• Ingen resultater fundet

The utilisation of the internal grid with the suggested grid upgrades in the Baltic countries are illustrated in Figure 6-13 for the Ambitious GPC scenario in 2050. Due to a skewed power balance with high demand and low generation in the most populated areas (Tallinn, Riga and Vilnius) and independent of offshore deployment, the internal grid is struggling to transfer capacity both with and without grid upgrades.

The results of both the market modelling in Task 2 and the grid modelling highlight the benefit of increased interconnector capacity in the Baltic countries. The main direction of the energy flow is from Finland via Estonia and Latvia to Lithuania, and further to Poland. Hence, a regional perspective on grid upgrades and interconnector capacity seems to be appropriate in these countries independent of offshore wind development scenarios.

Figure 6-14 Total change in social welfare costs due to offshore wind deployment in the BEMIP region in 2030, per scenario, in MEUR.

Figure 6-15 shows total annualised social welfare costs of redispatch and grid upgrades across the BEMIP region in 2050. The general trend that increased cooperation and higher ambition leads to lower grid costs across the region is reaffirmed. As in 2030, the scenario with highest cost is the low ambition NP scenario, and the scenario with lowest, in fact negative, impact on redispatch costs is the ambitious GPC scenario.

However, the picture is more complex in 2050: some countries see increasing redispatch costs with increasing cooperation. For example, Germany and the Nordic countries experience increases in the ambitious deployment scenarios. This finding motivates the recommendation that regional cooperation should be accompanied by a fair analysis of the benefits and costs that each member state bears, e.g., due to the connection of an offshore hub.

Also, in the under low ambition scenarios, the GPC scenario exhibits higher redispatch costs than the GC scenario. The increase stems from both Germany and Poland and might be related to insufficient German-Polish cross border capacity. However, it such effects were out of scope for the analysis of internal constraints in this section.

Figure 6-15 Total change in social welfare costs due to offshore wind deployment in the BEMIP region in 2050, per scenario, in MEUR.

As input to the cost-benefit analysis, we use the relative increase or decrease compared to the NP Low deployment scenario, which is used as reference in the analysis of offshore grid power scenarios. The following table summarises the results of the grid modelling for the whole BEMIP region. These numbers are used in the CBA in the next chapter.

Table 6-5 Change of social welfare cost due to redispatch and grid reinforcements in the BEMIP region as a total, after internal grid reinforcements, compared to the Low deployment NP scenario, in MEUR.

Grid Low Ambitious


Redispatch costs -49 -74 61 -65 -92

Grid reinforcement 0 0 0 0 0


Redispatch costs -397 -167 -198 -398 -579

Grid reinforcement 0 0 0 36 36

6.3.2 Conclusions

The grid modelling exercise gives some relevant insights into the effect of offshore wind deployment and regional Baltic grids on onshore congestions and need for and benefits of internal grid reinforcements. The main findings are

Given planned grid upgrades, none of the offshore wind power deployment scenarios drive severe congestions in the internal grid in the Baltic Sea by 2030.

In 2050, the grid exhibits congestions due to changes in market fundamentals stemming from the energy transition: increased electricity demand, a higher share of generation from intermittent onshore RES generation, and increased exports from the Nordic countries.

The higher offshore wind deployment is only a minor driver for grid congestions.

Targeted grid reinforcements and coordinated grid planning are likely to significantly reduce redispatch costs associated with offshore wind deployment in Germany, Poland and the Nordic countries, and to reduce congestion in general in the national networks.

Planning and implementation of such reinforcements should be taken with a long-term vision, considering their benefit and the long lead times of grid projects.

In general, we find that both in 2030 and 2050 and with both low and ambitious offshore wind power deployment, the impact on grid costs is lower in the cooperation scenarios than in the National Policy scenario. This seems to be driven by two factors: first, additional interconnector capacity provided by hubs allows alternative export routes for the power surplus in the north, thus reducing the overall costs related to congestion. Second, with policy coordination, offshore capacity is installed closer to areas where additional capacity is needed, i.e., notably Poland and the Baltic countries which see a relatively high demand growth. New offshore generation capacity can cover demand growth with less additional stress on the grid than increased imports along existing interconnections.

The finding that cooperation on Grids and Policies significantly reduces total redispatch costs associated with offshore wind power deployment compared to the National Policy scenarios holds both for Low and Ambitious offshore wind deployment. We also see lower total redispatch costs under Ambitious deployment compared to Low deployment.

Benefits of increased cooperation are not necessarily shared equally between countries. It might be relevant to discuss costs and benefits of cooperation projects such as offshore hubs incurred by participating countries in detail for each project.

7 Task 3b – Cost benefit analysis

Key Messages from the Results

The cost-benefit analysis including all results from the market and grid modelling demonstrates the value of regional cooperation. Except for the Low ambition scenario in 2030, all scenarios suggest significant total savings from regional cooperation on offshore wind power deployment in combination with regional grid planning and development. The savings are driven by more efficient dispatch, reduced fuel and CO2 costs, and to some extend by reduced redispatch costs for TSOs.

Considering the lead time for cross-border interconnector projects and considering the value of regional cooperation, the CBA clearly suggests that regional cooperation and concrete evaluation of common projects should start as soon as possible. Beneficial cross- border renewables projects may be able to receive support through the Connecting Europe Facility (CEF), provided they are identified and prepared sufficiently early in the selection process.

The cost-benefit analysis compares the social welfare changes between the scenarios. This allows us to understand the effects that different buildout options and levels of cooperation have on social welfare, taking the impacts on generation and grid costs into account.