IN Brief:
- Eurelectric and AFRY have identified stronger commercial potential for long-duration energy storage across several European markets.
- The analysis points to lower curtailment, reduced congestion, system cost savings, and greater flexibility as renewable penetration rises.
- Market design, revenue visibility, and high upfront cost remain central barriers to wider deployment.
Eurelectric has placed long-duration energy storage more firmly inside Europe’s grid flexibility debate, with new analysis suggesting that emerging LDES technologies are moving towards commercial viability in several European power markets.
Developed with AFRY, the analysis assesses storage technologies capable of shifting electricity over periods beyond conventional short-cycle battery operation. It identifies potential annual variable operating cost savings of €150m to €250m for each gigawatt of LDES deployed at system level, driven by reduced renewable curtailment, lower congestion, and improved security of supply.
As wind and solar account for a growing share of electricity supply, the value of storage is increasingly being measured against its ability to manage longer mismatches between generation and demand. Periods of high renewable output can create surplus electricity and grid congestion, while low-output periods can coincide with winter peaks, industrial load, or tight system margins.
Technologies highlighted in the analysis include iron-air batteries, compressed air energy storage, and liquid air energy storage, alongside Europe’s existing pumped-storage hydropower base. Pumped hydro remains the dominant long-duration flexibility resource across Europe, although geography, permitting, civil works, and construction times limit how widely it can be expanded.
Regional differences are central to the investment case. Wind-heavy systems such as Germany and Great Britain show stronger potential for storage durations above 24 hours later in the investment cycle, while Spain and Portugal present stronger prospects for storage in the eight-to-12-hour range. Storage value depends on the shape of renewable output, local congestion, price spreads, capacity adequacy, and whether electricity markets reward avoided system costs.
That creates a more complex case than the one that supported early grid-scale lithium-ion deployment. Shorter-duration battery projects have often relied on ancillary services, trading, balancing, and capacity market revenues. LDES needs a broader value stack that reflects its ability to capture surplus renewable generation, reduce congestion, support resilience through low-output periods, and provide firmness in systems with less synchronous generation.
European policy discussions are already moving in that direction, with long-duration storage increasingly framed as strategic infrastructure rather than an optional supplement to renewables deployment. That framing places storage closer to transmission planning, capacity adequacy, and industrial resilience.
Grid congestion strengthens the case for longer-duration storage in specific locations. Northern Germany’s wind resource and southern demand centres provide one example, with renewable generation often constrained by the ability to move power across the system. Storage cannot replace transmission reinforcement, but it can absorb energy during congested periods and return it when network conditions and demand change.
The industrial supply chain could also broaden if LDES deployment scales. These technologies draw on pressure vessels, turbomachinery, heat exchangers, electrolyte systems, power conversion, controls, civil works, and long-life maintenance models. Europe’s storage sector would become less dependent on a single battery chemistry and more closely tied to wider engineering capability.
Electrification is adding urgency to the question. Heating, transport, data infrastructure, hydrogen production, and industrial loads are all increasing demand while power systems become more weather-dependent. A reliable low-carbon grid will need flexibility across seconds, minutes, hours, days, and potentially seasons.
Market design will determine how much of that flexibility is built. Capacity mechanisms, cap-and-floor models, long-term flexibility tenders, congestion management, and locational signals are all likely to shape deployment. Europe’s storage debate is moving from whether to build more batteries towards how much duration the electricity system needs, where it should sit, and how its system value can be made investable.
