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Wind Power Generation
(2022)
Wind power plays a major role in the decarbonization of the power sector. Already now, it supplies increasing shares of the global energy demand. This book chapter provides an overview on the economics of wind energy and highlight global trends in the wind sector. It describes the technical characteristics of onshore and offshore wind energy and explains how these affect the economic competitiveness of the respective technologies. The authors describe how wind power, as an intermittent source of energy, can be integrated into power systems. They also discuss how renewable energy support schemes contribute in fostering the deployment of wind power.
Solar Power Generation
(2022)
Solar energy supplies increasing shares of global energy demand. As a renewable source of energy, it will play a major role in decarbonizing electricity supply. This chapter provides an overview on the solar sector from an economic perspective. It describes the technical characteristics of photovoltaic and concentrated solar power and explains how these affect the economic competitiveness of solar energy. The authors highlight trends in the solar sector and elaborate on how this intermittent source of energy can be integrated into a power system. They conclude with a discussion on how renewable energy support schemes can be designed to foster the deployment of solar power by accounting for the specific characteristics of solar power.
Frequency stability requires equalizing supply and demand for electricity at short time scales. Such electricity balancing is often understood as a sequential process in which random shocks, such as weather events, cause imbalances that system operators close by activating balancing reserves. By contrast, we study electricity balancing as a market where the equilibrium price (imbalance price) and quantity (system imbalance) are determined by supply and demand. System operators supply imbalance energy by activating reserves; market parties that, deliberately or not, deviate from schedules create a demand for imbalance energy. The incentives for deliberate strategic deviations emerge from wholesale market prices and the imbalance price. We empirically estimate the demand curve of imbalance energy, which describes how sensitive market parties are to imbalance prices. To overcome the classical endogeneity problem of price and quantity, we deploy instruments derived from a novel theoretical framework. Using data from Germany, we find a decline in the demand for imbalance energy by 2.2 MW for each increase in the imbalance price by EUR 1 per MWh. This significant price response is remarkable because the German regulator prohibits strategic deviations. We also estimate cross-market equilibriums between intraday and imbalance markets, finding that a shock to the imbalance price triggers a subsequent adjustment of the intraday price.
Contrary to liberalized U.S. electricity markets that apply nodal pricing, EU power markets rely on uniform pricing in bidding zones. The EU’s zonal pricing model is challenged by an increasing mismatch between network and generation expansion within existing bidding zones, as well as the complexity of defining adequate new bidding zones. A potential solution is to transition to nodal pricing in the EU. The academic literature provides strong evidence of significant cost savings under nodal pricing as compared to zonal pricing. The question is: Why has nodal pricing persistently been discarded in the EU? It cannot be denied that implementing nodal pricing would require significant changes to the EU market design and potentially also the institutional setup. However, so far, the debate in the EU has mostly focused on perceived flaws of the concept of nodal pricing. In this paper, we identify the main arguments against the concept of nodal pricing brought forward by EU stakeholders. We group the arguments into the six categories: susceptibility to market power, barriers to unlock flexibility, market liquidity concerns, increased investment risks, unmanageable complexity, and political undesirability of locational price differentiation. Our contribution is to critically assess each of the arguments and to demonstrate that they do not explain, nor justify, the opposition to nodal pricing. Instead of devoting attention to mostly misconceived flaws of nodal pricing, we urge a reconsideration of a nodal market.
Um die Klimaziele bis 2045 zu erreichen, muss der Stromsektor fundamental verändert werden. Insbesondere die Erneuerbaren Energien (EE) müssen massiv ausgebaut werden. Dabei stellt sich auch die Frage, an welchen Standorten neue Anlagen errichtet werden. Fand der Zubau historisch eher in den Regionen mit guten natürlichen Ressourcen an Wind und Sonne, hohen Volllaststunden und damit niedrigen Kosten pro erzeugter Stromeinheit statt, kann in Zukunft eine Standortsteuerung notwendig werden, um Kosten und Nutzen des EE-Ausbaus gleichmäßiger über das Bundesgebiet zu verteilen, die Stromnetze zu entlasten und die Potentiale in allen Regionen zu heben.
Im Rahmen des Kopernikus-Projekts Ariadne wurden Szenarien entwickelt, anhand derer Bürgerinnen und Bürger die Vor- und Nachteile verschiedener regionaler Verteilungen der Standorte aus Akzeptanzgesichtspunkten diskutierten. Dabei wurde erkennbar, dass mögliche regionale Verteilungen, die aus Sicht der Bürgerinnen und Bürger eher wünschenswert wären, deutlich vom Status Quo abweichen.
In der vorliegenden Analyse geben wir daher einen Überblick über die Regulierungs- und Politikinstrumente, mit denen eine ex ante bestimmte regionale Verteilung erreicht werden kann, die nicht allein einer ökonomischen Optimierung folgt. Zur Bestimmung der Verteilung können übergeordnete Anforderungen, beispielsweise an eine ausgewogene Flächenverteilung, eine Rolle spielen, aber auch gesellschaftliche Indikatoren, wie eine als gerecht empfundene Lasten- und Nutzenteilung. Wir analysieren Vor- und Nachteile der verschiedenen Instrumente und geben Hinweise zu ihrer juristischen Umsetzbarkeit. Außerdem quantifizieren wir anhand eines stilisierten Beispiels, wie preisbasierte Steuerungselemente ausgestaltet werden müssten, um zu einer regionalen Verteilung der Windanlagen in Deutschland zu führen, die in dem „Fokus PV“-Szenario des Ariadne-Reports zur Klimaneutralität 20451 modelliert wurde.
Die Analyse zeigt auf, dass eine Vielzahl von Instrumenten die regionale Verteilung so beeinflussen können, dass sie zu einer gleichmäßigeren und mitunter als gerechter empfundenen Verteilung des Zubaus an Erneuerbaren Energien führt.
Das Aufzeigen der verschiedenen Instrumentenoptionen zur regionalen Steuerung ist relevant für die künftige Gestaltung der Energiewende, da die bisherige regionale Steuerung vor allem innerhalb der Erneuerbaren-Förderung stattfindet, die in Zukunft jedoch zunehmend an Bedeutung verlieren dürfte und zudem nicht alle Technologien berücksichtigt. Die transparente Darstellung der Vor- und Nachteile hilft außerdem beim Abwägen im Falle von – bei der Auswahl von Standorten häufig auftretenden – Interessenskonflikten.
Locational Investment Signals: How to Steer the Siting of New Generation Capacity in Power Systems?
(2020)
New generators located far from consumption centers require transmission infrastructure and increase network losses. The primary objective of this paper is to study signals that affect the location of generation investment. Such signals result from the electricity market itself and from additional regulatory instruments. We cluster them into five groups: locational electricity markets, deep grid connection charges, grid usage charges, capacity mechanisms, and renewable energy support schemes. We review the use of instruments in twelve major power systems and discuss relevant properties, including a quantitative estimate of their strength. We find that most systems use multiple instruments in parallel, and none of the identified instruments prevails. The signals vary between locations by up to 20 EUR per MWh. Such a difference is significant when compared to the levelized costs of combined cycle plants of 64–72 EUR per MWh in Europe.
Numerical optimization models are used to develop scenarios of the future energy system. Usually, they optimize the energy mix subject to engineering costs such as equipment and fuel. For onshore wind energy, some of these models use cost-potential curves that indicate how much electricity can be generated at what cost. These curves are upward sloping mainly because windy sites are occupied first and further expanding wind energy means deploying less favorable resources. Meanwhile, real-world wind energy expansion is curbed by local resistance, regulatory constraints, and legal challenges. This presumably reflects the perceived adverse effect that onshore wind energy has on the local human population, as well as other negative external effects. These disamenity costs are at the core of this paper. We provide a comprehensive and consistent set of cost-potential curves of wind energy for all European countries that include disamenity costs, and which can be used in energy system modeling. We combine existing valuation of disamenity costs from the literature that describe the costs as a function of the distance between turbine and households with gridded population data, granular geospatial data of wind speeds, and additional land-use constraints to calculate such curves. We find that disamenity costs are not a game changer: for most countries and assumptions, the marginal levelized cost of onshore wind energy increase by 0.2–12.5 €/MWh.
Governments use regulation to affect the behavior of market participants such that welfare is maximized. Good regulation in the electricity sector aims to achieve an affordable, sustainable, and secure supply of electricity. However, the energy transition fundamentally changes the way electrical energy is produced and consumed. Consequently, market rules and regulatory interventions need to be adjusted to cope with these new political targets, technological innovations, and societal trends.
This cumulative dissertation contributes to the academic literature on regulatory incentives in the electricity sector with four scientific articles. At the core of this dissertation are incentives for participants of the electricity market that result from the market design and other regulatory interventions. I study how such incentives can be designed to minimize the cost of expanding and operating the transmission network. The transmission system is confronted with several new challenges resulting from the energy transition, including an increasing distance between generators and consumers, power flows that quickly change over time, and declining share of dispatchable generators that complicates frequency stability.
The first three articles of this dissertation study incentives for market participants to account for the cost of operating and expanding the transmission network in their investment and dispatch decisions. The first article introduces a conceptual framework for categorizing and analyzing locational signals that result from the market design and from other regulatory interventions. It classifies, quantifies, and discusses locational instruments in twelve jurisdictions. It finds that all reviewed systems apply regulatory locational instruments, and many systems even combine multiple instruments. Only few instruments result in economic incentives that are strong enough to affect investment decisions. The second article focuses on one key market design: nodal pricing. It identifies and assesses the main arguments against the concept of nodal pricing based on the experience made in US power markets. It shows that most of the perceived drawbacks of the concept in the European debate are misconceived and can be sufficiently addressed as it is done in systems that already implemented a nodal market. The third article studies the long-run effects of optimal administratively determined locational signals. To do so, it introduces a complementary power market model. Applying the model to a sample case study reveals characteristics of such signals and highlights their potential welfare gains.
The fourth article is dedicated to the balancing mechanism, which maintains the grid frequency by balancing the feed-in of electricity into the network and its withdrawal. This is another source of cost that arise in the transmission system. The article analyses the economic incentives resulting from the design of the balancing mechanism. It quantifies the price response of balancing responsible parties to the imbalance price and finds a significant effect. This finding is politically delicate because such a price responsiveness is forbidden by the regulator.
With these four articles, the dissertation provides insights how the regulator can affect the behavior of market participants through economic incentives, which is of interest for researchers and policy makers alike. It adds to the literature by proposing new frameworks and models, and by drawing from experiences in other jurisdictions. Thereby, it contributes to adapting the regulation of the power sector in times of the energy transition.