German grid fees are entering a new phase. The regulator BNetzA outlined the future system step by step: a revised grid access fee (BKZ), financing-based tariffs, and new dynamic localised fees. Financing-based tariffs will almost certainly worsen the business case for BESS. But the final question is whether dynamic fees - the locational component of the new regime - will make the overall picture better or worse for batteries, and how much they can counteract the IRR impact of financing grid fees.
The answer is not the same everywhere. Dynamic fees introduce something Germany's grid has never had before: a price signal that varies by location and by 15-minute period, reflecting exactly where and when the grid is under strain. For the right battery in the right place, this is a new revenue stream. For others, it changes little - or makes things worse.
Modo Energy has modelled the impact of dynamic fees for 21 regions across Germany using 2025 redispatch data, assigning locational value to each region - with an uplift of up to €27k/MW/yr for a 4h-battery in some regions. The results show a clear geographic pattern, but with important nuances that challenge the obvious north-south narrative.
This article is the third in a series on future grid fees for German batteries:
- What the regulator has proposed so far as a mechanism
- How financing tariffs may impact the business case
- How dynamic tariffs can become a revenue stream - depending on location
Key takeaways
- Dynamic grid fees are a net positive for batteries in almost all German regions, but the uplift varies by location. Only northern Baden-Württemberg shows a negative revenue impact based on 2025 data.
- At a ±€100/MWh maximum grid fee, the best-positioned batteries in Schleswig-Holstein increase their revenues by 15%, which would offset even considerable new grid capacity fees. Most regions in central Germany create barely any uplift even in a best-case scenario.
- The absolute level of the fee matters as much as the location: at €5/MWh reference price, even the most congested region generates under €1k/MW/yr of additional revenue - negligible against the grid capacity fees which will likely be introduced.
What will the new dynamic grid fees look like?
Not all of Germany's new grid fees will be a fixed tariff. BNetzA proposes dynamic fees that can serve as a direct signal to counteract Germany's chronic grid congestion problem. In 2024, redispatch costs reached €2.8 billion as TSOs repeatedly curtailed wind generation in the northeast and ramped up coal and gas plants in the south and west.
BNetzA proposes fees that:
- change every 15 minutes.
- are differentiated by location - on the TSO-level, for example, in the 22 week-ahead planning regions the TSOs are already using.
- are symmetrical: generators and consumers on the wrong side of a bottleneck pay, those on the right side get paid.
- are set every day before the day-ahead auction.
- should scale with congestion: zero in uncongested periods, and rising to reflect the cost of redispatch when the grid is constrained.
For price-sensitive assets like batteries, this opens up a new set of prices to operate and optimise around. Until now, grid operators have asked batteries to behave grid-friendly but given no information on what that actually means at each location and in each moment. Dynamic fees fix that. Of course, there will still be periods where arbitrage pays more than grid-friendly behaviour. But batteries can now make that choice based on a price signal rather than just following wholesale markets and being redispatched by the grid operator. As long as the fee is well-calibrated, the batteries can let the market signals decide whether flexibility is worth more to the grid or the wholesale market.
Where is the best location for Batteries under the new grid fees?
Dynamic grid fees introduce a locational signal for the first time. Using 2025 redispatch data and power prices, Modo Energy has modelled the revenue impact across Germany's TSO planning regions based on grid strain periods already visible in today's redispatch data.
Dynamic fees are a net positive for batteries in almost all regions. Batteries can adapt flexibly to new price signals, and in most locations, the additional revenue outweighs the cost. But the effect is not uniform: regions with strong curtailment offer the best opportunities.
The strongest uplifts are in the north. Schleswig-Holstein and the TenneT-operated part of Lower Saxony stand out - but even in the south, Bavaria generates a positive uplift relative to a no-fee baseline. The only notable exception is northern Baden-Württemberg, where several coal-fired power stations are used for redispatch-up on a near-continuous basis, leaving little room for a battery to benefit from the signal.
Daily redispatch shapes would point batteries to the south…
For batteries, the location of curtailments and redispatch-up spells tells only part of the story. Batteries operate on within-day cycles, so the shape of curtailment and redispatch activity matters as much as the volume.
That shape varies significantly across Germany, driven by the technology behind each constraint. Most congestion is wind-based (generation in the north that cannot reach demand centres in the west and south). Wind curtailment does not follow a daily cycle. It runs on longer-term patterns, with 46 curtailment spells in northern Germany being longer than 24 hours. That means batteries in curtailment zones have no incentive to charge during curtailment and discharge when it clears, as that would mean missing multiple cycles.
This mismatch between wind curtailment and battery cycles is causing similar problems for batteries in Scotland, which are not penalised for discharging during wind curtailment but can be bid down in the Balancing Mechanism to absorb curtailed energy instead. This can result in undesirable behaviour where batteries are continuously scheduling discharge but are reversed by the system operator at cost. Germany’s system would not create these distortions, but it also wouldn’t materially reduce redispatch volumes during longer congestion spells.
In Schleswig-Holstein, average curtailment is almost flat across the day. The same is true in North Rhine-Westphalia, where the redispatch-up requirement is equally constant.
In the south, the picture is different. Bavaria hosts most of Germany's solar capacity, and curtailment increasingly peaks at midday, with redispatch-up required in the morning and evening when extra generation is needed to meet demand behind the grid bottlenecks.
For a battery in the south, this is a natural fit. The dynamic fee signal reinforces what the battery is already doing: charging at midday when solar would otherwise be curtailed, discharging in the evening when supply is scarce. In the north, the flat curtailment profile means the fee shifts the level of prices but not their shape - battery dispatch changes less than the aggregate uplift figures might suggest.
… but cheaper charging costs for self-consumption swing the advantage back to the north
But net revenues across the year are still higher in the north. That’s because revenue from arbitrage is only one side of the equation. Batteries also pay for the power they consume. At 88% round-trip efficiency (RTE), each MW of a 4-hour battery uses around 400 MWh of power per year in RTE losses - charged at the cheapest periods of the day, but still a cost that compounds.
Here, the north has a structural advantage. Average dynamic grid fees across the year amount to €19.20/MWh in the north. In some southern regions, grid fees make baseload power on average €15.41/MWh more expensive - a gap that directly erodes net revenue.
This makes the optimal location sensitive to your project’s round-trip efficiency: at 88% RTE, a northern battery earns 9.3% more than one in northern Bavaria once self-consumption costs are accounted for. At 95% RTE - a more optimistic but extreme assumption to test sensitivity - the gap narrows to 4.7%, but the north retains the advantage. The ideal daily shape in the south does not fully offset the higher charging cost.
Implementation starts in 2029, but fees will rise slowly as TSOs test price sensitivities
BNetzA targets 2029 for the first dynamic fees, applied at the TSO level across several regions. Batteries come first. The regulator sees them as the ideal starting point:
- High price sensitivity
- No inflexible baseline consumption
- A clean bidirectional response
Fees will start low deliberately, giving TSOs time to learn each region's price sensitivity before calibrating correctly. Setting fees too high risks triggering a complete shutdown of generation rather than a measured partial reduction.
The rollout to lower voltage levels and broader consumer groups follows only after this learning phase, but the timeline is already under pressure. In a discussion paper, the four TSOs warn of possible delays, citing the implementation burden: coordinating signals across all distribution network operators, installing smart meters at scale, building shared data platforms, and establishing common standards. They point out that no country in Europe has implemented fully dynamic, load-flow-based grid pricing at scale before.
Dynamic grid fees are locational pricing through the back door, but only work if calibrated carefully
Dynamic grid fees achieve, in effect, what a nodal or zonal electricity market would do explicitly: they shift the relative economics of generation and consumption by location, pushing units up or down the merit order depending on where they sit relative to a congestion point. A battery in a curtailment zone faces a higher net cost to discharge and a lower net cost to charge, mirroring the economics of a nodal price discount.
This gives the battery important information about the grid: if a battery tries to discharge into an already constrained grid flooded with renewables, it causes additional curtailment and redispatch-up. The grid fee then also reflects the system cost this battery behaviour causes. A large industrial consumer behind the same bottleneck faces a higher net energy cost in congested hours, replicating what a locational marginal price would signal directly.
The mechanism operates through price rather than dispatch instructions, but that is also its central vulnerability. The fee only works if set at the right level for each region's actual price sensitivity, which varies enormously. A CHP-dominated region may barely respond to a €20/MWh signal as those units bid at deeply negative prices. A wind-heavy region may respond sharply but non-linearly: below some threshold, nothing moves; above it, large volumes switch off simultaneously, potentially replacing one congestion problem with another.
At launch, TSOs will have almost no empirical data on regional price sensitivities. Getting this wrong in either direction (fees too low to move behaviour, or fees that trigger abrupt synchronised responses) undermines the entire mechanism. It also shows why other markets have opted for zonal pricing instead. In Germany, that remains politically unlikely, leaving dynamic grid fees as the next-best option.
Dynamic fees can offset financing grid fees - but only in the right place, at the right fee level
From 2029, batteries face two new grid fee pressures pulling in opposite directions: the financing-based capacity charge covered in our previous article, which is a certain cost, and the dynamic revenue uplift covered here, which is uncertain and location-dependent. Whether one offsets the other depends entirely on where the project sits and where the fee scalar lands.
Location is the first filter. At a €100/MWh reference price, batteries in Schleswig-Holstein generate enough dynamic revenue to absorb significantly higher financing charges before returns deteriorate. At the other extreme, northern Baden-Württemberg produces a net negative; there is nothing to offset. Most central German regions fall somewhere in between: positive but modest uplifts unlikely to cover financing charges even at the maximum reference price.
The fee scalar is equally decisive. BNetzA has indicated fees will start low:
- at a €5/MWh reference price/maximum grid fee: even the most congested region generates under €1k/MW/yr; negligible against any financing charge
- at a €50/MWh reference price: the best regions reach around €11k/MW/yr, scaling roughly linearly
- at a €100/MWh reference price: the effect becomes genuinely material for well-sited assets
How quickly fees will reach €100/MWh (if ever) will not be known until the learning phase is complete. For most batteries in most locations, dynamic fees are unlikely to fully offset financing charges in the early years of the regime.
How will revenues from dynamic grid fees develop in future?
Germany is investing heavily in north-south grid capacity, which should reduce redispatch needs over time. But generation buildout is running ahead of infrastructure delivery, so the gap will persist for years.
Offshore wind is outpacing grid expansion in the north
Offshore wind capacity is set to triple from 9 GW today to 30 GW by 2032, with 14 of 17 planned sites located in the North Sea and landing power into the same northwestern onshore footprint. Grid relief is coming, but later:
- End-2028: SuedLink commissions - 4 GW of new north-south high-voltage direct current (HVDC) capacity, the single largest piece of relief infrastructure
- 2031 onwards: NordWestLink and OstWestLink add a further 4 GW combined
- 2035 target: 40–50 GW of offshore capacity, well ahead of available evacuation infrastructure
Redispatch volumes in the northwest are therefore likely to grow through 2028, partially ease with SuedLink, and remain structurally elevated through the mid-2030s as generation consistently outruns evacuation capacity.
Solar curtailment may continue to grow, making grid fee shapes in the South more and more ideal
Solar curtailment is only beginning to pick up, and midday curtailments in the south will likely increase as capacity grows. This could improve the dynamic fee outlook for southern batteries, potentially to the point where they rival the self-consumption cost advantage currently held by the north.
How quickly this materialises will depend on the pace of solar buildout and its dispatchability, both of which are shaped by proposed changes to the EEG and potential dynamic fees for solar generators.
