GESTIÓN RECAUDATORIA EN EL PERIODO EJECUTIVO

On the basis of the RES-E capacity expansion we have analysed the optimal expansion of the European transmission grids in order to accommodate different levels of RES-E at the lowest possible cost. This Section first presents the corresponding impacts in terms of grid transfer capability and changes to the topology of the European transmission grid. At the end of this Section, we furthermore provide an overview of associated investments and costs.

Figure 64 shows the development of total grid transfer capability (GTC) in the three main scenarios. By definition, no additional transmission capacity is required in 2020 since our assumptions are based on the investment plans set out in the Ten-Year Network Development Plan (TYNDP) developed by ENTSO-E. Consequently, the model optimizes transmission capacity requirements beyond 2020 only.

A comparison of the three main scenarios in Figure 64 shows that:

 The need for transmission expansion is significantly higher in scenarios with an increasing penetration of variable RES-E; and

 All three scenarios show a significant expansion of the European transmission grids already in both 2025 and 2030.

The model results show that investments into additional transmission infrastructure generally increase over time, i.e. as the penetration of variable RES-E grows. Moreover, Scenario 1 with a high share of RES-E requires significantly more transmission network investments than Scenarios 2 and 3. Indeed,

Scenario 1 Scenario 2 Scenario 3

FR

Scenario 1b Scenario 1 Scenario 1a

GTC effectively doubles from 2020 to 2030 in scenario 1, i.e. it increases from approx. 87,000 GW-km in 2020 to almost 170,000 GW-km in 2030. Conversely, the requirements are lowest in Scenario 3, which also has the lowest share of RES-E. Still, an additional grid transfer capability of almost 48,000 GW-km is required by 2030, representing an increase of approx. 55% compared to 2020. The results of Scenario 2 finally are between these two extremes, with a grid expansion of some 58,600 GW-km, reflecting an increase of 67% compared to the 2020 capability.

These results indicate that significant benefits can be achieved by reinforcing the European transmission grids, and that the need for transmission expansion grows with an increasing penetration of variable RES-E. However, it is worth noting that a significant expansion of the European transmission grids can already be observed for scenario 3 in the year 2025, which represents the lowest penetration of variable RES-E among the scenarios with optimised transmission expansion. This indicates that transmission expansion may not only be driven by the growing penetration of variable RES-E. Instead, at least some part of the additional transmission capacity may also serve to benefit from regional diversity and hence increase the efficiency of the 'existing' power system.

Strictly speaking, these results should therefore be interpreted as reflecting the benefits of increased transmission rather than an absolute need for additional transmission capacity. Hence, whilst the results clearly indicate that an increasing penetration of RES-E can be facilitated or may even require additional network capacity, not all of the additional transmission capacity may be absolutely required. We further explore this aspect below in the context of the sensitivities with reduced transmission expansion.

Figure 64 Development of Grid Transfer Capability in the main scenarios in the period 2020 to 2030

Figure 65 shows the modelling results regarding additional transmission capacity requirements in the year 2030 for the variations of scenario 141_{. When comparing the three different variations of scenario 1,} i.e. scenarios 1b, 1 and 1a, we observe an increasing volume of transmission expansion from scenario 1b (lowest) to scenario 1a (highest.) In direct comparison, scenario 1a requires about 20,000 GW-km (or 25%) more transmission expansion than scenario 1b. We note that this effect coincides both with increasing electricity demand and a growing penetration of RES-E in absolute terms. This seems to confirm our earlier observation that the absolute volume of variable RES-E seems to be a major driver for transmission expansion.

0 40,000 80,000 120,000 160,000 200,000 2020 2025 2030 2020 2025 2030 2020 2025 2030 Scenario 1 Scenario 2 Scenario 3

GW

-km

When comparing the scenarios with a more centralised or decentralised generation structure, the need for transmission expansion remains virtually unchanged. Whilst total GTC slightly decreases in scenario 1b-DG, transmission expansion actually increases in scenarios 1-DG and 1a-DG. This observation may appear surprising on first sight as it is often assumed that decentralised generation will by definition reduce the need for network expansion. The view that DG will naturally reduce the need for network expansion is implicitly based on the assumption that decentralised generation will always be located close to consumption and that it will mainly reduce residual net consumption locally. Under these circumstances, DG can indeed help to reduce the need for network expansion as also illustrated by the results of the distribution analysis (see discussion on p. 70 ff. in Section ‎4.4 below) or the load-driven scenario as subsequently discussed below. It is therefore important to also consider the specific assumptions underlying the DG scenarios in this study.

Figure 65 Grid transfer capability for the variations of Scenario 1 in the year 2030

As explained in the context of the load-driven scenario the regional distribution of RES-E in the PRIMES scenarios is mainly driven by resource availability. Besides the location of offshore wind power in the centralised scenarios, this also applies to the regional distribution of solar power in the decentralised scenarios. As a consequence, an over-proportional share of solar power is installed in Southern Europe, resulting in the need of exporting excess electricity to other regions. This effect is further aggravated by the assumption that solar power will be generally based on the use of PV panels, which are characterised by a relatively low capacity factor. The use of solar PV thus increases the need for exports of temporary exports, for instance during sunny days in the spring or autumn, even if local consumers still need additional supply of electricity at other times.

In this context, it is furthermore interesting to consider the impact which the different sensitivities of Scenario 1 have on the need for transmission grid expansion (compare Figure 66). Figure 66 shows that the load-driven scenario leads to a significant reduction in incremental transmission capacity. This reflects the fact that the load-driven scenario was specifically designed with the aim of a more balancing regional distribution of wind and solar power, i.e. with a more local production structure (see

Section ‎3.4.1). The load-driven scenario thus confirms that DG may indeed help to reduce the need for network expansion. In addition, it also requires less back up capacity (compare Figure 62 on p. 58) such that it more generally requires less additional infrastructure to integrate the same penetration of RES-E as the centralised scenarios 1 and 1-DG. However, as the need for additional network capacity in scenario 1-DG shows, it is not the use of DG in general, which allows reducing the need for network infrastructure, but rather the specific choice and distribution of different decentralised technologies. These considerations highlight the impact, which two major design parameters, i.e. the choice of technologies and the regional distribution of RES-E, may have on the cost of system integration.

0 40,000 80,000 120,000 160,000 200,000 1b 1b-DG 1 1-DG 1a 1a-DG GW -km

Although DR also allows for a reduction of transmission expansion, the impact is much smaller and remains of a largely marginal nature, i.e. less than 5% in terms of transfer capability as well as costs. This limited effect can probably be explained by the fact that transmission expansion is primarily driven by differences in resource availability, whereas DR mainly helps to mitigate the impact of short-term variations. In principle, it might be possible to achieve a further reduction in infrastructure needs by adjusting the geographical distribution of DR in accordance with the system’s needs. This, however, has not been further investigated in this study and would furthermore require strong locational signals and/or other regulatory interventions, in order to steer the geographical distribution of DR.

Figure 66 also shows that an increased use of heat pumps and EVs (without load management) requires additional reinforcements of transmission systems. This result emphasises that the need for transmission expansion is not only driven by RES-E but equally by potential developments on the demand side. However, it should be noted that these results do not consider the potential benefits of demand response or decentralised storage; these aspects are discussed in more detail in Sections ‎6.2.4 and ‎6.2.2,

respectively.

Figure 66 Grid transfer capability for sensitivities of Scenario 1 in 2030

Figure 67 and Figure 68 show the structure of the optimised transmission grid in the year 2030 in scenarios 1, 2 and 3. Each figure indicates both the existing grid transfer capability in the year 2020 as well as additional reinforcements until the year 2030.

These two figures reveal that most of the additional transmission capacity is located in few corridors linking in particular those regions with a high penetration of wind power, i.e. Scotland, Denmark / Northern Germany, BeNeLux, France, Spain and Italy. All scenarios furthermore result in additional capacity between Great Britain and Norway, allowing the former to benefit from the flexibility of Norwegian hydropower.

In Scenario 1, which has the highest share of RES-E, these network reinforcements effectively result in a large 'transmission loop' from Northern Germany via South-Western Europe to Italy and back to

Northern Germany, and two radial connections from Northern Germany to Northern Sweden and from France to Great Britain (and further to Norway).

0 40,000 80,000 120,000 160,000 200,000 Scenario 1 Low DR Transm. Delay No Transm. Scenario 1-DG Transm. Delay Scenario 1-DG Load Driven Scenario 1a-DG HP/EV GW -km 0 40,000 80,000 120,000 160,000 200,000 2020 2025 2030 2020 2025 2030 2020 2025 2030 Scenario 1 Scenario 2 Scenario 3

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-km

Figure 67 Existing and final transmission capacity in Scenario 1 (2030)

Scenario 2 (Figure 68) shows a similar pattern as scenario 1, but with generally lower transmission expansion. The same trend can principally be observed for scenario 3, except for a few isolated connections (such as from Serbia to Hungary).

Scenario 2

Scenario 3

Figure 68 Existing and final transmission capacity in Scenarios 2 and 3 (2030)

Figure 71 shows the same view for Scenarios 1a and 1b. In principle, both Scenarios reveal a similar pattern of transmission expansion as Scenario 1, although the overall level of interconnection is slightly higher and lower in Scenario 1a and 1b, respectively. When neglecting some other minor changes, these variations thus seem to broadly reflect the different penetration of variable RES-E in the three different scenarios.

Figure 69 Existing and final transmission capacity in Scenario 1a (2030)

Figure 70 Existing and final transmission capacity in Scenario 1b (2030)

Figure 71 compares the optimised transmission grid in two variations of Scenario 1a with a more centralised and decentralised generation structure, i.e. Scenarios 1a and 1a-DG. Despite a similar

general structure, the second variation with a higher share of decentralised generation leads to the following changes:

 A further strengthening of the transmission corridors between Spain and Italy, Spain and Great Britain, and between Northern Italy and (Northern) Germany;

 The extension of the link between Northern and Southern Italy; and

 A more limited expansion of the interconnector between Scotland and Norway.

These changes effectively result in a further strengthening of the links between the major centres of wind and solar power in (Western) Europe, whereas changes in other parts of Europe remain limited. Similar trends can also be observed for the other variations of Scenario 1, i.e. between Scenarios 1 and 1-DG as well as between Scenarios 1b and 1b-DG.

Scenario 1a

Scenario 1a-DG

Figure 71 Existing and final transmission capacity in Scenarios 1a and 1a-DG (2030)

Figure 72 shows the results of the load-driven scenario. A comparison with Figure 67 reveals some interesting differences with the outcome of Scenario 1. Figure 72 again shows that the load-driven scenario requires less transmission expansion than the original Scenario 1 or the corresponding variation with an increased share of decentralised generation (1-DG). Secondly, most of the reduction is achieved by either avoiding or reducing expansion in certain corridors that were required in the original

Western Germany and the Netherlands, between Northern Germany and Italy, and between Spain and Italy. In contrast, there is hardly any need for additional transmission capacity in the load-driven scenario, except for a new connection between Italy and Albania or the reinforcement of the

interconnector between Sweden and Poland. To a large extent, these changes seem to reflect the major reduction of offshore wind in more peripheral areas around the North Sea. Conversely, it appears to be much easier to integrate the additional volumes of biomass and onshore wind power in Central and Eastern Europe.

Figure 72 Existing and final transmission capacity in the load-driven sensitivity (2030)

Figure 73 presents a summary of the cumulative (annualised) costs associated with investments into the European transmission grids. The variations between the individual scenarios broadly reflect the

differences in transmission expansion as presented above. Annualised cost for Scenario 1 amount to approx. € 4bn in 2030, compared with approx. € 2.8bn for Scenario 2 and € 2.2bn for Scenario 3. Similarly, annualised costs vary between less than € 4bn and almost € 5bn in the variations of Scenario 1. Depending on the scenario, cumulative investments until the year 2030 thus vary between slightly more than € 20 billion and nearly € 50 billion.

Figure 73 Annualised costs of cumulative additional transmission capacity for the main scenarios (1, 2, 3) and the variations of Scenario 1 (EU-28, in MEUR)