European Electricity Grid Infrastructure Expansion in a 2050 Context.

• Author: Egerer, Jonas
• Position: Report

1. INTRODUCTION

   The transformation process of the European electricity sector has become more dynamic in recent years. From a European perspective, the main political drivers are the integration of national markets into one internal energy market (Article 194, European Commission, 2008a) and the reduction of total greenhouse gas (GHG) emissions. Compared to emission levels of 1990, general reduction targets are: i) the 20-20-20 goals, setting national emission reduction targets with an overall reduction of 20% in 2020 (European Commission, 2008b) and ii) the long-term reduction target as stated by the European Commission in the Energy Roadmap 2050 with a reduction of 80-95% by the middle of the century (European Commission, 2011a). In 2014, the European Commission has set a target of 40% for GHG reduction compared to 1990 with a renewable share of 27% for the European Union (EU) in 2030. The electricity sector plays a central role in the realization of these targets as its decarbonization is expected at a faster pace than that of the remaining economy.

   On the contrary, energy policy remains a deeply national domain. National electricity systems historically rely on specific technologies and fuels in electricity supply for geographical and political reasons. It therefore comes as no surprise that the current transformation process varies strongly between individual member states. The national strategies and enthusiasm for the implementation of the 20-20-20 goals vary between member states in their design and ambition as do national renewable support schemes. In addition, there are different points of view on nuclear power and carbon capture, transport, and storage (CCTS) as complementary options in a sustainable energy strategy. These challenges of combining national energy strategies and the vision of a European low-carbon electricity system with high renewable shares become apparent when raising the questions of market design and cross-border integration, with both depending on the physical exchange of electricity by the means of transmission infrastructure.

   This paper analyzes investments in the European high-voltage transmission network for different policy scenarios for electricity generation. A bottom-up electricity sector model assesses the cost-optimal network investments based on national generation portfolios which are disaggregated to a nodal representation of the electricity grid. The techno-economic mixed-integer linear problem (MILP) optimizes investments into voltage upgrades and line expansions in the existing high-voltage alternating current (HVAC) network and investments in additional point-to-point high-voltage direct current (HVDC) overlay lines in steps of ten years until 2050.

   The analysis focuses on the effect of different policy scenarios for electricity supply with regards to i) the reduction of GHG emissions and ii) the technological preferences and their effect on the actual transmission investment needs using a European nodal electricity sector model. The data for the pathways the power sector might take is based on PRIMES results with a national resolution, which have been created during the EMF 28 study (cf. Weyant et al., 2013; Holz and Hirschhausen, 2013). (1) PRIMES has provided official numbers for the Energy Roadmap 2050 of the European Commission (2011a) and has thus undergone a stakeholder process in all member states of the EU. The scenarios in this paper are the reference scenario, with a target of 40% GHG reduction by 2050 without technology restrictions (40%DEF), and two 80% mitigation scenarios. The first mitigation scenario sees no technology constraints (80%DEF) while the second scenario has higher renewable shares and technology constraints on CCTS and nuclear power (80%GREEN).

   The combination of both national and European legislation affects the low-carbon transformation of the electricity system. In this context, top-down energy system models are a suitable tool to determine the least-cost system development for a set of physical, economical, and political scenario assumptions and constraints. While energy system models are capable of representing the entire energy sector, their complexity limits them to an analysis on a national level. Due to spatial aggregation and the resulting simplification of the network topology, energy system models provide limited insights into future infrastructure requirements. Several studies analyze the development of the European electricity system until 2050. Most studies, however, do not represent the transmission grid in detail but aggregate on a country level. (Capros et al., 2012a, b; Dii, 2013; ECF, 2010; Eurelectric, 2010; Hagspiel et al., 2014)

   Calculations for the EU Energy Roadmap 2050 are based on results from the PRIMES model and describe possible pathways for the EU to reach its decarbonization targets while ensuring competitiveness and security of supply. For several scenarios, potential developments are analyzed in all energy-related sectors such as electricity, transportation, industry, and heating. The PRIMES model approximates the European transmission grid, using a single node per country and applies the DC load flow linearization. Country nodes are interconnected by multiple cross-border lines with information (or assumptions, for new lines) on their thermal capacity and their line reactance. Investments in generation and transmission capacity are inter-temporally optimized under perfect foresight. The low spatial resolution of the aggregated transmission grid does not allow for transmission investment on national levels or line-specific N-1 security considerations. (2) The model scope is limited to the EU. Potential imports and exports from and to North Africa are not taken into account (European Commission, 2011a, c, d). In the results, expanding the capacity of the transmission grid is seen as a no-regrets option to be able to "accommodate various power generation pathways" (European Commission, 2011b, p 14).

   The Grid Study 2030/2050 by Troster et al. (2011) determines a more detailed transmission grid expansion for Europe in the years 2030 and 2050, representing the European grid with 224 nodes. It implements the DC load flow linearization and approximates N-1 security with a limit of 80% of the thermal line flow capacity. Fursch et al. (2013) use the same grid model with the addition of endogenous investments into power plants. This allows for a better trade-off between investments into generation, storage, or transmission lines.

   European Network of Transmission System Operators for Electricity's (ENTSO-E) Ten-Year Network Development Plan (TYNDP) gives a detailed perspective on the planned grid expansions in Europe. These grid expansion plans are not solely based on model results but a combination of information provided by different institutions and stakeholders. Parts of the cost benefit analysis include the usage of power system models, including different levels of grid details (ENTSO-E, 2014).

   Compared to existing studies, this paper implements a nodal resolution of the high-voltage transmission network allowing for a detailed spatial representation of load, generation, and electricity flows. The analysis of different exogenous scenarios for possible developments of national power plant portfolios disregards endogenous investment into generation capacity.

   We find that transmission expansion can be seen as an option in the short term, as cross-border expansion takes place in all modeled scenarios. Furthermore, the overall investment structure is comparable to the investments described in the TYNDP. In the long term until 2050, the scenarios with high GHG mitigation targets require more investments than those with a moderate target. The overall inter connector investments of 30bn-60bn EUR by 2050 determined in this paper are generally lower than those specified in the Energy Roadmap 2050 (European Commission, 2011a). Even though the model allows for investments in an overlay HVDC grid, the majority of expansions take place in the existing HVAC network. By 2020, all scenarios suggest investments of about 16bn-19bn EUR. Thereafter, only the high-mitigation scenarios require large additional network investments. The statement of transmission as an option is valid until 2020 with market integration being the main driver. In this period, generation capacities are similar in all three scenarios due to the specific 20-20-20 targets. For the following decades, location and timing of transmission investments do not only depend on the GHG reduction target, but also on the choice of generation technologies. We find that the high-mitigation scenarios are more robust against changes in inter-connector investment cost. Without sufficient information on system development, particularly on the power plant portfolio, flexible infrastructure development might not be possible or might run the risk of stranded transmission investments.

   The remainder of this paper is structured as follows: Section 2 introduces transmission investment decisions in electricity sector modeling and describes the methodology applied in this paper. The data and scenarios are presented in Section 3. Section 4 discusses the quantitative results, and Section 5 provides the conclusion.

2. MIXED-INTEGER TRANSMISSION INVESTMENT MODEL

   2.1 Introduction to Modeling of Transmission Expansion Planning

   Models for transmission expansion planning in electricity networks have to consider many factors. They should include technical network aspects (e.g., flow distribution on lines, losses, and operational questions on network topology and reliability), investment options (e.g., lumpy investments, voltage levels, topology, and options for HVAC and HVDC technology), economic considerations (e.g., costs per investment option and power plant operation), uncertainty (e.g., development of load, generation capacity, and resource prices as well as short-term...