A battery can both consume and supply electricity, often within the same hour. Across much of Europe, however, regulators insist on assigning it one identity for paperwork and a different one for billing. This has created a project class that has multiplied its installed base tenfold since 2021, reaching 77.3 GWh by 2023, but now faces long queues, double taxation on the same electron, and permitting offices that treat it as two separate buildings sharing a fence.
The target is 750 GWh by 2030. The gap is not primarily a technology or capital problem; it is a filing problem.
The Category Error at the Center
The European Union’s Clean Energy Package of 2019 attempted to address this. Directive (EU) 2019/944 introduced definitions for “energy storage facility” and “active customer,” a legislative step toward recognizing that a battery is neither a power plant nor a factory line. Brussels wrote the opening sentence, but left the rest of the chapter to national capitals. Most Member States have not implemented it well.
In practice, a grid-scale battery draws from the network and is metered as load. It injects and is invoiced as generation. It needs an environmental permit for one function, a separate operational permit for the other, and sometimes two different authorities who do not share a waiting room. Developers in Spain and Italy have reported permitting timelines of three to five years. This is not because anyone objects to the project, but because the bureaucracy is designed for assets that perform only one function. A battery that arbitrages price spikes, provides frequency response, and soaks up midday solar surplus does not fit that architecture, so it waits.
The financial damage is more precise. Network tariffs, levies, and taxes hit the battery on import and again on export. Germany’s EEG surcharge and electricity tax have historically applied to power drawn for storage, though partial exemptions now exist for co-located renewable projects. Eurelectric flagged the pattern as early as 2021: in multiple EU countries, the same unit of energy pays twice to move through the same wires. This is not an abstract market distortion; it directly subtracts from project returns, enough to kill margins on assets that already face volatile revenue streams.
Queues That Punish the Cure
Grid connection queues compound the injury. Batteries are built to relieve congestion, absorbing oversupply when the wind blows hard and discharging when the system tightens. Connection rules in most European markets do not recognize this function. A storage project applies for grid access and is sorted into the same queue as a new gas plant or a steelworks expansion, behind whatever preceded it in the stack. In Ireland, EirGrid’s backlog meant multi-year waits for new projects by 2022. The battery that could have solved the constraint joins the line of projects creating it.
This is the paradox the headline catches. The grid needs flexibility, but the rules treat flexibility as an administrative anomaly, a hybrid to be processed twice rather than a resource to be accelerated. Poorly designed frameworks do not merely slow storage deployment; they actively reorder the queue so that batteries sit behind generation or load that will worsen the very congestion they were designed to relieve.
What 750 GWh Requires
The arithmetic is unforgiving. Europe needs to multiply its 2023 battery base nearly tenfold again in seven years. At current permitting velocity, that is not a stretch target; it is a fiction.
The cost of missing it is not just a missed climate target, although the European Commission’s 55 percent net emissions reduction by 2030 depends heavily on integrating variable renewables. The cost is curtailment: wind and solar farms switched off during high-output periods because no asset exists to store the surplus. The International Energy Agency estimated global renewable curtailment cost billions in lost revenue in 2022 alone. The cost is also continued reliance on gas peakers for frequency control, which keeps import demand alive and emissions higher than planned. It also affects competitive positioning: capital in battery manufacturing and project development is globally mobile, and regions with clearer rules attract more of it.
Where the Rules Are Being Rewritten
Not every European market is paralyzed. The United Kingdom, no longer bound by EU directive timetables, moved earlier and more decisively. Ofgem and National Grid ESO introduced “Modified Gate Closure” in 2020 to accelerate storage connections. They also built specific revenue streams, Enhanced Frequency Response in 2016 and Dynamic Containment in 2020, that price fast-response flexibility as a distinct service rather than an afterthought. The UK also largely eliminated double charging on network fees for storage. The investment case became legible, and deployment followed.
Germany has chipped away at its own double-charging problem. The 2021 revision of the Renewable Energy Sources Act granted exemptions from the EEG surcharge for storage charging when directly linked to renewable generation. The exemption is partial and conditional, not the clean carve-out developers wanted, but it acknowledges the principle that a battery serving the transition should not be taxed as if it were a conventional load.
Spain streamlined permitting for renewable-plus-storage projects through Royal Decree-Law 23/2020, though standalone storage still faces the older, slower pathways. France has set a 5.3 GW storage target for 2030 under its Multiannual Energy Programme and opened market mechanisms through RTE that storage can access. The direction is correct, but the pace is not.
The Comparison That Stings
Outside Europe, the contrast sharpens. In the United States, FERC Order 841 of 2018 required regional grid operators to remove barriers to storage participation in wholesale markets, enabling batteries to bid into energy, ancillary services, and capacity markets on the basis of technical capability rather than historical category. Order 2023, issued in 2023, targets interconnection queue reform specifically. At state level, California’s 1.325 GW storage mandate, set in 2013 and since exceeded, created demand certainty that pulled supply chain and developer capacity toward the market. New York is targeting 6 GW by 2030.
China’s approach is less replicable and less market-driven, but no less instructive. The National Development and Reform Commission and National Energy Administration set a 30 GW new energy storage target for 2025 and mandated co-location requirements, typically 10 to 20 percent of renewable capacity for two to four hours, on new wind and solar projects. The mechanism is administrative directive, not competitive market design. The result is rapid, centrally coordinated deployment that Europe’s fragmented governance cannot directly emulate but should measure itself against.
The Strategic Question
Europe’s battery expansion is not failing for lack of ambition or invention. The tenfold growth since 2021 proves the technology works and capital will flow where the path is clear. The blockage is regulatory design that predates the asset it is being asked to process, staffed by institutions that still want a battery to pick a single identity and stick to it.
The fix is known: a distinct legal category for storage, single-window permitting, elimination of double charging, and grid connection queues that prioritize flexibility assets by their system value, not their filing date behind a gas plant. The question is whether national governments, or a revised EU framework with sharper implementation teeth, can deliver these changes before the 2030 target becomes a retrospective explanation of what went wrong.
A battery is not a load or a generator; it is a buffer in a system that will increasingly depend on buffering. The rules need to say so, clearly and once, or the grid Europe is building will remain the grid that holds it back.
