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, any discrepancies arising from electricity being generated far away from its place of consumption can only be balanced out after a delay. 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. However, 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 system as well.

Costs for congestion management down by nearly €100mn on Q1 2025

The total volume of congestion management measures (redispatching with operational and reserve power plants and countertrading) decreased by around 9% compared with Q1 2025, from 9,035 GWh to 8,248 GWh in Q1 2026. The estimated total costs also decreased, amounting to around €784mn, which is nearly 11% below the figure for Q1 2025 (€882mn).

97% of renewable electricity generated successfully transported to final customers

The reductions and increases in feed-in from operational power plants (excluding countertrading) as part of the redispatching process amounted to around 5,989 GWh in Q1 2026 (Q1 2025: 6,773 GWh). This volume included reductions in feed-in amounting to 4,043 GWh (Q1 2025: 4,182 GWh), of which redispatching measures involving renewable power plants totalled 2,215 GWh (Q1 2025: 2,153 GWh). Thus renewable energy curtailments amounted to around 3% of the total amount of electricity generated by renewables. This means that around 97% of the renewable energy produced was fed into the grid and used by final customers.

Compared with Q1 2025, the volume of redispatching measures affecting renewable energy increased slightly by around 3%. The following trends can be noted:

• The volume of redispatching measures using solar installations increased from 234 GWh in Q1 2025 to 288 GWh in Q1 2026, corresponding to an increase of around 23%. The main driver of this development is the continuous expansion of installed photovoltaic capacity. The increase in the volume of measures occurred despite relatively little sun in Q1 2026.
• The curtailment of onshore wind installations in Q1 2026 was 1,054 GWh and thus around 39% higher than in Q1 2025 (758 GWh). A key factor in this development is the higher wind availability compared with Q1 2025, which was characterised by low-wind weather that resulted in fewer situations with high wind feed-in and the associated congestion. In addition, the continued expansion of wind power plants has led to an increase in installed capacity and thus to higher feed-in volumes in critical network situations.
• Although electricity generation from offshore wind increased from 6.7 TWh in Q1 2025 to 9.7 TWh in Q1 2026, the volume of redispatching measures for offshore wind power plants fell by around 25% to 864 GWh (Q1 2025: 1,155 GWh). One of the reasons for this development is the ongoing grid expansion, which generally helps to relieve existing congestion.

The changed congestion situation is leading to a shift in the cause of redispatching measures with renewable energy plants. In the period under review, about 34% of the redispatch volume in renewables was caused by congestion in the distribution system, while 66% was attributed to congestion in the transmission system. In the same quarter of the previous year, these proportions were 79% in the transmission system and 21% in the distribution system (Q1 2024: TSOs: 73%; DSOs: 27%; Q1 2023: TSOs: 83%; DSOs: 17%).

To balance out the reductions, feed-in from operational plants was increased by a total of 1,910 GWh. This corresponds to a decrease of around 26% from Q1 2025 (2,590 GWh). A further 854 GWh was accounted for by the increase in feed-in from reserve power plants (Q1 2025: 687 GWh). Overall, feed-in was increased by 2,764 GWh to resolve network congestion, compared with 3,277 GWh in Q1 2025.

The largest feed-in increases were for hard coal-fired power plants (1,301 GWh), followed by natural gas power stations (918 GWh).

The fact that feed-in had to be increased less than in Q1 2025 is due to network operators having to curtail less as part of congestion management. However, when interpreting this development, it should be noted that reductions in the distribution system increased by 43% compared with Q1 2025. As DSOs cannot balance these measures themselves, the balance responsible parties carry out the balancing. The quantities necessary for this are not included in the feed-in increases shown here.

The volume of countertrading measures in Q1 2026 was around 1,405 GWh, a decrease of almost 11% compared with Q1 2025 (1,575 GWh). One of the reasons for this development is the ongoing grid expansion, which can relieve existing network congestion and thus reduce the need for countertrading measures.

Significant decrease in costs for redispatching with operational plants and countertrading

The estimated total costs for congestion management measures in Q1 2026 were around €784mn (Q1 2025: €882mn), corresponding to a decrease of around 11%. These costs consist of the following:

The costs for redispatching measures using conventional power plants in Q1 2026 were estimated at €282mn, representing around a 33% decrease compared with Q1 2025 (€423mn). The decrease is mainly due to the reduction in the volume of redispatching measures with conventional power plants.

The financial compensation to the operators of curtailed renewable energy plants amounted to around €55mn. This means that, despite a slight increase in the volume of measures compared with Q1 2025, costs fell by around 22% (Q1 2025: €71mn). The decrease in total compensation payments, despite a slight increase in curtailment volume, is essentially due to a change in the energy mix of the curtailed volumes. While curtailment of solar power and onshore wind increased, redispatching measures for offshore wind decreased. Because the specific compensation per megawatt hour for offshore wind – due to the higher values to be applied – is above that for onshore wind and solar power, the financial benefit resulting from the decrease in offshore wind curtailments exceeded the volume-related increase in reductions in onshore wind and solar power. Overall, financial compensation thus decreased significantly.

The estimated costs of reserving the grid reserve plant capacity plus costs not dependent on the use of the reserve in Q1 2026 were around €280mn, representing a 28% increase compared with Q1 2025 (€219mn). The increase is due to the fact that additional installations have been added to the grid reserve and thus in Q1 2026 there were more power stations in the grid reserve than in Q1 2025.
The costs of deploying the grid reserve amounted to around €150mn (Q1 2025: €136mn). The increase compared with Q1 2025 is mainly due to the higher volume of redispatching measures with reserve power plants. Overall, costs for reserve power plants amounted to around €430mn in Q1 2026, which is around 21% above the figure for Q1 2025 (€355mn).

The net costs for countertrading amounted to around €17mn in Q1 2026, which is around 49% below the figure for Q1 2025 (€33mn). The decrease is mainly due to the lower volume of countertrading measures and the lower wholesale prices compared with Q1 2025.