Ore Energy Lines Up 1 GWh of Iron-Air Storage for European Grids as Curtailment Costs Hit €8.9bn
Dutch utility Budget Thuis is the first named European buyer, with a 400-MWh initial phase that uses no lithium or cobalt.
Ore Energy agreed in late June 2026 to deploy 1 GWh of iron-air battery capacity across Europe, with Dutch utility Budget Thuis as its first named buyer and a 400-MWh first phase already committed. The deal landed within days of Ofgem confirming support for 16 long-duration energy storage projects in the UK on June 30 (2026), a decision that followed a legal challenge from Zenobe and underlined rising regulatory appetite for multi-day storage on both sides of the Channel.3,4
The scale of the problem those systems are meant to solve has grown sharper over the past two years. Aurora Energy Research calculated that European grids curtailed roughly 72 TWh of electricity in 2024, predominantly renewables, at a cost of around €8.9 billion. The European Commission's Joint Research Centre projects that figure could reach 310 TWh annually by 2040 if grid investment does not keep pace with renewable build-out — equivalent to roughly half the EU's entire wind and solar output in 2022.3
Iron-air chemistry addresses a specific gap that lithium-ion cannot fill economically: storage durations between 24 and 100 hours. The technology works by oxidising iron with air during discharge and reducing it during charging, requiring no lithium or cobalt. Aytaç Yilmaz, Ore Energy's co-founder and chief executive, said European grids were already "wasting electricity that costs billions," framing the deployment as a way to absorb oversupply during low-demand periods and release it during peak stress events.4,3
The economic case for long-duration storage in Germany has drawn academic attention. Scenario modelling by TU Berlin using the PyPSA-Eur framework found that a zero-carbon German power system with iron-air storage deployed at scale could require around 32% less wind and solar capacity, with curtailment reduced substantially. German baseload power settled at €98.38 per MWh as of Friday's close (2026-07-04) and ICE Endex TTF front-month gas at €45.33 per MWh — levels at which storage dispatch economics sit in a competitive range with gas peaking plant.3
Budget Thuis chief executive Annemarie Buitelaar described multi-day storage as "a way to store clean electricity when it is abundant and deliver it when it is most valuable," a framing that points to seasonal arbitrage rather than pure frequency regulation. Iron-air systems charging during summer curtailment peaks and discharging into winter demand events would represent a different revenue model from the sub-daily cycle economics governing most existing storage assets.3
EDF separately described electrification as "imperative" for France on May 20 (2026-05-20), announcing plans to grow power demand by 5.5 TWh, or around 1 percent annually, through new industrial connections, heat pumps and electric trucks. That demand-growth assumption rests on a disputed generation outlook: the European Commission launched an investigation on May 19 (2026-05-19) into France's €73 billion plan to subsidise construction of six new nuclear reactors with a combined 10 GW capacity, leaving the country's long-term baseload mix in regulatory limbo.2,1
Whether Ore Energy's 1 GWh commitment translates into contracted revenue at multi-day discharge durations depends heavily on market design. The company cited two prior grid-connected deployments as evidence of commercial readiness, but European capacity market frameworks that reward 24-to-100-hour discharge remain fragmented across national regimes. The UK's move to support 16 LDES projects after Zenobe's legal challenge suggests regulators can find pathways. EU equivalents are still forming.4
If the European Commission's French nuclear investigation delays Paris's reactor programme beyond EDF's planned timeline, demand for multi-day storage in the French grid expands by default. Germany's own zero-carbon transition arithmetic points the same direction. The Commission's 310 TWh curtailment projection gives developers a cost ceiling against which to price long-duration contracts — provided national procurement rules evolve quickly enough to capture it.3,1