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[en] In this article we demonstrate how challenging greenhouse gas reduction targets of up to 95% until 2050 can be achieved in the German electricity sector. In the analysis, we focus on the main requirements to reach such challenging targets. To account for interdependencies between the electricity market and the rest of the economy, different models were used to account for feedback loops with all other sectors. We include scenarios with different runtimes and retrofit costs for existing nuclear plants to determine the effects of a prolongation of nuclear power plants in Germany. Key findings for the electricity sector include the importance of a European-wide coordinated electricity grid extension and the exploitation of regional comparative cost effects for renewable sites. Due to political restrictions, nuclear energy will not be available in Germany in 2050. However, the nuclear life time extension has a positive impact on end consumer electricity prices as well as economic growth in the medium term, if retrofit costs do not exceed certain limits. (orig.)
[en] Wind power has seen a strong growth over the last decade. Due to its high intermittency, spot prices have become more volatile and exhibit correlated behavior with wind power fed into the system. In this paper, we develop a stochastic simulation model that incorporates the spatial dependencies of wind power and its interrelations with spot prices: We employ a structural supply and demand based model for the electricity spot price that takes into account stochastic production quantities of wind power. Spatial dependencies are modeled with the help of copulas, thus linking the single turbine wind power to the aggregated wind power in a market. The model is applied to the German electricity market where wind power already today makes up a significant share of total power production. Revenue distributions and the market value of different wind power plants are analyzed. We find that the specific location of the considered wind turbine, i.e. its spatial dependency with respect to the aggregated wind power in the system, is of high relevance for its market value. Many of the analyzed locations show an upper tail dependence that adversely impacts the market value. This effect becomes more important for increasing levels of wind power penetration.
[en] This paper numerically analyzes redistribution effects resulting from cooperation among European countries in achieving the 2020 targets for electricity generation from renewable energy sources (RES-E). The quanti cation of redistribution effects builds on the theoretical analysis by Unteutsch (2014), who shows that cooperation in RES-E support increases overall welfare but is not beneficial for all groups. In this paper, we use a dynamic investment and dispatch optimization model of the European electricity system to investigate which groups potentially benefit from cooperation and which groups would be worse off compared to a situation in which national RES-E targets are reached solely by domestic RES-E production. In the analysis, cooperation in RES-E support is implemented as a European-wide green certificate trading scheme. Main findings of the analysis include that in the European electricity system, effects of the change in the certificate price in most countries would overcompensate for the effects of the change in the wholesale electricity price. Thus, in most countries with comparatively high (low) generation costs for renewable energies, consumer rents increase (decrease) due to cooperation and producers yield lower (higher) profits. In addition, it is found that the magnitude of redistribution effects between the individual groups is quite large: In some countries, the change in consumer rents or producer profits resulting from cooperation is nearly twice as high as the overall welfare effect of cooperation in the whole European electricity system. Moreover, we find that the sign, but not always the magnitude, of redistribution effects is quite robust to different developments of interconnector extensions, the CO2 price and RES-E investment costs.
[en] The paper at hand examines the power system costs when a coal tax or a fixed bonus for renewables is combined with CO2 emissions trading. It explicitly accounts for the interaction between the power and the gas market and identifies three cost effects: First, a tax and a subsidy both cause deviations from the cost-efficient power market equilibrium. Second, these policies also impact the power sector's gas demand function as well as the gas market equilibrium and therefore have a feedback effect on power generation quantities indirectly via the gas price. Thirdly, by altering gas prices, a tax or a subsidy also indirectly affects the total costs of gas purchase by the power sector. However, the direction of the change in the gas price, and therefore the overall effect on power system costs, remains ambiguous. In a numerical analysis of the European power and gas market, I find using a simulation model integrating both markets that a coal tax affects gas prices ambiguously whereas a fixed bonus for renewables decreases gas prices. Furthermore, a coal tax increases power system costs, whereas a fixed bonus can decrease these costs because of the negative effect on the gas price. Lastly, the more market power that gas suppliers have, the stronger the outlined effects will be.
[en] Exposing wind and solar power to the market price signal allows for cost-efficient investment decisions, as it incentivizes investors to account for the marginal value (MVel) of renewable energy technologies. As shown by Lamont (2008), the MVel of wind and solar power units depends on their penetration level. More specifically, the MV el of wind and solar power units is a function of the respective unit's capacity factor and the covariance between its generation profile and the system marginal costs. The latter component of the MVel (i.e., the covariance) is found to decline as the wind and solar power penetration increases, displacing dispatchable power plants with higher short-run marginal costs of power production and thus reducing the system marginal costs in all generation hours. This so called 'system price effect' is analyzed in more detail in this paper. The analysis complements the work Lamont (2008) in two regards. First of all, an alternative expression for the MVel of wind and solar power units is derived, which shows that the MVel of fluctuating renewable energy technologies depends not only on their own penetration level but also on a variety of other parameters that are specific to the electricity system. Second, based on historical wholesale prices and wind and solar power generation data for Germany, a numerical 'ceteris paribus' example for Germany is presented which illustrates that the system price effect is already highly relevant for both wind and solar power generation in Germany.
[en] The present paper discusses the concept of fuel poverty taking into account the arbitrages made by households when they are facing economic constraints. Fuel poverty is still lacking a common definition throughout Europe: while the UK and France have (different) official definitions, there is still no definition in a country like Germany, or at the European level. Where definitions exist, they often consider that fuel poor households have high energy needs. The possibility of being fuel poor even without having high energy needs and the various arbitrage possibilities of households - i.e. to under-spend and use too little energy - are not systematically discussed. Our paper tries to fill that gap by putting fuel poverty into the larger context of constraints faced by households. Based on a graphical analysis, it shows that different situations of fuel poverty might occur. It results in the identification of two distinct fuel poverty problems: an ''energy inequality'' problem, reflected by the fact that some households pay disproportionately high energy bills, and an ''energy affordability'' problem that can affect a larger share of the population. It finally explores the two types of fuel poverty for European countries and discusses policy implications.
[en] In this paper, we develop a microeconomic approach to deduce greenhouse gas abatement cost curves of the residential heating sector. By accounting for household behavior, we find that welfare-based abatement costs are generally higher than pure technical equipment costs. Our results are based on a microsimulation of private households' investment decision for heating systems until 2030. The households' investment behavior in the simulation is derived from a discrete choice estimation which allows investigating the welfare costs of different abatement policies in terms of the compensating variation and the excess burden. We simulate greenhouse gas abatements and welfare costs of carbon taxes and subsidies on heating system investments until 2030 to deduce abatement curves. Given utility maximizing households, our results suggest a carbon tax to be the welfare efficient policy. Assuming behavioral misperceptions instead, a subsidy on investments might have lower marginal greenhouse gas abatement costs than a carbon tax.
[en] This paper analyzes the strategic firm behavior within the context of a two-period resource duopoly model in which firms face endogenous intertemporal capacity constraints. Firms are allowed to invest in capacity in between two periods in order to increase their initial endowment of exhaustible resource stocks. Using this setup, we nd that the equilibrium price weakly decreases over time. Moreover, asymmetric distribution of initial resource stocks leads to a significant change in equilibrium outcome, provided that firms do not have the same cost structure in capacity additions. It is also verified that if only one company is capable of investment in capacity, the market moves to a more concentrated structure in the second period.
[en] It has been shown that international cooperation in achieving renewable energy targets, e.g., via a common tradable green certificate market, increases overall welfare. However, cooperation in the support of electricity from renewable energy sources also leads to regional price effects, from which some groups benefit while others lose. On a regional level, the introduction of cross-border cooperation in RES-E support generally has an opposite effect on support expenditures and wholesale electricity prices, as long as grid congestion between the different regions exists. In this paper, a theoretical model is used to analyze under which conditions different groups bene t or suffer from the introduction of cooperation. Findings of the analysis include that effects on consumers and total producers per country can only be clearly determined if no grid congestions between the countries exist. If bottlenecks in the transmission system exist, the relationship between the slopes of the renewable and the non-renewable marginal generation cost curves for electricity generation as well as the level of the RES-E target essentially determine whether these groups bene t or lose from the introduction of green certificate trading. In contrast, system-wide welfare always increases once cooperation in RES-E support is introduced. Similarly, welfare on the country level always increases (compared to a situation without RES-E cooperation) if the countries are perfectly or not at all physically interconnected. In the case of congested interconnectors, each country always at least potentially benefits from the introduction of certificate trade, taking into account possible distributions of congestion rents between the countries.
[en] Liberalized electricity markets are characterized by fluctuating priceinelastic demand of non-storable electricity, often defined by a substantial market share held by one or few incumbent firms. These characteristics have led to a controversial discussion concerning the need for and the design of capacity mechanisms, which combine some form of capacity payments with price caps in the spot market. The purpose of this study is to understand the effects of capacity mechanisms on the market structure. We consider a model with dominant firms and a competitive fringe and investigate the impact of price caps and capacity payments on investment incentives and market concentration. While lower price caps reduce the potential for the exercise of market power in static models, we find that in the dynamic model with endogenous investments, lower price caps result in an increase in market concentration, the frequency of capacity withholding and the profits of the dominant firms.