Valuing Diversity in Long-Duration Energy Storage

The energy storage industry finds itself at a critical crossroads, with numbers telling two different stories at once.

On one hand, global long-duration energy storage deployment surpassed 15 GWh in 2025 — a 49% increase over the 10 GWh installed in 2024, according to new research from Wood Mackenzie. On the other hand, overall LDES funding dropped 30% that same year, while venture capital investment cratered by 72%. Deployment is climbing, but capital confidence is retreating. Meanwhile, lithium-ion, excluded entirely from Wood Mackenzie's LDES figures, is quietly eating everyone else's lunch.

That contradiction isn't a paradox — it's a warning sign. The question is whether policymakers and market designers will read it correctly before the window for technology diversity closes.

What "Long-Duration" Actually Means — and Why the Definition Matters

Before dissecting the market, it's worth anchoring the terminology. Long-duration energy storage doesn't have a single universal definition. Depending on the jurisdiction, "long-duration" kicks in at four hours of discharge, six hours, eight hours, or more. Wood Mackenzie's figures exclude lithium-ion entirely, which means the 15 GWh deployment number reflects technologies like compressed air energy storage (CAES), thermal energy storage (TES), flow batteries, iron-air batteries, and similar alternatives.

That definitional ambiguity isn't just academic — it shapes policy, procurement criteria, and ultimately which technologies get funded.

The reason LDES matters at all comes down to grid math. Wood Mackenzie's modeling under net-zero scenarios finds that the average global storage duration needs to scale from roughly 2.5 hours today to nearly 20 hours. Countries pushing past a 50% renewable energy share by 2030 face the sharpest need. Wind and solar don't follow demand curves — they follow weather patterns. Once you cross certain thresholds of renewable penetration, four-hour lithium-ion batteries stop being a solution and start being a band-aid.

The Non-Lithium Contenders — and the Capital Drought They're Facing

Three companies have managed to raise serious money in the non-lithium LDES space: Hydrostor (advanced compressed air energy storage), EOS Energy (zinc hybrid cathode batteries), and Form Energy (iron-air batteries). Each raised more than $1 billion between 2021 and 2025 — a significant milestone in a sector that has historically struggled to attract the institutional capital that flowed so readily to lithium.

But even that achievement comes with an asterisk. Billion-dollar raises sound substantial until you compare them to the capital intensity required to commercialize entirely new electrochemical or mechanical systems at grid scale. These aren't software startups where a well-funded team can iterate to product-market fit in 18 months. Building the first commercial-scale advanced CAES facility or manufacturing iron-air battery cells at volume requires sustained capital over a decade — the kind of long-horizon commitment that VC funds aren't structurally designed to provide.

The 72% collapse in VC funding for LDES in 2025 isn't just a bad year — it may signal that early-stage capital has largely given up waiting for these technologies to become cost-competitive on the current market's terms.

China's dominance further underscores the structural challenge. Chinese projects accounted for 93% of global LDES deployment in 2025 — 14 of the 15 GWh — driven by aggressive government policy support and national grid buildout targets. That level of concentration reflects how much state-directed capital is doing the work that private markets won't.

Why Current Market Design Is Working Against Technology Diversity

Here's the non-obvious angle most coverage misses: the problem isn't that alternative storage technologies are failing on pure technical merit. The problem is that they're competing in markets designed to reward something else.

Energy storage markets, particularly in the U.S. and Europe, have historically valued two things: response time and arbitrage value over short time windows. Lithium-ion excels at both. It dispatches in milliseconds, charges and discharges efficiently, and has benefited from a decade of cost reductions driven by the EV industry. A 4-hour Li-ion BESS in China now costs approximately $107/kWh. The lowest-cost LDES alternatives — thermal energy storage at $190/kWh and compressed air at $201/kWh — don't come close to competing at that price point for short-duration applications.

But when a market only values four hours of storage, you're essentially asking a 20-hour technology to win a 100-meter sprint. Of course, it loses.

Wood Mackenzie's report points to a clearer path: market design reforms that explicitly value longer discharge durations. Capacity markets with duration-differentiated payments, targeted procurement mechanisms, and long-term offtake contracts that reflect the actual system value of multi-day storage — these are the tools that can shift the economics. California, certain Australian states, and the UK have made early moves in this direction. They're the proof-of-concept that policy can make the math work.

The Long Duration Energy Storage Council has been pushing this message directly to governments. Will Broad, the LDES Council's global director of policy, put it plainly at the Energy Storage Summit 2026: policymakers need to stop thinking "just about lithium-ion and pumped hydro" and plan for a variety of technologies across different time horizons. His framing identified three distinct rationales for diversity that deserve to be taken seriously.

Three Arguments for Not Betting Everything on One Technology

Broad's framework for why technology diversity matters is worth unpacking because it goes beyond the usual "don't put all your eggs in one basket" generality.

Duration diversity addresses the temporal mismatch between today's grid needs and tomorrow's. Lithium-ion is the right tool for a grid with 30% renewables. It may be the wrong tool — or at least an insufficient one — for a grid at 70% renewables, where multi-day storage becomes critical for managing extended low-generation weather events. Locking in a single-technology procurement strategy today could mean costly retrofitting or capacity shortfalls within a decade.

Innovation deployment makes the case that cost reductions in emerging technologies require scale, and scale requires deployment, and deployment requires policy support. The LDES Council, in a joint report with EPRI, projects that long-duration storage costs could fall by approximately 37% by 2030 — but only if manufacturing scales and technology matures through real-world deployment. That learning curve doesn't activate by waiting for the technology to become competitive on its own.

Supply chain diversity is the argument that resonates most viscerally in today's geopolitical environment. Lithium-ion battery supply chains run overwhelmingly through China — from lithium mining to cell manufacturing to module assembly. The risk isn't hypothetical anymore. A diversified technology portfolio means some storage assets drawing on iron, compressed air, or thermal mass — resources that don't depend on a single country's export policy.

The Path Forward — If Markets Cooperate

The cost gap between lithium-ion and LDES alternatives is real and won't close on goodwill alone. But framing it purely as a competitiveness problem obscures what's actually at stake: grid systems optimized entirely around today's cheapest technology won't be optimized for the grid that needs to exist in 2035.

The LDES Council's cost reduction projections — that 37% decline by 2030 under the right conditions — suggest these technologies are not permanently uncompetitive. They're pre-scale. There's a meaningful difference. The same lithium-ion batteries that now cost $107/kWh in China were nowhere near that price in 2015. Scale and policy created that cost curve.

The real risk isn't that long-duration energy storage technologies fail. It's that they never get the sustained procurement signal needed to find out whether they can succeed.

Governments serious about deep decarbonization need to treat energy storage procurement less like a commodity purchase and more like infrastructure planning — with time horizons that match the grid's actual needs. Duration-differentiated capacity markets are a start. Long-term contracts that price in the avoided cost of curtailment, transmission upgrades, or fossil fuel backup capacity would be even more powerful.

The deployment numbers are moving in the right direction. The funding numbers are moving in the wrong one. Correcting that divergence — before the window closes on a generation of LDES companies — is exactly the kind of structural challenge that markets alone won't solve.

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