Four Essays on the Economics of Renewable Power Markets

In the scope of four related essays, this thesis analyzes potential pathways to a low-carbon European electricity supply with a large share of intermittent renewables. In particular, the thesis investigates the related costs of such a transition under different economic and technical developments as well as energy policies. For this purpose, several (stochastic) optimization models and a spatial equilibrium model have been developed. These model-based analyses yield, among others, the following findings: Under cost-efficient energy policies and favorable technical and economic developments, system costs and electricity prices may not increase significantly compared to today. However, this requires a Europe-wide common energy strategy, large amounts of usable land and an open mindset surrounding feasible technology options. Moreover, the integration of intermittent renewable generation remains technically challenging. Given a large share of wind and solar power generation, regional and intraregional weather conditions play an important role in renewable power markets. Thus, simulation models neglecting weather uncertainty, which are often used in practice, underestimate system costs substantially. Furthermore, weather uncertainty induces financial risks for conventional and renewable-based electricity producers. The effect on the financial risk for green electricity producers depends on the renewable promotion scheme and the slope of the power market's supply function. It is shown that feed-in tariffs (fixed-price compensation) do not necessarily offer producers the lowest variance in profits. Moreover, the analysis shows that renewable policies not including the hourly wholesale price set inefficient incentives. For the particular case of concentrating solar plants, flat feed-in tariffs set an inefficient incentive to invest in integrated thermal energy storages in today's electricity market. The analyses in this thesis are carried out for the European electricity system. However, the results may be useful for the assessment of a transition to a low-carbon and mostly renewable-based electricity system in other regions as well

The costs of electricity systems with a high share of fluctuating renewables - a stochastic investment and dispatch optimization model for Europe

Renewable energies are meant to produce a large share of the future electricity demand. However, the availability of wind and solar power depends on local weather conditions and therefore weather characteristics must be considered when optimizing the future electricity mix. In this article we analyze the impact of the stochastic availability of wind and solar energy on the cost-minimal power plant mix and the related total system costs. To determine optimal conventional, renewable and storage capacities for different shares of renewables, we apply a stochastic investment and dispatch optimization model to the European electricity market. The model considers stochastic feed-in structures and full load hours of wind and solar technologies and different correlations between regions and technologies. Key findings include the overestimation of fluctuating renewables and underestimation of total system costs compared to deterministic investment and dispatch models. Furthermore, solar technologies are - relative to wind turbines - underestimated when neglecting negative correlations between wind speeds and solar radiation.Stochastic programming; electricity; renewable energy

The economic value of storage in renewable power systems - the case of thermal energy storage in concentrating solar plants

In this article we analyze the value of thermal energy storages in concentrated solar plants depending on the electricity generation mix. To determine the value from a system integrated view we model the whole electricty generation market of the Iberian Peninsula. Key findings for thermal energy storage units in concentrated solar plants include an increasing value in electricity systems with higher shares of fluctuating renewable generation and a potentially significant role in a transformation to a primarily renewable based electricity system. Due to the relatively high investment costs concentrated solar power plants with or without thermal energy storages are not cost efficient in todays electricity markets. However, expected cost reductions due to learning curve effects and higher fluctuating renewable generation may lead to a comparative cost advantage of concentrated solar power plants with thermal energy storages compared to other renewable technologies.Fluctuating renewables; value of storage; concentrated solar power; power plant optimization

Scenarios for an Energy Policy Concept of the German Government

In this working paper 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.Roadmap 2050; GHG reduction; renewable energies; carbon capture and storage; power plant fleet optimization

German Nuclear Policy Reconsidered: Implications for the Electricity Market

In the aftermath of the nuclear catastrophe in Fukushima, German nuclear policy has been reconsidered. This paper demonstrates the economic effects of an accelerated nuclear phase-out on the German electricity generation sector. A detailed optimization model for European electricity markets is used to analyze two scenarios with different lifetimes for nuclear plants (phase-out vs. prolongation). Based on political targets, both scenarios assume significant electricity demand reductions and a high share of generation from renewable energy sources in Germany. Our principal findings are: First, nuclear capacities are mainly replaced by longer lifetimes of existing coal-fired plants and the construction of new gas-fired plants. Second, fossil fuel-based generation and power imports increase, while power exports are reduced in response to the lower nuclear generation. Third, despite the increased fossil generation, challenging climate protection goals can still be achieved within the framework of the considered scenarios. Finally, system costs and electricity prices are clearly higher. We conclude that the generation sector can generally cope with an accelerated nuclear phase-out under the given assumptions. Yet, we emphasize that such a policy requires a substantial and costly transformation of the supply and the demand side.Nuclear policy; climate protection; renewable energy; electricity market modeling

The emergence of a self-catalysing structure in abstract origin-of-life models

We formalize a class of abstract and simple biochemical models that have been proposed for understanding the origin of life. We then analyse conditions under which 'life-like' substructures will tend to arise in such models

Decarbonizing Europe's power sector by 2050-Analyzing the economic implications of alternative decarbonization pathways

The European Union aims to reduce greenhouse gas emissions by 80-95% in 2050 compared to 1990 levels. The transition towards a low-carbon economy implies the almost complete decarbonization of Europe's power sector, which could be achieved along various pathways. In this paper, we evaluate the economic implications of alternative energy policies for Europe's power sector by applying a linear dynamic electricity system optimization model in over 36 scenarios. We find that the costs of decarbonizing Europe's power sector by 2050 vary between 139 and 633 (sic)(2010), which corresponds to an increase of between 11% and 44% compared to the total system costs when no CO2 reduction targets are implemented. In line with economic theory, the decarbonization of Europe's power sector is achieved at minimal costs under a stand-alone CO2 reduction target, which ensures competition between all low-carbon technologies. If, however, renewable energies are exempted from competition via supplementary renewable energy (RES-E) targets or if investments in new nuclear and CCS power plants are politically restricted, the costs of decarbonization significantly rise. Moreover, we find that the excess costs of supplementary RES-E targets depend on the acceptance of alternative low carbon technologies. For example, given a complete nuclear phase-out in Europe by 2050 and politically implemented restrictions on the application of CCS to conventional power plants, supplementary RES-E targets are redundant. While in such a scenario the overall costs of decarbonization are comparatively high, the excess costs of supplementary RES-E targets are close to zero. (C) 2013 Elsevier B.V. All rights reserved

Flexibility in Europe's power sector - An additional requirement or an automatic complement?

By 2050, the European Union aims to reduce greenhouse gases by more than 80%. The EU member states have therefore declared to strongly increase the share of renewable energy sources (RES-E) in the next decades. Given a large deployment of wind and solar capacities, there are two major impacts on electricity systems: First, the electricity system must be flexible enough to cope with the volatile RES-E generation, i.e., ramp up supply or ramp down demand on short notice. Second, sufficient back-up capacities are needed during times with low feed-in from wind and solar capacities. This paper analyzes whether there is a need for additional incentive mechanisms for flexibility in electricity markets with a high share of renewables. For this purpose, we simulate the development of the European electricity markets up to the year 2050 using a linear investment and dispatch optimization model. Flexibility requirements are implemented in the model via ramping constraints and provision of balancing power. We found that an increase in fluctuating renewables has a tremendous impact on the volatility of the residual load and consequently on the flexibility requirements. However, any market design that incentivizes investments in least (total system) cost generation investment does not need additional incentives for flexibility. The main trigger for investing in flexible resources is the achievable full load hours and the need for backup capacity. In a competitive market, the cost-efficient technologies that are most likely to be installed, i.e., gas-fired power plants or flexible CCS plants, provide flexibility as a by-product. Under the condition of system adequacy, flexibility never poses a challenge in a cost-minimal capacity mix. Therefore, any market design incentivizing investments in efficient generation thus provides flexibility as an inevi complement (C) 2014 Elsevier B.V. All rights reserved