, has seen no commercial deployments.

Hydrogen for Grid-Scale Electricity Storage

Green hydrogen produced via electrolysis and stored for later reconversion to electricity through fuel cells or turbines faces a fundamental efficiency challenge: the electricity-to-hydrogen-to-electricity pathway achieves a round-trip efficiency of only 30 to 40%, meaning 60 to 70% of the input energy is lost. At current green hydrogen production costs of $3.50 to $6.00 per kg in the Asia-Pacific region, the effective cost of stored electricity exceeds $200 per MWh for most configurations. Hydrogen's role in LDES may ultimately be limited to seasonal storage (weeks to months) where no other technology is viable, or to applications where the hydrogen has dual-use value (grid storage plus industrial feedstock). The CSIRO's assessment concluded that hydrogen-to-power is unlikely to be cost-competitive with iron-air batteries or flow batteries for durations of 10 to 200 hours before 2035.

Key Players

Established Companies

• CATL: the world's largest battery manufacturer, developing sodium-ion battery systems targeting the 4 to 8 hour LDES market and investing in condensed-matter battery technology for longer durations
• Sumitomo Electric Industries: a Japanese manufacturer operating vanadium redox flow battery systems across 40 installations in Japan and Australia, with a cumulative 100 MWh deployed capacity
• Siemens Energy: integrating compressed air energy storage and thermal storage systems into grid planning solutions for utilities across Southeast Asia and Oceania
• State Grid Corporation of China: the world's largest utility, operating over 40 GW of pumped hydro storage and commissioning the Dalian vanadium flow battery complex

Startups

• Form Energy: developing 100-hour iron-air battery systems with commercial manufacturing beginning in 2026, and Asia-Pacific expansion through a licensing agreement with POSCO
• Invinity Energy Systems: a UK-listed flow battery manufacturer targeting the Australian and Southeast Asian markets with vanadium redox systems for mining, commercial, and grid applications
• Gelion Technologies: an Australian startup commercializing zinc-bromine flow batteries for the 4 to 12 hour duration segment, with manufacturing in Sydney

Investors

• Breakthrough Energy Ventures: invested $450 million in LDES companies including Form Energy, Antora Energy, and Malta Inc. since 2018
• Temasek Holdings: allocated $1.2 billion for energy storage investments across the Asia-Pacific region, with specific LDES mandates
• Asian Development Bank: financing LDES demonstration projects in India, the Philippines, and Vietnam through concessional loan programs totaling $800 million

KPI Benchmarks by Technology

Metric	Pumped Hydro	Iron-Air Battery	Vanadium Flow Battery	Compressed Air
Duration range (hours)	8-100+	24-100+	4-12	8-48
Round-trip efficiency	75-82%	45-50%	68-75%	42-70%
Energy capacity cost ($/kWh)	$50-100	$6-20 (projected)	$150-300	$100-350
Design life (years)	50-80	20-30	20-25	30-40
Annual degradation	Negligible	0.1-0.5%	<0.1%	Negligible
Construction time (years)	5-10	1-2	0.5-1.5	3-6
Geographic constraints	High	None	None	Moderate

Action Checklist

• Map grid reliability requirements for multi-day low-renewable events using at least 10 years of historical weather data to determine required storage duration
• Evaluate pumped hydro potential at greenfield sites and existing reservoir infrastructure before considering emerging technologies
• Request performance data from iron-air and flow battery vendors for installations operating 12 or more months under comparable climatic conditions
• Model levelized cost of storage (LCOS) across candidate technologies using site-specific electricity costs, utilization rates, and required discharge durations
• Assess grid interconnection capacity and upgrade timelines for large-scale LDES installations (50 MW and above)
• Engage with regulators on capacity market and ancillary services frameworks that appropriately value storage durations exceeding 4 hours
• Develop procurement specifications that distinguish between energy capacity cost ($/kWh) and power capacity cost ($/kW) to avoid misleading comparisons
• Establish pilot project partnerships with LDES vendors offering performance guarantees backed by independent monitoring

FAQ

Q: At what renewable penetration level does LDES become essential for grid reliability? A: Grid modeling studies consistently show that LDES becomes critical at renewable penetration levels above 60 to 70% of annual generation. Below this threshold, a combination of lithium-ion storage (2 to 4 hours), demand response, and flexible gas generation can manage variability. Above 70%, multi-day low-renewable events (3 to 7 consecutive days of low wind and cloud cover) create energy shortfalls that short-duration storage cannot address. In the Asia-Pacific region, Australia's National Electricity Market and India's western grid are approaching these thresholds, making LDES planning decisions urgent for engineers working on 2030 to 2035 infrastructure.

Q: How should engineers compare LDES technologies that have very different round-trip efficiencies? A: Focus on levelized cost of storage (LCOS) rather than round-trip efficiency in isolation. A technology with 50% RTE but $10/kWh energy capacity cost may deliver lower LCOS at 100-hour durations than a technology with 80% RTE and $200/kWh capacity cost. The key metric is the all-in cost of each MWh discharged, which incorporates capital cost, energy input cost (adjusted for RTE), operating costs, and asset lifetime. For durations exceeding 24 hours, energy capacity cost dominates the LCOS calculation, making low-RTE but cheap-capacity technologies (like iron-air) competitive despite their higher energy losses.

Q: What is the realistic timeline for iron-air batteries to reach commercial deployment in the Asia-Pacific region? A: Form Energy's US manufacturing facility is expected to begin production in late 2026, with initial grid-connected deployments in 2027. The POSCO licensing agreement for Asia-Pacific manufacturing targets production in South Korea by late 2027 or early 2028. First commercial installations in the region (likely in South Korea or Australia) are expected in 2028. Large-scale deployments of 500 MWh or more are unlikely before 2029 to 2030, given the need for manufacturing ramp-up, utility procurement cycles, and grid interconnection approvals. Engineers should plan for iron-air availability in the 2029 to 2031 window for project commissioning.

Q: Can existing pumped hydro facilities be upgraded to provide longer-duration storage? A: Yes, in many cases. Reservoir capacity is typically the limiting factor for duration, and operational changes can extend discharge periods. Turbine and generator overhauls to improve efficiency at partial loads can increase energy extraction from existing reservoirs by 8 to 15%. Variable-speed pump-turbine retrofits, which Japan's J-Power has implemented at several facilities, improve both pumping efficiency and grid flexibility. Adding upstream or downstream storage reservoirs (where topography permits) can extend discharge duration from 8 to 12 hours to 24 to 48 hours. The cost of such upgrades typically ranges from 20 to 40% of equivalent new-build capacity.

Sources

• Form Energy. (2025). Iron-Air Battery System: One-Year Operational Performance Report. Somerville, MA: Form Energy.
• LDES Council. (2026). Net-Zero Heat 2026: The Role of Long-Duration Energy Storage in Decarbonized Grids. Geneva: LDES Council.
• International Energy Agency. (2025). Energy Storage Outlook 2025: Technology Pathways to Net Zero. Paris: IEA.
• Australian Energy Market Operator. (2025). 2025 Integrated System Plan: Renewable Energy Curtailment Analysis. Melbourne: AEMO.
• China National Energy Administration. (2025). 14th Five-Year Plan Progress Report: Energy Storage Deployment and Pipeline. Beijing: NEA.
• BloombergNEF. (2026). Long-Duration Energy Storage Market Outlook 2026. London: BNEF.
• CSIRO. (2025). GenCost 2025: Electricity Generation and Storage Cost Projections for Australia. Canberra: CSIRO.