European Electricity Market Research Articles

The Market Value of Variable Renewables

The income that wind and solar power receive on the market is affected by the variability of their output. At times of high availability of the primary energy source, they supply electricity at zero marginal costs, shift the supply curve (merit-order curve) to the right and thereby reduce the equilibrium price of electricity during that hour. The size of this merit-order effect depends on the amount of installed renewable capacity, the slope of the merit-order curve, and the intertemporal flexibility of the electricity system. Thus the price of wind power falls with higher penetration rates, even if the average electricity price remains constant. This work quantifies the effect of variability on the market value of renewables using a calibrated model of the European electricity market. The relative price of German wind power (value factor) is estimated to fall from 110% of the average electricity price to 50% as generation increases from zero to 30% of total consumption. For solar power, the drop is even sharper. Hence competitiveness for large-scale renewables deployment will be more difficult to accomplish than often believed.

On the Efficiency of the EPEX Day-Ahead Spot Market

In this paper we investigate the efficiency of the day-ahead market for electricity at the EPEX, the largest central European market for electricity. To analyze whether generating companies use their market power to influence prices, we used a conjectural variations approach for the years 2007-2010 on a yearly basis as well as a direct approach for estimating marginal costs for the year 2010. The results of both approaches show no indication for systematic abuse of market power by the suppliers of electricity on the EPEX day-ahead spot market for the analyzed period of time. Conducting the same analysis for high load hours, which are generally considered to be the most prone to market manipulation, yielded similar results suggesting that the results are robust. For our analysis, we considered hourly price and demand data and consequently obtained a high level of statistical significance in our models.

District heating and ethanol production through polygeneration in Stockholm

Ethanol can be produced with little impact on the environment through the use of polygeneration technology. This paper evaluates the potential of integrating a lignocellulosic ethanol plant into a district heating system by case study; the plant has an ethanol capacity of 95 MW with biogas, electricity and heat as by-products. Stockholm’s district heating system is used as the case study, but the results may be relevant also for other urban areas. The system has been studied using MODEST – an optimisation model framework. The results show that introducing the plant would lead to a significant reduction in the cost of heat production. The income from the biofuels and electricity produced would be about €76 million and €130 million annually, respectively, which is an increase of 70% compared to the income from the electricity produced in the system today. Assuming that the electricity produced will replace marginal electricity on the European electricity market and that the biofuel produced will replace gasoline in the transport sector, the introduction of the polygeneration plant in the district heating system would lead to a reduction of global CO 2 emissions of about 0.7 million tonnes annually.

Sustainability and reliability assessment of microgrids in a regional electricity market

We develop a framework to assess and quantify the sustainability and reliability of different power production scenarios in a regional system, focusing on the interaction of microgrids with the existing transmission/distribution grid. The Northwestern European electricity market (Belgium, France, Germany and the Netherlands) provides a case study for our purposes. We present simulations of power market outcomes under various policies and levels of microgrid penetration, and evaluate them using a diverse set of metrics. This analysis is the first attempt to include exergy-based and reliability indices when evaluating the role of microgrids in regional power systems. The results suggest that a power network in which fossil-fueled microgrids and a price on CO2 emissions are included has the highest composite sustainability index.

A Generalized Nash Equilibrium Model of Market Coupling in the European Power System

“Market Coupling” is currently seen as the most advanced market design in the restructuring of the European electricity market. Market Coupling, by construction, introduces what is generally referred to as an incomplete market: it leaves several constraints out of the market and hence avoids pricing them. This may or may not have important consequences in practice depending on the case on hand. Quasi-Variational Inequality problems and the associated Generalized Nash Equilibrium can be used for representing incomplete markets. Recent papers propose methods for finding a set of solutions of Quasi-Variational Inequality problems. We apply one of these methods to a subproblem of market coupling namely the coordination of counter-trading. This problem is an illustration of a more general question encountered, for instance, in hierarchical planning in production management. We first discuss the economic interpretation of the Quasi-Variational Inequality problem. We then apply the algorithmic approach to a set of stylized case studies in order to illustrate the impact of different organizations of counter-trading. The paper emphasizes the structuring of the problem. A companion paper considers the full problem of Market Coupling and counter-trading and presents a more extensive numerical analysis.

Fruitful symbiosis: Why an export bundled with wind energy is the most feasible option for North African concentrated solar power

The idea of generating electricity in North Africa using concentrating solar thermal power (CSP) has been around for some time now but has recently gained momentum through the Mediterranean Solar Plan (MSP) and the formation of the Desertec Industrial Initiative. This paper argues that while the large-scale deployment of CSP in North Africa does not seem economically attractive for either European or African institutions or countries on their own at present, combining domestic use and electricity exports could be profitable for both parties. A detailed economic portfolio covering both solar and wind power plants can achieve competitive price levels, which would accelerate the diffusion of solar technology in North Africa. This portfolio could be financed partially by exporting electricity from solar thermal plants in North Africa via HVDC interconnections to European consumers. Sharing the costs in this way makes it possible to generate solar electricity for the domestic market at a reasonable cost. Some of the electricity produced from the solar power plants and wind parks in North Africa is sold on European energy markets in the form of a long-term contracted solar–wind portfolio, which would qualify for support from the financial incentive schemes of the European Member States (e.g. feed-in tariffs). This transfer of green electricity could help to meet the targets for energy from renewable energy sources (RES) in the EU Member States as the new EU Directive of 2009 opened the European electricity market to imports from third states.

Cross-border integration in the European electricity market. Evidence from the pricing behavior of Norwegian and Swiss exporters

This paper examines the electricity market integration process in two European areas based on the pricing behavior of Norwegian and Swiss exporters. The aim is to gain evidence for the period after the adoption of the “Second Legislative Package” (2003). The pricing behavior of Norwegian exporters indicates that the wholesale markets for Denmark and Sweden are highly integrated. Moreover, results are fully compatible with the existence of a very competitive marketplace for electricity. This clearly contrasts with the evidence provided by Swiss exporters. In this last case, analysis revealed differences in pricing-to-market behavior between Italy, France and Germany, which indicates that exporters take advantage of international market segmentation and divergences between market structures. This outcome provides a reasonable explanation as to why price differences between countries cannot be fully attributed to transmission costs, as has been claimed in previous research. We also found cross-country convergence in levels of markups and in pricing-to-market behavior of the Swiss exporters for the first part of the period that was analyzed. The evidence is fully consistent with an initial impulse toward market integration originated by reforms implemented at the beginning of the last decade.

Security of Supply and Electricity Network Flows after a Phase-Out of Germany’s Nuclear Plants: Any Trouble Ahead?

This paper, which examines the impacts of phasing out nuclear power in Germany, is the first to include an analysis of energy supply security and critical line flows in both the German and Central European electricity networks. The technical-economic model of the European electricity market, ELMOD, is used to simulate alternative power plant dispatch, imports, exports, and network use for a representative winter day. The results suggest that the shutdown of Germany’s nuclear plants will result in higher net imports, especially from the Netherlands, Austria, and Poland, and that electricity generation from fossil fuels will increase slightly in Germany and in Central Europe. We find that no additional imports will come from nuclear plants since they are already fully utilized in the merit order, and that electricity prices will rise on average by a few Euros per MWh. We conclude that closing the seven nuclear power plants within the government’s moratorium will cause no significant supply security issues or network constraints and an eventual full phase-out seem to be possible due to the completion of several new conventional power plants now under construction. Finally, we suggest that a nuclear phase-out in Germany within the next 3-7 years will not undermine security of supply and network stability in Germany and Central Europe.

Subsidies for Learning in Renewable Energy Technologies Under Market Power and Emission Trading

Under perfect competition on the output market, first best technology subsidies in the presence of learning by doing are justified by knowledge spill overs that are not accounted for by individual companies. First best output subsidies are thus depending directly on the learning effects and are, if applicable, positive. Considering electricity markets, a setting of imperfect competition is more appropriate. We show that the second best output subsidy for learning by doing in renewable energies takes the market distortion due to imperfect competition into account and is of ambiguous sign. Based on simulations with a European electricity market model, we find that second best renewable energy subsidies are positive and only insignificantly impacted by market power. By contrast, the welfare gains from an optimal subsidy are considerably higher compared to a hypothetical situation of perfect competition.

The European Offshore Supergrid and the Expansion of Offshore Wind Energy in Germany, Ireland and the United Kingdom – Legal, Political and Practical Challenges

The intention of this paper is to provide an up to date overview of the key legal, political and practical challenges arising from the proposal by Airtricity/Mainstream Renewable Power to construct a European offshore Supergrid, a super-structure of interconnected HVDC subsea electricity networks designed to span the coastal regions of the European continent. The paper takes a multi-disciplinary and comparative approach of the legal and policy positions in three core European offshore wind energy markets and is motivated by a firm belief that the Supergrid is an ``achievable'' energy infrastructure project. Two central objectives of the Europe Union's energy policy are rooted in the Supergrid proposal. In the first instance, the Supergrid would enhance the expansion of renewable electricity generation in Europe, thus acting as an implementation tool for the European Union's climate change obligations. At the same time, the proposal would also contribute to the achievement of the union's triple energy policy goals: Emission reductions, energy security and technical competitiveness. In its second capacity, by developing an interconnected offshore grid network, the Supergrid would duplicate the congested European onshore grid and serve as a vast interconnector between energy markets. By enabling for the first time the genuine competitive trading of electricity across the union's borders, the proposal would considerably contribute to the achievement of the single European electricity market.

Why Higher Price Sensitivity of Consumers May Increase Average Prices: An Analysis of the European Electricity Market

We develop a model of the European electricity market that allows analyzing the impact of consumers' price sensitivity, defined as the willingness to change energy providers, on equilibrium prices. The model is parameterized with publicly available data on total demand, marginal costs and capacity constraints of power generators. Comparably precise data on the price sensitivity is not available, so that we analyze its impact in a range of simulations. Contrary to apparently straightforward expectations, we find that a higher price sensitivity increases average prices under reasonable assumptions. The reason is that, when price sensitivity is high, the most efficient energy providers can attract sufficiently many consumers for operating at full capacity, even when price differences to their less efficient competitors are small. Hence, incentives to reduce prices are higher when the price sensitivity is low. We conclude that the widespread view that high electricity prices can (partially) be attributed to a low willingness of consumers to change their providers is flawed.

On European Electricity Market Liberalization: A Game-Theoretic Approach

In this paper, we deal with the European electricity market liberalization problem, formulated as a game with electricity producers as players, while the consumers' electricity demand is exogenous. The producers maximize their profit by choosing how much electricity they will produce individually by means of electricity production available to them. The aim of the research presented in this paper is to investigate the differences between the resulting electricity prices with different scenarios: a market with one Stackelberg leading producer, a market with two Stackelberg leading producers being noncooperative among themselves, and a perfectly competitive market. In the case studies the games involving one, two, and eight European countries are played. In the scenarios dealt with in this paper the perfectly competitive market yields the lowest electricity prices for the consumers. However, we also discuss possible drawbacks of liberalization. Our research aims to help understanding the complex process of electricity market liberalization.

Regional electricity markets in Europe: Focus on the Energy Community

Regional electricity markets (REM) are a natural step towards the creation of a single European electricity market. There are seven Electricity Regional Initiatives (ERI) launched by European Regulators Group for Electricity and Gas (ERGEG). This paper brings the focus to the eight REM covering the South East European (SEE) countries initiated by the European Commission. The congestion management and capacity allocation are used as an example to show that the SEE REM deals with the same priority issues as the other REMs do, and that the progress of this eight REM is great despite the short time of its existence. Given the EU membership perspective of the SEE countries and the expectation that the SEE REM shall become part of the internal electricity market, as well as the overlap between some members of the SEE REM and the other ERGEG ERI, the work of both initiatives shall be organized in a manner that uses the best practices and experience gained in each of them.

The Single European Electricity Market: A Long Road to Convergence

In the context of a first Working Paper the authors argued that electricity has a number of characteristics that set it apart from other commodities. It was demonstrated that some of these characteristics might complicate the deregulation process. This paper analyses the ongoing deregulation process in the European electricity sector and attempts to establish whether these difficulties can more readily be solved at European level. It would appear that some problems, e.g. economies of scale in electricity generation, have less of an impact at European level than within smaller national markets. However, a number of difficulties have to be overcome before a unified European electricity market can become a reality. These include the limited interconnection capacities between Member States. The European Commission has taken steps to improve the situation, for example by offering financial support for investments and promoting the development of regional markets as an interim measure ultimately leading to a fully integrated market. Apart from the difficulties related to electricity generation and transmission there are also exogenous factors that influence the ongoing deregulation process, e.g. the implementation of the Kyoto protocol and the dramatic increases in primary fuel prices. This paper argues that a consistent, stable and uniform European regulatory framework must be put in place if the impact of these difficulties is to be minimised.

A Large-Scale Spatial Optimization Model of the European Electricity Market

In this paper, we present a large-scale spatial model of the European electricity market including both generation and the physical transmission network (DC Load Flow approach). The model was developed to analyze various questions on market design, congestion management, and investment decisions, with a focus on Germany and Continental Europe. It is a bottom-up model combining electrical engineering and economics: its objective function is welfare maximization, subject to line flow, energy balance, and generation constraints. The model provides simulations on an hourly basis, taking into account variable demand, wind input, unit commitment, start-up costs, pump storage, and other details. Various forms of spatial price discrimination can be implemented, such as locational marginal pricing (“nodal pricing”), or zonal pricing. With over 2,000 nodes and over 3,000 lines, this is one of the largest models developed to date, and allows a highly differentiated spatial analysis. We report modeling results regarding efficient congestion management for Germany and Europe, optimal network expansion under the aspect of increased wind energy production, and the impact of network constraints on location decisions of generation investments.

Welfare Effects of Electricity Transit

The liberalization of the European electricity market facilitating the cross-border exchanges of electricity requires the establishment of a system for accessing the European grid. The starting point for the discussion of pricing the access to interconnected networks in this paper is the fact that electricity transit creates external effects to the involved countries which have to be internalized. Using a three countries model we analyze the welfare effects of different compensation scenarios for the electricity transfer between countries under individual and joint welfare maximization. The three countries have different roles: country 1 is an electricity exporting country, country 2 is importing electricity from country 1 and country 3 is the transit country. Individual and joint maximization deliver identical results if and only if export prices and transit charges are equal to marginal production and marginal transit costs. The joint optimum implies that the demand for imported electricity is determined by the sum of all relevant marginal costs: marginal production cost and marginal electricity loss in the export country, marginal transit costs and marginal electricity loss in the import country. The transit country has to be compensated for its electricity loss costs on the basis of marginal costs. Capital costs of transit capacity should only be compensated in the case of capacity shortage in the transit country.

Will the Market Get it Right? The Placing of New Power Plants in Germany

This paper applies ELMOD, an economic-engineering model of the European electricity market to the issue of optimal investment placing of generation capacity in Germany under different market integration scenarios. The model is formulated as cost minimization approach. We conduct a scenario analysis comparing different rules for power plant placing in a national, a market-coupling and an integrated EU market approach. We find that there are great benefits for consumers and producers if taking into account network conditions and cross border congestion in generation location planning. Moreover a change from national planning to an integrated market planner perspective shows even more improvements in prices and network utilization.

Simulation of the European Electricity Market and CCS Development with the HECTOR Model

In this paper we introduce HECTOR, a new and advanced long-term electricity market model that simulates market behavior bottom-up through opportunistic, variable cost-based bidding of individual power plants into auction-based national markets with international interconnection capacities. Unlike most other approaches, we implement the objective function on an hourly level. This allows for a reduction of the solution space, and enables a higher modeling resolution, including opportunistic bidding behavior of power plants based on expected supply scarcity, and ex-post investment decisions based on NPV considerations. The model simulates the electricity markets of 19 European countries, with over 400 groups of power plants, and is able to closely approximate historic electricity prices. The average base load price computed by the model for 2006-2008 and across the largest regions in Europe is 54.5 €/MWh, compared to 54.8 €/MWh in reality, using 2005 as training period. In a projection until 2040, we find that conventional fossil fuel-fired power plants are replaced both by renewable energy technologies and large quantities of CCS, the latter of which almost fully utilize available CO2 storage capacities in some of the regions studied.

European Electricity Market Reforms: Any Signs of Efficiency Improvements?

This paper investigates whether European electricity market reforms have induced any changes in firm efficiency either through productive, allocative or dynamic efficiency improvements. In particular, this ex-post analysis looks closely at productivity effects of changing industry structure, ownership structure and regulation with respect to barriers to entry and access to wholesale and retail markets. Based on the European firm-level data for the period 1996-2007, the results indicate sluggish productivity improvements of European electricity firms due to reforms implemented in the last decade. In particular, productivity gains are associated with high-productivity firms close to the technology frontier, while no significant impact is found for the laggards. Looking from a dynamic perspective, it seems that the closest are the firms to the frontier the more they are able to improve productivity in response to liberalization efforts stimulating competition.

From Liberalization Towards Integration: Have Markups of EU Electricity Firms Changed?

This paper presents an ex-post empirical analysis of the impact of European electricity market reforms on markups of firms. The working hypothesis is that further economic integration would bring competition into electricity markets reflected by lower markups of electricity firms. The results show that reforms have gradually reduced the markups, but the markup premium of incumbent firms is on average larger than theoretical models would predict under effective economic integration. Considering regional proximity and heterogeneity of firms along the supply chain, the results suggest that better market access and cross-border arbitrage disciplined the markups, but have not led to competitive market outcomes due to prevailing market concentration and insufficient unbundling of transmission and distribution channels.