The role of cross-border power transmission in a renewable-rich power system – A model analysis for Northwestern Europe

This study quantifies the economic potential of cross-border transmission to a decarbonized future Northwestern European power system through the energy model Balmorel. A scenario with modelled optimal transmission capacity at lowest total system costs is compared to the scenario with given capacity level of existing and planned projects. Increased transmission investments decrease total system costs and regional price difference. It benefits particularly wind power deployment and thus, lowers CO2 emissions in the power and heat sector. The impacts are, nevertheless, distributed asymmetrically to northern and western stakeholders. Northern consumers receive higher power prices, but the revenues of wind and hydropower producers also increases. Meanwhile, western consumers receive lower power prices, but gas power producer revenues decrease.


Introduction
Large deployment of renewable energy sources is one of the major means for decarbonization in the energy sector. It is, however, well known that fluctuating characteristics of wind and solar power brings new technical and economic challenges to the energy system. To address these challenges, more solutions providing energy system flexibility are needed (Sovacool et al., 2018). The flexibility may be provided by increased supply side flexibility, new storage solutions or increased demand side management (Blumberga et al., 2015;Cebulla et al., 2017;Kirkerud et al., 2017;Skytte et al., 2017;Sneum et al., 2018;Soder et al., 2018;Tveten et al., 2016a;Vithayasrichareon et al., 2017). The main challenges for large-scale implementation are, however, high costs and/or low technical maturity for many of these options.
One potential option is increasing the interregional transmission capacities in accordance with the growing shares of variable renewable energy (VRE). Fundamentally, transmission lines are to send power from where it is generated to where it is used. Interconnecting regions opens up possibilities to exploit clean power from further or better sites and provides spatial flexibility. A larger and more diverse energy system can potentially lower total costs of energy transition (Ahmed et al., 2017;Boie et al., 2016;Tveten et al., 2016b). Indeed, to ensure meeting climate targets without sacrificing security of supply, several large-scale transmission projects are under construction or planned in Europe in the following decade (ENTSO-E The European network for transmission system operators electricity, 2018;European Commission, 2017). An economic model by (Abrell and Rausch, 2016) have noted that transmission expansion benefits emission abatement only with increased renewable energy penetration, which coincides with European energy policy.
Some previous publications have studied the benefits of transmission in the context of fully renewable or low emission European power system. Results from Rodriguez et al., 2014) have shown that transmission mitigates the need of backup energy (Schlachtberger et al., 2017. have performed a thorough analysis on cost benefits from zero to optimal grid expansions reaching a 95% CO 2 emission reduction target (Child et al., 2019). has urged that 100% renewable energy power sector by 2050 is achievable in Europe and increased transmission grids can contribute to faster defossilization at a lower cost. Nevertheless, cross-border transmission projects are complex and require long planning periods (Khuntia et al., 2016;Kishore and Singal, 2014). Several studies have also identified lack of appropriate regulatory design and coordination as main barriers and institutional change might be required (Andersen, 2014;Battaglini et al., 2012;Bergaentzle et al., 2019;Rumpf and Bjornebye, 2019). Increased local and general oppositions against power lines are also observed because of their health, visual and environmental impacts, but not least due to the fear of higher power prices in the exporting regions (Aas et al., 2014;European Commission, 2017). Realization of transmission projects can thus be uncertain, and it leads to further difficulties on national generation adequacy planning (Jaaskelainen et al., 2018).
The Northwestern European energy system should be particularly well suited for high geographical integration. The northern areas have abundant flexible hydropower. Other areas, like Denmark, have good potential of onshore and offshore wind power. Areas further south are well suited for solar PV and with larger energy markets. European countries have had successful experiences on emission reduction through Burden-Sharing Agreement, taking both efficiency and equality into account (Marklund and Samakovlis, 2007). Cross-border transmissions can also be seen as a physical form of regional efforts on emission reduction. Against this background, the objective of the present paper is to analyze and quantify how different levels of cross-border transmission capacities affect the power system and the power market in a decarbonized future towards 2050 in Northwestern Europe. We do so, by comparing model results from a detailed energy system model (Balmorel) where the transmission capacity is: (i) kept constant at the current and planned level by 2030, and (ii) allowed for additional investments in accordance with the system optimal levels.
Electric systems are complex to model by nature, in addition to the lack of transparent information from grid operators. This paper compares within the Balmorel energy system model two approaches of modelling existing transmission grids to better reflect physical flows in Northwestern Europe. Our study stands out by showing endogenousdetermined generation and transmission capacities along a pathway to 2050. We reflect potential generation investment change as a result of increased competition, instead of ignoring generators response as criticized strongly by (de Nooij, 2011). Furthermore (Schlachtberger et al., 2017, have pointed out the potential influence from other energy sector and (Thellufsen and Lund, 2017) has demonstrated the decreased benefits of transmission from sector coupling. Our model also includes the district heating sector to reflect possibility of power and heat coupling (combined heat and power generation as well as power-to-heat), although this is not emphasized in the result section below.

General model design and assumptions
The analysis is performed with the open source energy system model -Balmorel (Wiese et al., 2018), programmed in GAMS language. It finds the optimal solution at the lowest total system costs, using partial equilibriums simulating electricity and district heat generation by bottom up approach. The solution satisfies a set of constraints, including (but not limited to) energy balance, technology operations, resource availability and regulatory constraints. This study uses the model version developed within Flex4RES project (Nordic Energy Research, 2018).
The objective of the model is to supply electrical and heat energy to cover demand in the modelled system: therefore, the demand-side consumption profile variation is a major driver of flexibility need. VRE such as supply from wind turbines and PV panels are another major source of flexibility need. Although their generation can be curtailed, the available power generation is constrained by the availability of the relevant resource. Inflexibility from demand and VRE is matched by a variety of flexibility options in the model: conventional thermal power plants, electricity-and heat storages, reservoir hydro power plants, power-to-heat technologies and cross-regional transmission capacity. The amount of hydro power plants is assumed to be constant throughout the modelling period, because of the assumption that the majority of feasible hydro power sites have already been utilized. The amounts of conventional, VRE generators, storages and power-to-heat technologies in the system are an endogenously modelled based on cost minimization principle. Flexibility from demand-side management, electric vehicles has not been considered in this modelling exercise.
The studied period covers the base year 2016 and every decade from 2020 to 2050. For an efficient but representative calculation, we aggregate modelled time series in a year into four seasons with 24 h each by duration curves and energy demand and renewable resource profiles in 2012, taking spatial and temporal correlations into account. The modelled countries consist of countries from Northern Europe (Nordics and Baltics, excluding Iceland) and from Western Europe (Belgium, Netherlands, France, Germany, Poland and the UK). In this analysis, most of our discussions focus on these two aggregated parts of Europe.
Costs and technical data of technologies, existing generation and transmission capacities, planned commissioning and decommissioning, energy demand, fuel and emission prices are determined exogenously.  (Lundgren et al., 2015). Endogenously defined new power generation and storage capacity investments are allowed from 2020 and the decisions are made with a myopic view of the current modelled year.

Transmission modelling
This study models the transmission grid in a simplified manner, by depicting transmission capacities between regions. Nordic and Baltic countries are divided as in the bidding areas in the European power exchange Nord Pool (Nord Pool). The other countries are modelled as one region itself, except Germany which is divided into four regions. One aggregated line is assumed across two regions. This study uses two different approaches to model transmission grids: net transfer capacity (NTC) and flow-based (FB). The NTC approach is a more conservative method. To avoid physical power line constraints, both AC and DC grids are modelled as DC lines but use only the capacities that is always feasible regardless operation modes. The FB approach approximate actual power flows by power transfer distribution factors (PTDF) and line capacities. It relaxes capacity constraints compared to the NTC approach and allows more efficient grid utilization.
The mathematical formulation of the NTC approach is z NTC � z NTC , where power flow z NTC is bounded by the maximum line capacity z NTC . Same restriction applies in the FB approach that z FB � z FB , where power flow z FB is bounded by the maximum line capacity z FB . The magnitude of the maximum line capacities in the two approaches are different. NTC capacities (z NTC ) are artificial flow potentials, calculated and published by the transmission system operator (TSO) in advance for market operators. FB capacities (z FB ) are actual thermal limits of transmission lines. In addition, the flow dependencies in AC grids are described by PTDF � NEB FB � z FB in the FB approach. The PTDF is a dense matrix showing the inverse of the sparse line reactance matrix and it distributes flows according to the net balance NEB FB at every single node in the system. As a TSO has to take into account all potential flows within a longer period, z NTC is usually a conservative estimation. Contrarily, the FB approach allows for continuous updates on e.g. hourly basis which allows for a better utilization of the lines for the respective hour and system status. Therefore, the feasible operation space with the FB approach is equal or larger than the NTC approach, but at the same time, it accounts physical flows from the AC system in the model. Fig. 1 illustrates potential operation modes and feasible areas in both approaches.
In this study, both approaches are applied to existing AC transmission grids and results are compared. Any new grid is modelled by NTC approach i.e. as DC lines, to maintain a reasonable calculation time. Existing and announced grid capacities refer to PyPSA-Eur (Horsch et al., 2018) and grid development plans (ENTSO-E The European network for transmission system operators electricity, 2018). Fig. 2 demonstrates the geographical modelling scope with the aggregated AC and DC transmission lines in the FB approach. Cost data of new transmission capacities are in principle derived from or estimated by established projects, assuming an annuity payment factor of 4.5% over 40 years. Table A.2 lists the total investment costs of transmission lines per capacity by connecting regions.
An efficiency of 95.8% and operation and maintenance cost of 0.1€ per MWh is applied to all transmission lines. In addition, lines have capacity rating at 90% to simulate potential power line outages.

Studied scenarios
This study aims to demonstrate impacts of cost-optimal level of transmission capacity, compared to existing and planned level. The reference scenario "Planned", as described in (i) in the introduction section, represents limited transmission expansion, causing by possible opposition or late planning. The "Optimal" scenario, as described in (ii) in the introduction section, removes constraints on transmission capacity expansion. Additional transmission capacities can be invested from 2030 in order to reach least system costs.

Optimal transmission capacities
The modelling results demonstrate significant difference between the planned and the optimal level of transmission capacity expansions. Fig. 3 illustrates the results by the transmission modelling approach of existing AC grids in FB and NTC approach. In both approaches, exogenous and endogenous transmission expansions since 2030 are modelled as DC lines. Note that only cross-border transmission capacities are discussed here.
Applying FB approach implies more existing grid capacities can be used, compared to a more conservative NTC approach. Although it potentially requires indirect transmission expansion, the optimal solution shows an overall 15 GW less of optimal cross-border transmission expansion. In the FB approach, while the planned cross-border transmission projects include around 21 GW by 2030 (half of which within western countries), the optimal investment suggests additionally 44 GW (half of which connect west and north). From 2030 to 2050, the optimal investments of cross-border transmission capacities reach over 76 GW. Compared to the planned capacity expansion by 2030, the additional endogenous investments between 2030 and 2050 suggest around four times more of the planned scale. The NTC approach suggests 20% more of endogenous investments compared to the FB approach. Fig. 4 disaggregates the capacities by connecting countries and reveals further details by showing differences between optimal and planned capacities by 2050. In FB approach, the optimal scenario has close to 10 GW more of the capacity compared to the planned scenario in Fig. 1. Illustration of the feasible areas in an AC grid of two power flows from one node to region r1 and to region r2 in the NTC approach (red) and the FB approach (green). Black lines are the flow constraints from different transmission lines in the grid. Poland-Germany, the UK-France, Sweden-Denmark and the UK-Norway. The connection of Sweden-Poland is a completely new endogenous investment of 4.6 GW. Meanwhile, several lines do not increase their capacities endogenously, namely Belgium-Netherlands, Germany-Netherlands, Netherlands-the UK, Lithuania-Sweden, Germany-Norway, Netherlands-Norway and Denmark-the UK, apart from the planned ones. Some connections require more capacities, compared to NTC approach, even though the total amount decreases, reflecting complexities of AC and DC grid modelling due to physical constraints.

Power generation capacity mix
The development of installed power generation capacity in the planned scenario is shown in Fig. 5. As a result of coal and nuclear decommission policies, as well as increasing carbon prices, VRE is to a large extent replacing fossil fuels towards 2050 in both western and northern regions. The required capacity for a secure energy supply increases with increasing VRE share.
The modelling of endogenous grid investments shows that when optimal transmission capacities are in place, more renewables can substitute fossil fuels. With the FB approach, 26 GW of wind from Northern Europe together with 13 GW of wind in Western Europe replace 30 GW of fossil fuel based generation in the west (Fig. 6). Although other renewables also have more installed capacities, increased transmission capacities benefit significantly more to wind than to other renewables because it has more diverse production profiles across geographic regions, compared to solar PV that has more uniform generation profile. Higher transmission capacities provide compensating possibilities from wind power to other regions. Wind resource is also better in the north than in the western regions in the sense of full load hours and generation profiles, which leads to lower costs of new wind energy and more extensive investments into wind in the north than in the west when transmission capacity is large enough. Fig. 7 shows the modelled relationships between assumed EU ETS prices and total CO 2 emissions from the power and district heat sectors for both scenarios. From 2030, fossil-based power generation is largely replaced by renewables because of both decommissioning policies and higher carbon prices, but it still leaves over 263 million tons of CO 2 emissions. In 2050, emissions are further reduced to 69 million tons. Allowing more transmission capacities contributes to further 25% emission reduction in 2030 and brings the emission down to 24 million tons in 2050.

Emission impacts
With the assumed carbon prices, Northern European countries almost achieve their carbon neutral target by 2050 without additional transmission capacities.    reduction are, however, more obvious in western region where currently thermal power dominates (Table 1).

Power prices
The annual prices in Fig. 8 are represented by chronological averages of marginal costs of electricity. Increased transmission lines lift average prices of all modelled countries up a little but decreases spatial and temporal price differences. Taking Norway and the UK as an example, in 2020 with 1.4 GW of planned interconnector, the price difference stay around 25€ per MWh until 2050. If the transmission capacity between the two countries expands 10 GW more by 2050, the price difference decreases to 10€ per MWh instead. Increasing transmission lines shifts up prices in low-price regions (i.e. Norway), drives down prices in high-price regions (i.e. the UK) and leads to closer relations of power prices between connecting regions.

Distributional effects
Allowing optimal transmission capacities lowers the total system costs (Fig. 9). Additional transmission investments replace parts of fuel and emission costs. It is a win for all modelled countries as one in the economic aspect.
However, benefits from transmission lines are distributed asymmetrically not only among producers and consumers but also in different countries. Fig. 10 shows the modelled producer revenues and consumer costs in 2050 of the planned scenario and the optimal scenario. Producer revenues are defined as sum of spot prices multiplied by power generation in each hour and consumer costs are defined as sum of spot prices multiplied by power consumption. For gas power producers in western region, revenues from power generation decrease by 4 billion euros when more transmission capacities are in place. Nuclear power producers receive a billion-euro higher revenues in the optimal scenario though. In addition, consumers in western countries can save almost 6 billion euros, equivalent to 3€ per MWh. Northern power producer revenues increase by 8 billion euros. The biggest winners are hydropower producers that count half of the increase, followed by wind power producers with the highest growth rate of 67%. But the consumer costs of electricity in the Northern countries increase by 3 billion euros, equivalent to 21% higher per unit of electricity. The unequally distributed benefits among stakeholders within and between countries needs to be addressed by authorities in order to utilize the flexibility potential of increased transmission grids. If addressed well, it might help gain local supports as in wind farm experiences (Mulvaney et al., 2013;Warren and McFadyen, 2010).

Conclusions
This paper quantifies the economic impacts of cross-border transmission in Northwestern Europe using an energy system model which includes a detailed representation of the power as well as the district heating sector. The "planned" scenario defines transmission capacities exogenously as the existing level in 2016, plus the planned level by 2030, remaining constant until 2050. In the "optimal" scenario, the model additionally allows endogenous transmission investments from 2030 to 2050. We adapt both FB and NTC approaches to model existing grids but focus on results from FB approach. All new grids are modelled by NTC approach or as DC lines.
The optimal scenario suggests additional 76 GW of cross-border transmission capacity expansion from 2030 to 2050, which is almost four times of the planned expansion (21 GW) by 2030. With increased transmission capacity in place, more wind power is installed to substitute fossil fuel based energy, contributing to 40% less of total emission between 2030 and 2050. Total system costs also decrease by more than 5% in the "optimal" scenario relative to the "Planned" scenario. Benefits from higher transmission capacities are, nevertheless, asymmetrically distributed among regions and players. In terms of generation technologies, wind power benefits significantly more than any other technologies, including solar PV, thanks to its diverse spatial production profiles. In terms of regions, Western European countries experience decreases in producer revenues and consumer costs, while the opposite happens to Northern Europe. In average, western consumers pay 6% less per unit of electricity, but prices for northern consumers are 21% higher. The study demonstrates why internationally asymmetric benefits and costs is likely a main barrier to increased power exchange cooperation in the future but it also indicates potential resolutions through cooperation and proper policy design. Policies that can mitigate these distributional effects are probably necessary for a full utilization of the large benefits of high transmission line capacities in renewable-rich power systems.
The results of this study can support energy system planners and investors on their decision-making and reinforce the importance of cross-border power transmission in the energy transition context.

Acknowledgement
This paper has been prepared under the "Flex4RES" (www.flex4RES. org) research project, supported by Nordic Energy Research (Grant: 76084) and the "NorENS -Developing the Norwegian energy system in the European energy transition project" financed by the Norwegian Research Council (Grant: 280987). The authors are grateful for the supports from the project partners and the organization. Furthermore, we wish to thank the reviewers of this article for their variable feedback, leading to relevant revisions of the study.  10. Modelled difference in producer revenues by fuels and consumer costs between the optimal and the planned scenarios in 2050 with FB approach of existing transmission grids in Western and Northern Europe.