The future developments of the electricity prices in view of the implementation of the Paris Agreements: Will the current trends prevail, or a reversal is ahead?
Introduction
On 30th November 2016, the European Commission presented a set of measures, the “Clean energy for all Europeans” package (commonly called as “Winter Package”), to keep the European Union competitive as the clean energy transition changes global energy markets (EC, 2016). The European Union (EU) has committed to cut CO2 emissions by at least 40% in 2030 from 1990 levels, in-line with the EU National ly Determined Contribution in Paris 2015 COP 21 Agreements. Electricity plays a central role in this transition (E3mlab and IIASA, 2017), and the electricity price would be a key enabler for achieving low-carbon end-use sectors. However, the implementation of the “Winter Package” would imply stronger carbon prices, which, together with the volatility of the fuel prices (especially the gas price), will affect the future electricity prices in Europe. In addition, the transition to a low-carbon electricity system would require the deployment of zero short-run marginal cost electricity generation (mainly wind and solar), with a large part of it being decentralised. Since existing electricity markets were designed for regulated and monopolised national electricity systems based on centralised (fossil-based) generation, the restructuring of the electricity supply would also call for structural market changes, which in turn will further affect the future electricity prices in Europe.
In the last years, the transition in the European electricity market was accompanied by a substantial decline in wholesale prices. Fig. 1 presents the average daily wholesale electricity prices from 2010 to 2018 in Switzerland and its four neighbours. The yearly average wholesale price across the five countries dropped by around 20% from 2010 to 2016. This decline is often attributed to the expansion of the renewable electricity generation, which—to a large extent—has been fostered by financial subsidies. For example in Martin de Lagarde and Lantz (2018), the authors apply a two-state Markov switching model estimated with data from the German market and confirm that the renewable production induces frequent and long episodes of low prices. In fact, the effect of renewables in the merit-order (Sensfuß et al., 2008), where conventional thermal power plants are pushed out of the market in hours when electricity from low marginal cost or subsidized renewables is available, has been widely studied in the literature for different countries (see for example Benhmad and Percebois, 2018; Würzburg and Linares, 2013; Lopes et al., 2018; Luňáčková et al., 2017; Welisch et al., 2016; Ray et al., 2010; Bjørndal et al., 2017; Azofra et al., 2014; Keles et al., 2013; Cludius et al., 2014). Almost all these studies showed a consistent impact of renewable electricity on reducing the spot market prices.
However, a growing number of studies considers additional drivers with a significant impact on the electricity prices, such as fossil fuel prices, the CO2 prices and the cross-border flows. Moreover, depending on the time of the day and the season, the impact of these drivers could be higher than the effect of increased wind and solar generation. For example, in Paraschiv et al. (2014) it is found that together with the wind and solar also coal and gas prices have a strong effect on the electricity prices, and in particular in hours with typically high demand. In Dehler et al. (2016) it is noted that even though in their study large gas-based generation capacities are not installed in Switzerland in the future, the gas price drives the Swiss electricity price to a large extent, due to the important role of gas in the Italian market. In Kallabis et al. (2016) it is showed that the largest impact on the German electricity future prices has the CO2 price, followed by the demand and renewable feed-in. In Bublitz et al. (2017) the authors find that the carbon and coal prices mainly caused the electricity price decline from 2011 to 2015 in Germany, and they confirm this result by applying three different types of models: a regression model, a fundamental model and an agent-based model. The findings of all the above studies are confirmed in Fig. 1, where there is an increasing price trend after 2016 when the fuel and CO2 prices started to rise again.
The declining prices of electricity also reduce the ability of producers to cover their capital and fixed costs (Pikk and Viiding, 2013), while at the same time the large shares of variable generation increase the price volatility (Paraschiv et al., 2014). These developments question the ability of producers to exercise “market power”, i.e. the ability to profitably alter prices away from competitive levels (Mas-Colell et al., 1995). Some studies find that there is evidence of strategic behaviour from producers in the wholesale electricity day-ahead market (for example in Weigt and von Hirschhausen (2008), Müsgens (2006) and Pham (2015), especially during the peak hours (Willems et al., 2009), but it lessens over the years as due to decentralised generation and market integration (Mulder, 2015; Möst and Genoese, 2009).
To this end, some questions arise regarding future electricity prices, since the EU commitments in the Paris Agreement affect almost all the key drivers influencing the electricity prices (i.e. demand, fuel prices, CO2 prices and penetration of renewables). For instance, what will be the impact of the current EU energy and climate policy on the electricity prices of the year 2030? Or, given the importance of cross-border flows on setting the wholesale electricity prices, how will increased market integration influence the spot prices in the year 2030? Moreover, as it is expected that the producers' bidding curves will be altered because of the deployment of large shares of low marginal cost electricity generation, will there still be strategic behaviours in the market, and will the deployment of large-scale electricity storage (to cope with the variability in the future generation and demand) influence the wholesale electricity prices?
To provide insights regarding the above questions, we assess the impact of the policies and measures of the “Winter package” in Switzerland and its four neighbouring countries. The five countries have very distinct characteristics, which all of them help in forming a very interesting case study regarding the structure of the electricity market. In Germany, there is a high share of variable renewable generation, in Italy gas prices play a key role in forming the electricity prices, in France the nuclear power dominates the domestic electricity mix, while Switzerland is an electricity trade hub with its price being influenced by the cross-border flows and neighbouring markets. We also include in our assessment Austria, which currently forms a single zone with Germany but a market splitting is foreseen from October 2018 (Eike Blume-Werry, 2017).
We employ a newly developed model at the Paul Scherrer Institute, the crossBorder Electricity Market (BEM) model (Panos et al., 2017). The model represents different electricity producers (market players) that invest in electricity capacity expansion and make their operating and unit commitment decisions to supply an elastic demand. The players own a portfolio of power plants located at different nodes in the transmission network, and a player can have power plants in more than one country. The model can run in two modes: a) game-theoretic, in which each player maximises its net profit; or b) social welfare maximisation across all the five countries. This built-in dual formulation of the model, together with its high technical detail, allows BEM to be a suitable tool for capturing the level and the volatility of today's prices and assessing the impact of main drivers on the wholesale electricity prices. With the BEM model we evaluate two core scenarios: a) a Base scenario which is a continuation of existing trends and which is compatible with the EU reference scenario (EU, 2016); and b) a Low Carbon scenario that implements the Paris Agreements of EU and which is compatible with the “Winter package” scenarios (E3mlab and IIASA, 2017). We also complement our analysis with additional insights for the future development of the electricity prices concerning different levels of fuel and CO2 prices, the availability of large-scale batteries for wholesale trading, and different levels of market integration.
The aim of our analysis is not to provide a forecast of the electricity prices in 2030, but an impact assessment of the energy and climate policy of the EU on future prices via what-if scenario analyses. To the best of our knowledge, so far few studies have provided insights on this topic in the context of the climate change mitigation objectives of the EU. One study employed the PRIMES model to quantify the EUCO scenarios for the European Commission (E3mlab and IIASA, 2017). A second study applied the PLEXOS model on the results of PRIMES to quantify price effects (Collins et al., 2017), and a third study applied the REMIX model to quantify again the impact of the EU energy and climate policy on electricity prices (Borggrefe, 2017). In this sense, we contribute to the existing literature regarding modelling methodologies for electricity markets, and we complement existing assessments concerning the impact of the current European energy and climate policy on the wholesale electricity prices.
The rest of the paper is organised as follows. In the next section, we briefly describe the BEM model and provide insights about its key features and its calibration. In part 3, we discuss the results from the two core scenarios and their variants with respect to the electricity generation capacities, demands, supply mixes and prices. We summarise and conclude in Section 4.
Section snippets
Short description of the BEM model
As stated in the introduction, the BEM model can represent either a Nash-Cournot game or a social-welfare maximisation problem of the electricity markets. In the game-theoretic setup, the market players invest in electricity expansion capacity and make their operating decision and plant dispatching in the day-ahead market to supply an elastic demand. We adopt the open-loop formulation (Wogrin et al., 2013), in which the capacity expansion and energy production decisions are taken
Results
In this section, we briefly present the new capacity additions and the electricity supply mix in 2030. We mainly focus on the development of electricity prices and the insights gained from the additional variants regarding the prices' main drivers.
Discussion and conclusions
In this study, we assess the impact on the electricity prices from the implementation of Paris Agreement climate targets in Switzerland and its neighbouring countries (as it is implemented in the EU and Swiss energy and climate strategies). We focus the analysis on the year 2030, which is the year with concrete climate change mitigation policies in these regions at the time of the study. For the assessment of the electricity wholesale price, we employ a fundamental model, which can be
Acknowledgements
This study is based on research funded by the Swiss Federal Office of Energy in the context of the project with the title “Oligopolistic capacity expansion with subsequent market-bidding under transmission constraints” with contract number SI/501119-01, and by the “Swiss Competence Centre for Energy Research – Supply of Electricity (SCCER-SoE)” with contract number CTI-1155002546. We are thankful to the anonymous reviewers because their comments and suggestions contributed to the improvement of
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