The constant growth of renewable energy in regions where local demand is small poses increasing challenges for the electricity grid. As it often takes a long time to plan and implement the expansion of the grid, electricity is increasingly generated far away from its place of consumption. Consequently, there are strong power flows between the main areas of generation and consumption that place a heavy strain on existing transmission capacity and can lead to regional network congestion.

Intensive efforts are being put into expanding the grid to avoid such congestion but, until new lines are operational, temporary measures are needed to ensure system stability. Congestion management plays a key role in this process by reducing the amount of electricity fed in by installations in areas with limited network capacity while activating additional generation in regions that are under less strain.

There is an increasing focus on distribution networks as well as the transmission network. The strong growth in distributed renewable energy installations is causing greater congestion in the lower network levels, making congestion management more important in the distribution, as well as in the transmission, system.

Volume and costs of congestion management measures lower than a year before

The total volume of the measures taken for congestion management (redispatching with operational and grid reserve power plants and countertrading) fell from 6,289 gigawatt hours (GWh) in the second quarter of 2024 to 5,856 GWh in the same quarter of 2025. The total costs were provisionally put at around €623mn and were therefore also lower than in the second quarter of 2024 (Q2 2024: €630mn).

97% of renewable electricity generated successfully transported to final customers

The reductions and increases in feed-in from operational power plants as part of the redispatching process amounted to around 4,575 GWh in the second quarter of 2025 (Q2 2024: 4,727 GWh). This volume included reductions in feed-in amounting to 3,269 GWh (Q2 2024: 3,060 GWh), of which redispatching measures involving renewable power plants totalled 2,298 GWh (Q2 2024: 2,100 GWh).

The total volume of redispatching measures with renewables was around 9% higher than in the same quarter of last year. Two opposing trends are evident here.

First, the volume of redispatching measures using PV installations has nearly doubled from 605 GWh in the second quarter of 2024 to 1,168 GWh in the second quarter of 2025. About 51% of all redispatching measures using renewables were thus carried out with solar. The main reasons for this development were the continuing expansion of generating capacity and, in particular, the unusually sunny weather. By contrast, the curtailment of offshore wind installations fell 37% to 575 GWh during the same period. Reasons for these opposing developments include:

• Less wind: The period was not as windy overall, leading to less potential power from offshore wind and lower demand for redispatching measures for offshore turbines.
• Much higher feed-in from solar at the same time as less windy conditions changed the congestion situation: the strong solar output causes greater east-west flows that are little, if at all, affected by the curtailment of offshore wind installations.

The changed congestion situation leads to a shift in the cause of redispatching measures. In the period under review, about 49% of the redispatch volume in renewables was caused by congestion in the distribution system, while 51% was attributed to congestion in the transmission system. In Q2 2024, these proportions were 71% in the transmission system and 29% in the distribution system.
Overall, renewable energy curtailments amounted to 3% of the total amount of electricity generated by renewables. This means that 97% of the renewable energy produced was fed into the grid and used by end customers.

The reductions were offset by increases in feed-in from power plants totalling 1,650 GWh, representing a decrease of about 16% compared with the second quarter of 2024 (1,964 GWh). Of the increases, 1,306 GWh were from operational plants (Q2 2024: 1,667 GWh), while the remaining 344 GWh (Q2 2024: 301 GWh) came from additional feed-in from reserve power plants.

Feed-in from natural gas (698 GWh) and hard coal-fired (640 GWh) power plants was most frequently increased.

When considering the decline in increases from generating installations to offset reductions, it must be remembered that reductions in the distribution network have risen significantly. As the distribution system operators do not balance these themselves, the balance responsible parties carry out the balancing and the relevant volumes are not included in the increases shown here.

The volume of the countertrading measures taken fell by 26% from 1,261 GWh in the second quarter of 2024 to around 937 GWh in the same quarter of 2025. As for the decline in offshore wind curtailment, the lower volume of countertrading is also due to less wind and changes in grid flows caused by the large solar output. These two factors led to less need for countertrading measures overall.

Decrease in congestion management costs due in particular to decrease in volumes

The total costs for congestion management measures in the second quarter of 2025 were provisionally put at around €623mn (Q2 2024: €630mn), a slight drop. These costs are made up as follows:

The provisional costs for redispatching measures using conventional power plants in the second quarter of 2025 were €179mn, representing a 19% fall compared with the same quarter of 2024 (€222mn). The drop is due to the lower volume of redispatching measures to increase the generation of conventional plants compared to the second quarter of 2024.

The financial compensation paid to operators of curtailed renewable energy installations amounted to around €158mn, which is similar to the second quarter of 2024 (€162mn).

When feed-in from direct-selling renewable energy installations is reduced, plant operators are treated economically as if the intervention measure had not taken place. The network operator credits the reduced volume of electricity to the balancing group of the installation operators and/or their direct sellers. This enables the plant operator to actually complete its commercial transaction and receive the same market revenue as agreed with the direct seller. The network operator also receives the “market premium,” as the financial support for direct selling is referred to under the Renewable Energy Sources Act (EEG). The market premium is the difference between a certain set price of the installation (equal to the renewable energy installation’s primary revenue need) and the monthly average price for electricity on the exchange.

That the financial compensation remained stable although the volume of redispatching of renewables was higher is basically down to two factors. For one, higher wholesale prices pushed the market premium down. For another, there was less curtailment of offshore wind, whereas the curtailment of PV installations was higher. As offshore wind installations have a higher set price than solar installations, the rise in financial compensation for solar was more than made up for by the decline in the offshore wind sector.

The provisional costs of reserving the grid reserve plant capacity plus costs not dependent on the use of the reserve in the second quarter of 2025 totalled €191mn (Q2 2024: €154mn). The costs of deploying the grid reserve amounted to about €77mn (Q2 2024: €66mn). The total costs for the grid reserve were therefore around €267mn. The increase in operating costs is due to the higher number of reserve power plants being deployed compared with the first quarter of 2024. The increase in the costs of reserving the grid reserve plant capacity results from the inclusion of new installations in the grid reserve where measures were necessary to bring installations back online and reserve capacity.

The net costs for countertrading measures in the second quarter of 2025 were about €19mn, corresponding to a decrease of 30% (Q2 2024: €27mn). This decrease is mainly caused by the decline in volumes.