The Short and Long Term Impact of Europe's Natural Gas Market on Electricity Markets until 2050.

• Author: Abrell, Jan
• Position: Report

1. INTRODUCTION

   The transition of our fossil based electricity systems towards a renewable based system is often linked with natural gas as important transition fuel (EC, 2011a). Flexible combined cycle gas fired power plants are seen as low emitting backup for the transition (EC, 2011b). Naturally, the role of gas in the electricity market strongly depends on the developments on the gas market itself as well as coal and carbon markets. This interrelation is highlighted by the current developments in the European electricity market: despite increasing renewable shares the output of gas fired plants reduced from 462TWh in 2012 to 365TWh in 2014. At the same time the installed gas capacity increased from 193GW to 212GW (ENTSO-E, 2015). This divergence shows the uncertainties involved with respect to the role of gas in electricity systems. Similar changes, but in the other direction take place in the US with the "shale gas revolution" pushing gas plants into and coal out of the electricity market.

   In addition, uncertainties on the gas supply side and availability of import capacities, i.e. the Russia-Ukraine conflict and the unstable political conditions in North Africa, have put supply security back on the European political agenda. Some countries and regions within the European Union are dependent on a small number of suppliers, which makes them vulnerable to (temporal) supply disruptions. South European countries (Italy and increasingly Spain) depend on pipeline imports from North Africa (Algeria, Libya) and use liquefied natural gas (LNG) to diversify their supplies. Central and South East European countries import almost exclusively from Russia and the current network topology does not allow them to quickly change this import pattern. Storage and reverse flow capacities (to import from the West to the East, opposite the traditional direction from the East / Russia to the West) are put forward as remedies to increase their security of supply, in addition to increasing the number of import routes (Richter and Holz, 2015).

   Parallel to the long run uncertainties there is also a strong interdependence on the short time dimension, especially with respect to the spatial availability of gas supplies. An example is the cold spell in continental Europe during winter 2012 sending electricity demand in France to a long-time high of 100 GW. As the export capacity of German nuclear power plants had been shut down following the moratorium after the Fukushima accident gas fired plants in South Germany could have stepped in. However, they could not substitute for the loss of power from the nuclear plants due to a lack of access to natural gas pipeline capacity. At the same time, plenty of natural gas was transported from Austria and South Germany to Italy (EC, 2012). While rolling blackouts have been avoided due to active demand management by the French operators, the issue of electricity-natural gas interdependence was launched and led to a major enquiry by the European Commission.

   Summarizing all those relevant aspects in both markets, it becomes evident that a combined assessment is needed to derive solid recommendations about the future development of European energy markets. The objective of this paper to evaluate the feedback effect of different short and long run natural gas market developments on the European electricity market.

   Many model based analyses of energy markets either focus on a single sector and aim to be detailed with respect to the underlying market characteristics or they are aggregated energy system models that naturally have to include simplifications on time and spatial dimensions (see e.g. Herbst et al., 2012 for a general energy modeling review).

   There is a large stream of literature addressing the development of electricity markets and networks in the wake of an increased share of RES (e.g. Neuhoff et al., 2008; and Egerer et al., this issue). Studies like ECF (2011) and SRU (2010) determine possible development paths for the European electricity system. Investment needs in grid and generation infrastructure, based on renewable targets and potentials, is determined mostly in a cost-minimizing or welfare-maximizing way. Similar, several papers address the market structure and development of the European and global natural gas markets often with a large focus on the Russian-European relations (e.g. Egging et al., 2008, 2010; Dieckhoner et al., 2013). These gas market models have different degrees of spatial network representation and strategic aspects covering optimization and equilibrium models. Depending on their focus those single sector models can either be designed as short term or long term models. However, those models need to account for changes on the respective up-stream or down-stream market impact by adjusting the respective parameters (i.e. gas prices or demand by gas fired electricity plants).

   Large scale energy system and macroeconomic models allow keeping those relations endogenous to the model as they cover the interrelation between fuel markets or/and the economy as a whole. However, due to the scale of those models they are typically limited to long term relations. Furthermore, as they have to keep the system representation aggregated they often lack detailed network characteristics. Examples are Capros et al. (1997), Paltsev et al. (2005), Most and Perlwitz (2009), IPTS (2010), and Capros (2010).

   This paper combines bottom up representations of the European electricity and natural gas market and examines the impact of different pathways of European carbon and renewable policy on electricity and natural gas infrastructure. Our approach allows extending the more detailed single market evaluations with an assessment of interaction effects accounting for network aspects, especially loop flows in the electricity market, seasonal and daily market dynamics, as well as long term investment incentives. Albeit being more simplified in its respective market representations than single market models the results can provide addition insights providing a more comprehensive overall assessment.

   The research objective is to evaluate the infrastructure implications of the envisioned European energy transition. Given the coupled nature of our model approach this objective is addressing three related topics: First, the supply security of the European energy system, especially the relation between Russia and Europe. Second, the policy interrelation of Europe with a multitude of energy and environmental objectives and subsequent policies interacting on the markets. And finally, the influence of the vertical relation between and interdependence of energy markets for the future development. To provide a comprehensive evaluation of those topics we perform a three-stage analysis. First, we aim to get a better understanding of the importance of policy and market developments in the electricity-gas nexus by evaluating a selection of different carbon and renewable scenarios using the coupled model. Second, we perform alternative long term gas market scenarios to capture their impact on power plant investments. Finally, we design short run supply shock scenarios to analyze spatial feedbacks towards the electricity system under different power plant configurations

   From a methodology point the coupling approach applied in this paper is in line with existing models as the coupling of electricity and gas market models has gained increasing attention in recent years (see e.g. Unsihuay et al., 2007; Rubio et al., 2008; Liu et al., 2009; Damavandi et al., 2011; Duenas et al., 2012; Spiecker, 2013; Erdener et al., 2014). The research focus is largely on the techno-economic short term relation between both markets. Few combined models include endogenous investments (e.g. Geidl and Andersson, 2006; Unsihuay-Vila et al., 2010; Linert and Lochner, 2012; Chaudry et al., 2014; Abrell and Weigt, 2016). Our model follows these approaches to evaluate the future European electricity scenarios by including an endogenous natural gas market representation. In contrast to Abrell and Weigt (2016) the paper at hand is focused on long term market evaluations and the feedback effect from different gas market developments on electricity generation investments.

   The remainder of this paper is structured as follows. Section 2 presents the combined model and the underlying data. Section 3 provides the central scenario results. Section 4 and 5 present the long and short run feedback effects, respectively. Section 6 summarizes and discusses the main findings and concludes.

2. MODEL AND PARAMETERIZATION

   2.1 The model

   The model in this paper allows for a combined natural gas and electricity sector representation, both taking into account the respective sector's transmission grid and how they can be run independently of one another or in a combined manner (Figure 1). The natural gas model, which is shown on the left hand side of Figure 1, depicts pipelines, LNG routes, and seasonal storage. The arcs in the pipeline network are directed, i.e. the natural gas flows in a predetermined direction given by the compressor stations in the pipeline network. As we aggregate all cross-border pipelines into one representative pipeline we capture backflow alternatives by using two opposing directed pipelines for each border with respective flow capacities. LNG routes are treated similar to pipelines with the regasification capacity at the receiving node being the pipeline capacity.

   The electricity model, which is depicted on the right side of Figure 1, includes the transmission grid using a DC-loadflow approach (Schweppe et al., 1988; Leuthold et al., 2012). Electricity generators sell at their respective node while the system operator handles exchange and congestion. Short term storage in form of pumped-storage hydropower allows the transfer of energy between load segments. Contrary to the natural gas market seasonal storage is not possible...