The Impacts of Variable Renewable Production and Market Coupling on the Convergence of French and German Electricity Prices.

Author:Keppler, Jan Horst

    This paper estimates the impact of the amount of production by variable renewables in Germany and market coupling on the spread between French and German electricity prices. This is the first time that these two factors with their opposing impacts on price spreads and welfare have been assessed jointly. Both, production from variable renewables (wind and solar PV) and market coupling, have become decisive determinants of price spreads and efficiency in European electricity markets in recent years and foreshadow the issues confronting electricity markets elsewhere in the years to come. Their welfare effects also pose the question of what should be the appropriate level of interconnection capacity in markets with large amounts of variable renewable production and to which extent market coupling can substitute for such added interconnection capacity.

    France and Germany are the two most important electricity markets in continental Europe, disposing of the two largest European generation systems as well as the highest consumption. Their interaction has a decisive influence on electricity prices all over Europe. While French gains 75% of its electricity from nuclear power, Germany has in recent years invested heavily in wind and solar PV. Their respective capacity today exceeds 36 GW (wind) and 38 GW (solar PV). While in 2014 their share was only 9.9% (wind) and 6.3% (solar PV) of total German production, their impact on electricity prices is far more significant due to their low variable cost and, in particular, their time structure of production, which is clustered around high output hours when it strongly impacts interconnection flows.

    Interconnecting two adjacent areas of electricity production through market coupling absorbs some of those impacts and improves combined welfare by allowing electricity to flow from the low cost area to the high cost area. This lowers prices in the high cost area, raises them in the low cost area and thus has prices in both areas converge. With unconstrained interconnection capacity, price convergence is, of course, complete and the two areas are merged into a single area. With constrained interconnection capacity, the challenge for transport system operators (TSOs) and market operators is using the available capacity in an optimal manner. This is the logic behind the "market coupling" mechanism installed by European power market operators in November 2010 in the Central Western Europe (CWE) electricity market, of which France and Germany are the two largest members. Market coupling aims at optimising welfare by ensuring that buyers and sellers exchange electricity at the best possible price taking into account the combined order books of all power exchanges involved as well as the available transfer capacities between different bidding zones. By doing so, interconnection capacity is allocated to those who value it most. (1)

    Market coupling arose as part of the integration process of European electricity markets on the basis of the collaboration of network operators and market operators and has become a general template for market integration between adjacent countries.

    As predicted by theory, electricity prices in France and Germany converged substantially in 2010 and 2011 in the wake of market coupling (see below for more detailed descriptive statistics) with concomitant welfare benefits. These benefits were shared between both countries. In first approximation, France exports base-load power, while Germany exports peak-load power, thus exporting and importing at different times of the day. However since 2012, electricity prices between France and Germany diverged, a process that accelerated during 2013. The hypothesis this paper is exploring is that this divergence is due to the significant production of variable renewables (wind and solar PV) in Germany, which tends to cluster during certain hours. Typically, solar production around noontime constitutes such an event. However, wind production is also highly auto-correlated and tends to have a significant impact during a limited number of hours of the year. When the production of variable renewables with low variable costs is high, German exports tend to saturate interconnections thus causing price convergence to cease and French-German electricity prices to diverge.

    This article assesses the combined impact of market coupling and production from variable renewables on the spread between French and German day-ahead electricity prices on the basis of three and a half years of hourly data for electricity prices on the EPEX Spot day-ahead market as well on nuclear, wind and solar PV production. This is the first time the effect of solar PV and wind generation as well as market coupling on price convergence is assessed empirically. Previous works on these issues, such as the articles by Pellini (2012) for Italy and by Denny et al. (2010) for Ireland-Great Britain, were based on simulations.

    The structure of the article is as follows. Section 2 provides a brief review of the relevant literature and sets out the contribution of this paper. Section 3 gives some descriptive statistics on price spread and details the mechanism of the French and German power exchanges. Section 4 describes data and the econometric framework. Section 5 presents our main results on the impact of renewable on price spread. Section 6 provides additional results on the congestion of interconnection capacity. Section 7 discusses welfare impacts and Section 8 concludes.


    In December 2008, the European Commission in its 2nd Climate and Energy package decided to promote renewable production in the European energy mix. The target was to reach 20% of renewable energy in the total energy consumption in the EU by 2020. This led to large investments in wind and solar PV, which are characterized by both variable production and low marginal costs. This results in lower average prices, increased volatility and reduced load factors for existing producers of dispatchable thermal power. See, for instance, Woo et al. (2011) in their empirical study of the Texas ERCOT electricity market. In their scenario analysis, MacCormack et al. (2010) also found that wind integration tends to increase average costs of production as the generator capacity factor was declining.

    Due to the low average load factors of solar PV and wind, large amounts of capacity are required to arrive at meaningful contributions to electricity supply. This means that when the climatic conditions are favourable, very sizeable amounts of electricity are produced. Germany's more than 70 GW of combined solar PV and wind capacity corresponds to roughly two thirds of peak demand and is far larger than demand at certain low demand hours (e.g., week-ends), while producing less than 15% of annual demand. This means that at certain hours renewable production is larger than the German electricity system is able to absorb either due to limited demand or due to limited internal interconnections. This indicates a general policy conclusion, namely that higher shares of renewable energy require strengthening internal networks and external interconnections.

    Schaber et al. (2012) computed a model based on historical data in order to assess the effect of grid extensions for the market, with an increasing share of wind capacities until 2020. They found that grid extension helped to reduce the externalities of wind integration. In a similar spirit, Spiecker et al. (2013) developed a model covering 30 European countries which simultaneously optimized generation investments as well as the utilization of transmission lines. Their model confirms that wind integration requires the development of additional interconnection capacities (see also Lynch, Tol and O'Malley (2012)). To our knowledge no econometric studies on the impact of variable renewables in European studies exist for the time being.

    Interconnection congestion remains a frequent by-product of wind and solar generation. The consequence is, of course, price divergence between the two sides of the border. From a social welfare point of view, this price divergence is detrimental to the combined welfare of both countries. With unconstrained interconnections, consumers in the higher price zone would gain more in terms of consumer surplus than what consumers in the lower price zone would lose. Based on a simulation model, Doorman and Frcentsystad (2013) for instance found that developing an HVDC interconnection between Norway and Great Britain would strictly generate an increase in welfare. Physical interconnection extension is also part of the solution proposed by Creti et al. (2010) for the Italian market.

    According to the current trend of European network investments, one should not expect a substantial increase in interconnection capacity anytime soon. In a study of European electricity prices from 2002 to 2006, Zachmann (2008) found that market integration failure was only partially due to the lack of physical interconnection capacities. At the time, the lack of cross-border congestion management was also an important factor in holding back market integration. It is here that market coupling plays its role as an intermediate solution towards market convergence and the efficient integration of variable renewable energy in the European electricity system.

    By aggregating all offers and requests, market coupling optimizes the allocation process of cross-border capacities. In an early study Hobbs et al. (2005) estimated that the welfare impact of market coupling between Belgium and the Netherlands delivered an increase in social surplus only under certain conditions concerning the pricing behaviour of producers. In a more recent study, Ehrenmann and Neuhoff (2009) found through a numerical simulation for the North-Western European network that implicit auction (market coupling) performs better than...

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