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Based on the power system analyses we draw the following main conclusions:

The model-based analysis of supply and demand shows a European power system undergoing a rapid transformation to renewable energy – renewable energy shares reach close to 70% by 2030 and more than 90% in 2050. At the same time, electrification within transport, heating and industry increases the overall demand for electricity.

Technology developments and learning effects imply falling levelised costs for offshore wind. Consequently, Baltic Offshore wind power’s levelised cost of energy at the best sites falls to 50 €/MWh in 2030 and 38 €/MWh in 2050, including connection costs.

The most attractive sites are located in the southern part of the Baltic Sea, mainly due to better wind conditions and a higher market value for the power generated. The higher market value is explained by the proximity to load centres in central Europe. In the Northern part of the Baltic Sea the presence of relatively cheap alternative RES (mainly onshore wind) and grid bottlenecks limit the market value of offshore wind power.

Even without cooperation, offshore wind power in the most favourable sites in the Baltic Sea could be able to compete with other generation options (both fossil and renewable) already in 2030.

Cooperation on the construction of advanced offshore hubs, which both connect offshore wind power and increase interconnection capacity between countries, may further increase the value of Baltic Offshore wind power. The regional system analysis suggests that aggregate costs could be reduced by up to €5 per MWh of Baltic offshore wind power generation through the use hubs. The results also show that the configuration and timing of hubs should be carefully considered, and that the efficiency of using hubs is improved by the wider use of cooperation mechanisms for the deployment of offshore wind power in the Baltic Sea area.

In general, regional cooperation mechanisms support a more efficient distribution of offshore wind power capacity across the Baltic Sea as a whole, allowing greater focus on sites with lower deployment costs and more valuable power generation. Scenarios that allow for a more efficient distribution of offshore wind power capacity across the region have aggregate costs that are €5 – 9 lower per MWh of Baltic offshore wind power generation in the longer term.

6 Task 3a – Grid modelling and grid investment options

Key Messages from the Results

Until 2030, internal grids are likely to be able to cope with the buildout of offshore wind power in all scenarios, assuming that grid investments in line with ENTSO-E’s TYNDP 2018 and current national plans are carried out.

After 2030 and independent of the expansion of offshore wind power, substantial grid investments will be needed in many of the BEMIP countries due to a shift from conventional to renewable energy sources and an expected significant increase in electricity demand from the heating and transportation sectors.

Offshore wind power deployment and the development of advanced offshore hubs in the Baltic Sea region are expected to both increase and redistribute redispatch costs among BEMIP countries, particularly affecting Estonia, Lithuania, Latvia, Poland and Germany.

Targeted and timely investments can significantly mitigate the cost increases.

Across all BEMIP countries, higher levels of regional cooperation reduce overall grid utilisation and expected socio-economic costs of redispatch compared to purely national approaches: The additional Baltic Sea interconnectors allow for excess offshore wind power to be shared more efficiently between countries and offer alternative trading paths, thereby relieving the grid around existing interconnectors.

Costs and benefits are not equally shared between the countries. Any cooperation should therefore be accompanied by a fair analysis of the burden of each member state, ensuring that all countries share the benefits of increased cooperation.

The purpose of the grid modelling is to quantify the social welfare effects related to grid congestions and redispatch due to offshore wind deployment, and to investigate how the level of offshore deployment ambition and the level of cooperation between BEMIP countries impact the social welfare effects. To this end, we investigate if offshore wind deployment in the Baltic Sea necessitates onshore grid reinforcements, and if so, aim to identify efficient grid upgrades.

We consider an upgrade efficient if the annualised cost for the upgrade is lower than reduction in redispatch costs – that is, the upgrades we include lead to total cost reductions as the system is better adjusted to handle offshore wind.

A grid model simulates physical flows in a nodal representation of the network and therefore allows computation of the location of congestions within zones and estimation of the social

welfare cost of redispatch. A grid model also allows us to propose grid reinforcements where the grid congestions occur and evaluate if the reinforcements reduce redispatch cost sufficiently to be economically sensible. The grid modelling does not only compare redispatch costs in a fixed grid in the different scenarios, but also considers how the grid may be reconfigured in order to match the differences in generation and trade between the scenarios.

For this study, we used THEMA’s The-GRID model.

In Section 6.1 we describe the methodology used for the grid modelling and the calculation of redispatch costs. We proceed to present the results from the grid modelling in terms of utilization of internal grid elements in the relevant countries and regions, in Section 6.2. The impact of offshore wind power on internal grid costs is quantified through a simple calculation of redispatch costs. These calculations create the basis for a discussion of the need for internal grid upgrades due to the offshore wind deployment in the scenarios described in Task 2.

Finally, we collect the results from all countries and conclude our findings in Section 6.3.

The impact of redispatch and grid upgrades on total system costs is included in the cost benefit analysis in Chapter 1. For all countries, the results should be interpreted in the context of a system undergoing profound changes towards a system with a high penetration of renewable power generation, electrification of transportation and heating sector, as well as increased cross-border interconnector capacity. Such a system will challenge the internal grids regardless of offshore deployment, as we will see in the model results.