When the wind blows hard in northern Germany, wind turbines sometimes stand still. Not because nobody needs the electricity, but because it cannot get to where it is needed. There is a term for this process that is rarely heard outside the energy industry: redispatch. It costs around three billion euros every year. And it regularly raises the question of whether it would not be better to convert that electricity into hydrogen. The question is legitimate. The answer is more uncomfortable than it first appears.
What redispatch is
Redispatch is often explained in terms of keeping the grid frequency stable, that is, the balance between electricity generated and electricity consumed. That is wrong. That balance, the famous 50 hertz, is maintained by a different instrument: balancing power.
Redispatch solves a spatial problem. Power plants feed in where they stand. Consumers draw power where they sit. In between are lines with limited capacity. If a line or a transformer is at risk of being overloaded, the grid operator intervenes. It ramps down a plant ahead of the bottleneck and ramps up another one behind it. The amount of electricity in the system stays the same; only its geographic origin changes.
In Germany, the most important of these bottlenecks runs from north to south. Wind power from Schleswig-Holstein, Lower Saxony and the North Sea meets lines that cannot fully transport it to the consumption centres in the south. So generation is curtailed in the north and a gas or coal plant is ramped up in the south.
Alongside redispatch in the narrow sense, this congestion management also includes countertrading, where grid operators buy electricity on the market to reduce transport requirements, as well as the use of reserve power plants.
Where the costs come from
The costs arise in three places. First, the curtailed plant operator has to be compensated. It could have sold electricity and must not be left worse off by the intervention. In 2024, around 554 million euros flowed to operators of renewable installations for this.
Second, the electricity that is not generated in the north has to be generated in the south. That is done with plants that would not otherwise have been dispatched, which means more expensive ones. The difference is a cost block of its own.
Third, there are reserve power plants and countertrading, which are only indirectly related to the curtailment of renewable installations.
In total, congestion management came to around 3.3 billion euros in 2023, around 3.0 billion in 2024 and around 3.1 billion in 2025. The peak was 2022, at 4.1 billion euros. The costs are therefore not falling in a straight line; they fluctuate with fuel prices, weather conditions and progress on grid expansion.
Important for context: only a small share of generation is curtailed. In 2024, 96.5 per cent of electricity from renewable energy could be fed in and used. Around 3.5 per cent was curtailed, equivalent to roughly 9.4 terawatt hours. Anyone who speaks of billions of euros of “wasted electricity” is confusing the total cost of congestion management with the value of the curtailed energy.
Who pays the costs
Not the taxpayer. That confusion is widespread and wrong.
The costs of congestion management are passed on through grid fees. They appear on the electricity bill, not in the federal budget. They are therefore paid by all electricity customers, from private households to industrial operations.
What is interesting is the spatial redistribution involved. One example: Schleswig-Holstein Netz AG curtailed around 802 gigawatt hours onshore in 2025, at a cost of around 74.2 million euros. It carries out more than 65 per cent of these curtailments at the request of the transmission system operator TenneT, because of bottlenecks in the extra-high-voltage grid that are in part not even located in Schleswig-Holstein.
Accordingly, these costs are largely socialised nationwide through transmission grid fees rather than regionally. The place of curtailment and the place of its cause regularly diverge.
Redispatch solves a spatial problem. Power plants feed in where they stand. Consumers draw power where they sit.
Redispatch: why the system is so expensive
Up to this point, redispatch sounds like a purely technical balancing mechanism. Economically, it is more than that. Redispatch sustains a price world that does not physically exist in the grid.
Germany has a single exchange electricity price for the entire country. Generators and consumers trade as if electricity were equally scarce everywhere. In fact it is not. In the north there are frequent surpluses because of the wind supply; in the south demand often exceeds supply. The uniform price blends out the limited transport capacity in between. Redispatch corrects this fiction after the fact, physically and at the expense of grid fees. Redispatch can therefore also be read as the price we pay for a single, nationwide electricity price zone.
The dispute over the price zone
This is exactly where a debate that has been running for years begins. The European Commission has long pushed for Germany to be split into several bidding zones. The logic behind it is a price signal. If electricity were cheaper in the windy north and more expensive in the south, consumption and new generation would gravitate on their own to where the grid can handle them. The balancing would happen in the market rather than after the fact through redispatch. Proponents, among them the think tank Epico and most recently the Greens, see this as the more efficient solution because it addresses the cause instead of the symptom. Several northern and eastern states such as Schleswig-Holstein, Lower Saxony and Brandenburg have also floated the idea, in part with the thought of forming joint zones with Denmark or Poland.
Against this stands an equally serious argument. A split would turn the south, above all industrially strong Bavaria, into a high-price zone. Business there and the federal government reject that; the coalition agreement commits to preserving the single zone. Critics point to higher electricity prices for industry, lower market liquidity, an implementation period of several years, and the fact that central grid projects such as SuedOstLink, Ultranet and SuedLink are meant to remove a large part of today's bottlenecks by the end of the decade anyway, before a split would even take effect. Parts of the renewables industry are sceptical too, because lower prices in the north would weaken revenues and thus the investment incentives for wind power there.
The real question, then, is less whether today's system is inefficient. That is largely undisputed. The question is whether splitting the zone actually lowers the cost of that inefficiency or merely shifts it somewhere else.
The European dimension
The debate does not end at the border. The European Commission wants national electricity markets to grow together through a massive expansion of cross-border lines. Germany's single zone is increasingly seen as a drag on this, because German price pressure is carried into neighbouring countries via new connections. In Sweden, for instance, there is growing concern about catching Germany's high price level through additional interconnectors, which dampens the willingness there to build such connections at all. The question of the German bidding zone is therefore also a question of European market integration.
What policymakers are trying instead
Rather than splitting the zone, the federal government is trying to capture the imbalances in another way. Economics Minister Katherina Reiche is planning a redispatch proviso as part of the so-called grid package. New renewable installations in congested grid regions would no longer receive compensation if their electricity cannot be taken up by the grid. The renewables industry counters that this would make new build-out uneconomical across large parts of Germany. Critics object that the proviso once again fights the symptom rather than the cause, namely that grid bottlenecks are barely reflected in the electricity price. Reiche has recently signalled a willingness to compromise.
What is striking is where several actors from apparently opposing camps end up, namely at the expansion of grids, storage and flexible loads, hydrogen included. That is not a contradiction of the price zone debate but its practical flip side. With or without regional price signals, in the end physical capacity is needed that absorbs surpluses where they arise. And steering that capacity in a grid-friendly way, rather than purely market-driven, is at its core a data task.
Themen / Tags: Redispatch · Strommarkt · Wasserstoff · Netzausbau
Kategorie / Category: Blogposts