Grid fees for battery storage: the exemption until 2029 and the AgNeS reform

Few cost items are set to zero as routinely in storage business cases as grid fees, the charges for using the electricity network. The reason sits in Section 118(6) of the German Energy Industry Act (EnWG): battery storage systems are exempt from fees on the electricity they draw for charging for 20 years. That very rule is being rewritten. On 6 August 2026, the Federal Network Agency (Bundesnetzagentur) published the final draft of its grid fee reform AgNeS, and with it the conditions under which current and new projects keep the exemption.

This article explains what grid fees are, how the exemption works, what the reform changes and which deadlines now matter; it closes with what investors in a storage direct investment should look for.

What are grid fees, and why do they affect battery storage?

Grid fees are the charges for transporting and distributing electricity; they finance the construction and operation of the power grids and make up a substantial share of the electricity price for end consumers. A battery storage system would be hit twice: when charging, it draws electricity from the grid like a consumer; when discharging, it feeds it back in. Without a special rule, the same electricity would be burdened with network costs twice on its way through the storage system, even though the storage system does not consume it but merely shifts it through time.

How large the item would be depends on the grid level and the fee model; without the exemption, charging power would carry a burden of several cents per kilowatt-hour depending on the connection situation. For a grid-scale system running one to two full charge-discharge cycles a day, that would be a cost block that visibly squeezes the trading margin between cheap and expensive hours. The exemption is therefore one of the most important economic foundations of the current project generation; how a storage system earns money in the first place is explained in How does a grid-scale battery storage system work? Design, operation and revenue logic explained.

How does the grid fee exemption under Section 118(6) EnWG work?

Section 118(6) EnWG exempts electricity storage systems from grid fees on the electricity they draw for storage for 20 years from commissioning; under current law, the condition is commissioning by 4 August 2029. The exemption is not open-ended but works as an asset-specific window: whoever starts operating in time takes the exemption along for two decades.

The deadline has already been extended once, by three years; originally it would have expired in August 2026. Two details of the provision matter for context. First, the exemption covers the recurring fees on charging power, not the one-off costs of the grid connection. Second, sentence 12 of the provision contains an opening clause allowing the Federal Network Agency to deviate from the rule, including its temporal scope. It is precisely this power the agency is now using with the AgNeS reform.

What is the AgNeS reform of the Federal Network Agency?

AgNeS stands for the general grid fee system for electricity, the framework with which the Federal Network Agency is fundamentally reorganising grid fees; the determination proceeding has been running since May 2025. After orientation points on storage grid fees in January 2026 and a background paper in May, the agency published the final draft determination on 6 August 2026. Comments can be submitted until 18 September 2026; the decision is still planned for 2026.

For storage, the direction is clear: the blanket full exemption is being phased out and will not be extended to 2045; storage systems are to contribute to network costs going forward because they use the grid. Part of the background is a 2021 ruling of the European Court of Justice that calls blanket statutory fee exemptions into question. From 1 January 2029, the draft provides for a moderate capacity-based grid fee for storage without grandfathered status. As the long-term target, the agency names dynamic grid fees that vary by time and region and reward grid-friendly behaviour with the correct sign: whoever charges when the grid needs to shed surplus electricity relieves it and should not pay like an ordinary consumer for doing so.

Which projects keep the 20-year exemption?

Under the final draft determination, all projects keep the full 20-year grid fee exemption if they made their final investment decision (FID) before publication of the final AgNeS determination and are commissioned by 4 August 2029. Exemptions already running under Section 118(6) EnWG are explicitly left untouched.

The final investment decision is not a soft term here: the draft requires binding orders covering at least 50 percent of the investment volume, from which the project could not withdraw without substantial financial damage. Proof must be provided to the grid operator in suitable form by 31 March 2027. An additional hurdle discussed earlier, a binding grid connection commitment, was dropped in the final draft; projects still waiting for that commitment in the grid operators' connection process can therefore still reach grandfathered status.

In practice, the decisive deadline thus moves forward: the cut-off is not August 2029 but the publication of the final determination, expected around the turn of 2026/27. The effective window for new projects with the full exemption is considerably shorter than the year 2029 suggests; how this deadline sits next to the tax deadlines of the asset class is laid out in Forming the IAB now: which tax deadlines and time windows count in 2026/2027.

What is the grid connection charge, and what did the Federal Court of Justice decide?

The grid connection charge (Baukostenzuschuss, BKZ) is a one-off payment to the grid operator for providing connection capacity; it is distinct from the recurring grid fees and is not covered by the exemption under Section 118(6) EnWG. In July 2025, the Federal Court of Justice ruled (decision of 15 July 2025, EnVR 1/24) that distribution grid operators may demand such a charge, calculated under the so-called capacity price model, from battery storage systems connected at medium and high voltage as well; whether they levy it is at their discretion.

For projects, this means the connection charge is a real line in the investment budget that can be substantial depending on the grid operator, the grid level and the requested capacity; the higher the connection capacity, the more expensive the connection. In a serious calculation it appears as a stated item, not hidden in a lump sum. How projects share a grid connection and thereby optimise connection costs is covered in Co-located vs. stand-alone: which gives the better risk structure.

What does this mean for the revenues of a battery storage system?

For a storage system with secured grandfathered status, nothing changes for now: the grid fee exemption applies per asset for 20 years from commissioning and thus covers most of the usual analysis horizons. The revenue side of such a project is driven by the power markets, not by the reform; how day-ahead, intraday and balancing markets interact is explained in Direct marketing explained: day-ahead, intraday and balancing power.

For projects without grandfathered status, the new system applies from 2029. How strongly a moderate capacity-based fee changes the economics depends on its level, which the draft does not yet quantify; the only serious approach is therefore a conservative model that includes a grid fee assumption for the years after 2029 instead of silently extending today's full exemption. Dynamic fees could over time even become an additional opportunity for flexible assets if grid-friendly charging is rewarded; that cannot be reliably quantified today. Which return ranges all of this feeds into is shown in Battery storage returns: where the revenue comes from, and what is realistic.

What does this mean for investors in a storage direct investment?

For investors, the reform is above all a checklist: whether a specific project keeps the 20-year exemption is decided by documentable facts, not declarations of intent. The revenue assumptions in the project documents stand or fall with this status. Four questions therefore belong in front of any provider:

• When was the final investment decision made, and can it be proven to the grid operator (binding orders covering at least 50 percent of the investment volume, proof by 31 March 2027)?
• Is commissioning realistically scheduled before 4 August 2029, with buffers for delivery times and the grid connection?
• Does a grid connection charge appear in the investment calculation, and at what amount?
• How does the revenue plan treat grid fees in case grandfathered status is not achieved?

A project with a documented FID and a realistic commissioning schedule carries a regulatorily anchored cost advantage over 20 years; a project without that status needs revenue assumptions that reflect this honestly. How regulatory risk fits into the overall picture next to power prices, technology and financing is laid out in Risks in BESS direct investments, and how they are structurally addressed; the market backdrop with build-out figures and the connection queue is described in Germany's battery storage market: the numbers, the drivers, and why "now" has a date.

Whether a specific project reaches grandfathered status and how its revenue plan treats grid fees is something we walk through in a no-obligation initial consultation, based on the actual project documents and with stated assumptions. We do not give return promises.