Long-Duration Energy Storage (LDES) KPIs by Sector
Essential KPIs for long-duration storage evaluation, with 2024-2025 benchmark ranges for cost, efficiency, and grid application performance across technologies.
As electricity grids approach 80%+ renewable penetration, multi-day and seasonal storage becomes essential. Lithium-ion batteries address 4-hour needs efficiently but become uneconomic for longer durations. Long-duration energy storage (LDES)—technologies capable of storing energy for 10+ hours to multiple days—is the missing piece. The LDES Council estimates 85-140 TWh of storage capacity will be needed by 2040. This benchmark deck provides the KPIs that matter for LDES evaluation, with ranges drawn from 2024-2025 technology development and early deployments.
The Duration Gap
Current grid storage is dominated by lithium-ion, which excels at 2-4 hour applications but costs scale linearly with duration. At 12+ hours, lithium-ion capital costs ($150-250/kWh × hours) become prohibitive compared to LDES technologies where energy capacity costs are decoupled from power capacity.
The need is acute: as renewable penetration increases, multi-day weather events (wind droughts, extended cloud cover) create reliability gaps that short-duration storage cannot address. California's 2020 rolling blackouts and UK's 2021 "wind drought" demonstrated vulnerability.
LDES technologies fall into several categories: mechanical (pumped hydro, compressed air, gravity), electrochemical (flow batteries, iron-air), thermal (molten salt, cryogenic), and chemical (hydrogen). Each has different cost structures, efficiencies, and application fits.
The 8 KPIs That Matter
1. Levelized Cost of Storage (LCOS)
Definition: All-in cost of storing and delivering electricity per MWh, including capital, operations, and efficiency losses.
| Technology | 8-Hour LCOS | 24-Hour LCOS | 100-Hour LCOS |
|---|---|---|---|
| Lithium-Ion | $120-180/MWh | $300-450/MWh | Not viable |
| Pumped Hydro | $100-160/MWh | $80-140/MWh | $60-100/MWh |
| Compressed Air | $110-180/MWh | $90-150/MWh | $70-120/MWh |
| Flow Battery (Vanadium) | $150-220/MWh | $100-160/MWh | $80-130/MWh |
| Iron-Air | $140-200/MWh | $80-120/MWh | $50-90/MWh |
| Thermal (Molten Salt) | $130-200/MWh | $90-140/MWh | $70-110/MWh |
| Hydrogen (Round-trip) | $300-500/MWh | $250-400/MWh | $180-300/MWh |
Duration advantage: LDES technologies show flatter cost curves with increasing duration. Iron-air and pumped hydro become most economic at 100+ hour durations.
2. Round-Trip Efficiency
Definition: Percentage of stored energy recovered when discharged.
| Technology | Efficiency Range | Key Loss Mechanisms |
|---|---|---|
| Lithium-Ion | 85-92% | Conversion, thermal |
| Pumped Hydro | 75-85% | Hydraulic, evaporation |
| Compressed Air (Diabatic) | 40-55% | Heat loss |
| Compressed Air (Adiabatic) | 65-75% | Thermal storage losses |
| Flow Battery (Vanadium) | 65-75% | Pump, crossover |
| Iron-Air | 45-55% | Electrochemical |
| Thermal (Molten Salt) | 60-70% | Heat loss, conversion |
| Liquid Air (Cryogenic) | 50-60% | Liquefaction losses |
| Hydrogen | 30-45% | Electrolysis + fuel cell |
Efficiency vs. cost tradeoff: Lower-efficiency technologies (iron-air, hydrogen) can still win on LCOS if capital costs are sufficiently low and duration is long.
3. Capital Cost Structure
Definition: Breakdown of system cost between power capacity ($/kW) and energy capacity ($/kWh).
| Technology | Power Cost ($/kW) | Energy Cost ($/kWh) | Crossover Duration |
|---|---|---|---|
| Lithium-Ion | $150-250 | $150-250 | N/A (linear) |
| Pumped Hydro | $1,500-3,000 | $5-20 | 6-10 hours |
| Compressed Air | $800-1,500 | $10-30 | 8-12 hours |
| Flow Battery | $600-1,200 | $80-150 | 8-12 hours |
| Iron-Air | $400-800 | $20-50 | 6-10 hours |
| Thermal | $500-1,000 | $30-60 | 8-12 hours |
Why LDES economics differ: High power cost but low energy cost means LDES technologies become cheaper than lithium-ion at longer durations. The "crossover" point varies by technology.
4. Degradation and Lifespan
Definition: Annual capacity loss and total cycle/calendar life.
| Technology | Annual Degradation | Cycle Life | Calendar Life |
|---|---|---|---|
| Lithium-Ion | 2-4%/year | 3,000-5,000 | 10-15 years |
| Pumped Hydro | 0-0.1%/year | Unlimited | 40-60+ years |
| Compressed Air | 0-0.2%/year | Unlimited | 30-50 years |
| Flow Battery | 0.5-1%/year | 10,000-20,000 | 20-25 years |
| Iron-Air | 1-2%/year (est.) | 6,000-10,000 | 20-25 years |
| Thermal | 0.5-1%/year | 8,000-15,000 | 25-30 years |
Asset life advantage: LDES technologies generally offer longer operational lives than lithium-ion, improving lifetime economics despite higher initial costs.
5. Deployment Status
Definition: Technology readiness and installed capacity.
| Technology | TRL | Global Installed | 2030 Pipeline |
|---|---|---|---|
| Pumped Hydro | 9 (Commercial) | 180 GW | 50+ GW |
| Lithium-Ion (>4h) | 9 (Commercial) | 15 GW | 100+ GW |
| Compressed Air | 8-9 (Commercial) | 1.5 GW | 10+ GW |
| Flow Battery | 8 (Commercial) | 1 GW | 15+ GW |
| Iron-Air | 7-8 (Demo/Early) | <0.1 GW | 5+ GW |
| Liquid Air | 7-8 (Demo) | <0.1 GW | 2+ GW |
| Gravity | 6-7 (Pilot) | <0.01 GW | 1+ GW |
| Thermal | 7-8 (Demo/Early) | <0.5 GW | 5+ GW |
Pumped hydro dominance: 95%+ of grid storage remains pumped hydro. But geographic/environmental constraints limit new sites. Emerging technologies target applications where pumped hydro isn't feasible.
6. Response Time and Services
Definition: Speed and flexibility of storage dispatch for different grid services.
| Service | Response Required | Suitable LDES Technologies |
|---|---|---|
| Frequency Regulation | <1 second | Flow batteries, some thermal |
| Spinning Reserve | <10 minutes | Most LDES |
| Peak Shaving | 15-30 minutes | All LDES |
| Energy Arbitrage | Hours | All LDES |
| Capacity/Reliability | Hours-days | All LDES |
| Seasonal Storage | Weeks-months | Hydrogen, thermal, CAES |
Service stacking: LDES value improves when systems can provide multiple services. Flow batteries and some thermal systems can stack fast-response with long-duration services.
7. Siting Flexibility
Definition: Geographic and environmental constraints on deployment.
| Technology | Siting Constraint | Footprint | Environmental Factors |
|---|---|---|---|
| Pumped Hydro | Terrain, water access | Large | Ecological, permitting |
| Compressed Air (Cavern) | Geology (salt/rock) | Medium | Limited |
| Compressed Air (Surface) | Limited | Medium-Large | Limited |
| Flow Battery | Limited | Medium | Chemical handling |
| Iron-Air | Limited | Small-Medium | Minimal |
| Thermal | Limited | Medium | Minimal |
| Gravity (Tower) | Limited | Small footprint | Visual |
| Gravity (Shaft) | Geology | Small footprint | Limited |
New technology advantage: Emerging LDES technologies (iron-air, flow batteries, thermal) have minimal siting constraints compared to pumped hydro and cavern CAES, enabling broader deployment.
8. Revenue Stacking Potential
Definition: Ability to capture value from multiple grid services.
| Revenue Stream | Value ($/kW-year) | Duration Sensitivity |
|---|---|---|
| Capacity Payment | $50-150 | Increases with duration |
| Energy Arbitrage | $30-100 | Increases with duration |
| Ancillary Services | $20-80 | Less duration-dependent |
| Transmission Deferral | $20-100 | Duration and location |
| Renewable Integration | $15-50 | Increases with duration |
| Resource Adequacy | $50-200 | Increases with duration |
Total revenue potential: LDES projects targeting multiple revenue streams can achieve $150-400/kW-year, supporting economic viability despite technology immaturity.
What's Working in 2024-2025
Iron-Air Battery Commercialization
Form Energy's iron-air batteries are moving from demonstration to commercial deployment. The technology uses iron (rust) chemistry—abundant, low-cost materials—to achieve 100-hour storage at projected costs of $20/kWh for energy capacity.
First utility deployments (Great River Energy, Xcel Energy) are operational in 2024-2025. If commercial performance matches demonstrations, iron-air could become dominant LDES technology for multi-day applications.
Pumped Hydro Innovation
While conventional pumped hydro faces siting limits, new approaches are expanding possibilities. Underground/abandoned mine pumped hydro, seawater pumped hydro, and modular small-scale systems open new sites. Australia's Snowy 2.0 (2 GW) and multiple European projects demonstrate continued investment.
Flow Battery Cost Reduction
Vanadium flow batteries have achieved commercial scale (100+ MWh installations). Cost reductions from manufacturing scale and alternative chemistries (iron, zinc-bromine) are improving economics. Invinity, ESS Inc., and others are delivering utility-scale projects at $250-350/kWh installed cost.
What Isn't Working
Hydrogen Round-Trip Economics
Hydrogen storage (electrolysis → storage → fuel cell) suffers from 30-45% round-trip efficiency. This means each MWh stored requires 2.2-3.3 MWh of input electricity. For grid balancing applications, this inefficiency makes hydrogen uneconomic except for very long durations (seasonal) where alternatives don't exist.
Gravity Storage Scaling
Several startups proposed gravity-based storage (lifting heavy weights). While physically sound, achieving competitive costs has proven challenging. Most gravity storage companies have pivoted, failed, or remain at pilot scale. The approach may work in specific contexts (abandoned mines) but isn't a general solution.
Regulatory/Market Barriers
Most electricity markets weren't designed for long-duration storage. Capacity payments often don't fully compensate duration value. Interconnection queues delay projects 3-5+ years. Planning processes don't adequately model multi-day storage needs. Policy reform is needed to unlock LDES deployment.
Key Players
Established Leaders
- Tesla — Market leader in lithium-ion grid storage with 31.4 GWh deployed in 2024 (113% growth YoY). Shanghai Megafactory adds 40 GWh annual capacity. Megapack units provide 3.9 MWh modular storage with 20-year warranty.
- BYD — Global battery manufacturer with MC Cube-T system for grid storage. Secured 15.1 GWh Saudi Arabia deal (June 2025), the largest single storage project globally. Leverages LFP Blade Battery technology from EV business.
- Fluence — Joint venture between Siemens and AES, specializing in grid-scale battery storage systems. Major deployments across North America, Europe, and Asia-Pacific. Industry leader in software-defined storage optimization.
- Sumitomo Electric — Major redox flow battery manufacturer with wide regional presence. Pioneer in vanadium flow technology for utility-scale applications with 20+ year system life.
Emerging Startups
- Form Energy — Iron-air battery pioneer with $1.2B+ raised (including $405M Series F in October 2024). Developing 100-hour storage at target cost of $20/kWh. First commercial deployments in Minnesota (Great River Energy) and Maine (85 MW—largest battery globally). West Virginia gigafactory under construction.
- EnerVenue — Nickel-hydrogen batteries adapted from NASA space technology. Raised $125M+ through Series B (2024). Offers decades-long lifespan with minimal degradation.
- Antora Energy — Thermal storage using carbon blocks heated to 2,400°C. Raised $200M Series B backed by BlackRock. Uses thermophotovoltaic conversion for electricity output.
- Fourth Power — MIT/Georgia Tech spinout developing liquid tin thermal storage. Raised $39M Series A+ (September 2024). Claims 10x cheaper than lithium-ion for 5-100+ hour durations.
- ESS Inc. — Iron flow battery manufacturer with commercial deployments. 75 kW/500 kWh system for Burbank Water & Power (May 2024). Long-duration, non-flammable, and uses abundant materials.
Key Investors & Funders
- Breakthrough Energy Ventures — Bill Gates' climate fund backing Form Energy, Fourth Power, and Antora Energy.
- GE Vernova & T. Rowe Price — Co-led Form Energy's $405M Series F round.
- BlackRock — Major investor in Antora Energy's thermal storage technology.
- US Department of Energy — $349M LDES demonstrations program plus $147M to Form Energy for Maine project. Additional $100M pilot program supporting emerging technologies.
- NYSERDA — $5M+ for LDES innovation targeting 10-100+ hour systems in New York.
Examples
Form Energy (Iron-Air): 100-hour iron-air battery technology. First commercial deployment: 15 MW/1.5 GWh with Great River Energy (Minnesota). Technology: reversible rusting of iron pellets. Target cost: $20/kWh energy capacity. Status: commercial deployment 2024-2025.
Hydrostor (A-CAES): Advanced compressed air energy storage using purpose-built underground caverns. Goderich Project (Canada): 1.75 MW demonstration operational since 2019. Rosamond Project (California): 500 MW under development. Technology: stores air in underground caverns with thermal storage for adiabatic operation (70% efficiency).
Highview Power (Liquid Air): Cryogenic energy storage using liquefied air. Pilsworth plant (UK): 5 MW/15 MWh operational. Carrington (UK): 50 MW/250 MWh under construction. Technology: liquefies air at -196°C, stores in insulated tanks, expands through turbine. Round-trip efficiency: 50-60%.
Action Checklist
- Assess grid needs beyond 4-hour duration for reliability and renewable integration
- Model LCOS for target applications across technology options
- Evaluate siting feasibility for different LDES technologies
- Identify revenue stacking opportunities in your market
- Engage with LDES developers on project pipeline and timelines
- Monitor iron-air and flow battery commercial deployment results
- Advocate for market rules that compensate long-duration storage value
- Consider hybrid approaches (lithium-ion for short, LDES for long)
FAQ
Q: When will LDES be cost-competitive with peaking gas plants? A: For 8-12 hour applications, LDES is approaching competitiveness now ($150-200/MWh vs. peaker costs of $150-250/MWh in many markets). For 24+ hour applications, LDES targets $100/MWh LCOS by 2030, competitive with gas at meaningful carbon prices. The timeline depends on technology maturation and gas/carbon prices.
Q: How do I choose between LDES technologies? A: Key factors: (1) Duration need—iron-air and thermal favor 24-100+ hours; flow batteries 8-24 hours; (2) Response time—flow batteries provide fast response; mechanical systems are slower; (3) Siting—pumped hydro needs terrain; cavern CAES needs geology; others are flexible; (4) Technology risk—pumped hydro is proven; iron-air is early commercial; gravity remains speculative.
Q: Should I wait for LDES technology to mature? A: For 2025-2027 projects, proven technologies (pumped hydro, flow batteries, CAES) are deployable now. For 2028+ projects, iron-air and advanced thermal may offer better economics. Planning should incorporate technology evolution—don't lock into suboptimal solutions, but don't delay necessary projects waiting for perfect technology.
Q: How do I model LDES value in planning? A: Standard capacity expansion models often undervalue LDES because they don't capture multi-day reliability events. Use models with weather-year variability (not just average conditions), reliability-focused capacity metrics, and multiple revenue streams. The LDES Council provides modeling frameworks.
Sources
- Long Duration Energy Storage Council (LDES Council), "Net-Zero Power: LDES to Enable the Energy Transition," 2024 Update
- BloombergNEF, "Long-Duration Energy Storage Outlook," October 2024
- US DOE, "Long Duration Storage Shot: Progress Report," 2024
- Form Energy, "Iron-Air Technology Overview and Project Updates," 2024
- Lazard, "Levelized Cost of Storage Analysis," Version 8.0, 2024
- Wood Mackenzie, "Global Energy Storage Market Tracker," Q4 2024
- EPRI, "Long-Duration Energy Storage Technology Assessment," 2024
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