• Energy Research

In 2020, the European Commission published a hydrogen strategy announcing different policy measures to support the construction of a European hydrogen infrastructure. Hereby, a target of 40 GW installed electrolyser capacity within the EU by 2030 was set, which will cause a significant electricity demand and will link together hydrogen and electricity markets. Therefore, state-of-the-art power modelling must include both electricity and hydrogen. This work proposes a novel approach to integrate hydrogen in existing long-term optimization electricity market dispatch models. A comprehensive modification of the optimization framework is not necessary as the hydrogen market can be modelled in analogy to the electricity market. This is done by implementing hydrogen markets as additional zones within the model with their own hydrogen demands and production. Thus, a hydrogen layer next to the existing electricity layer is created. Next to the dispatch model, hydrogen generation technologies are integrated into a system dynamics investment module, which is interlinked with the optimization model and determines market-driven investments in power plants based on the NPV. As a support scheme for electrolysers, carbon contracts for difference are implemented. Further, a detailed analysis of the German hydrogen and electricity markets is carried out. The analysis shows that renewable energy sources and electrolysers are complementary technologies, which mutually increase their profitability. The model indicates that higher electricity demands caused by electrolysers will not lead to higher electricity prices but reduce the price volatility.

For this study, the agent-based electricity market simulation model PowerACE is applied to investigate the impact of demand response (DR) on resource adequacy against the background of a coal phase-out in 2030. In addition, two market designs (current implementation and Europe-wide capacity market) are investigated. The results show that demand shortfalls cannot be avoided under the current energy-only market/strategic reserve market design due to a coal phase-out in 2030 in Germany. Even under a capacity market, timely investments to guarantee resource adequacy are not certain, but the shortfall risk is substantially lower. Therefore, market design adoptions in Germany appear necessary. DR can contribute to ensuring resource adequacy in both scenarios and significantly reduce the Loss of Load Expectation (LOLE) and Energy not Served (ENS). However, DR alone is not sufficient to guarantee resource adequacy solely.

Agentenbasierte Strommarktmodelle werden vielfach eingesetzt, um die Entwicklung des Strommarkts und Energiesystems explorativ zu untersuchen. Häufig werden hierbei auf Basis von Eingangszeitreihen die Investitions- und Dispatch-Entscheidungen von konventionellen Kraftwerken, wie Gas- oder Kohlekraftwerke, und Speichertechnologien nachgebildet . Modelle wie PowerACE und AMIRIS nutzen Brennstoffpreisreihe, Last, Erneuerbaren-Energien (EE)-Erzeugung und Investitionsoptionen sowie den bestehenden Kraftwerkspark als Eingangsdaten. Die zu Grunde gelegte Last und EE-Erzeugung sind hierbei stark vom jeweiligen Wetterjahr, auf denen sie basieren, abhängig. Zum einen ist das Wind- und Strahlungsdargebot als auch der Wärme- und Kältebedarf, welche einen starken Einfluss auf den Strombedarf haben, jedes Jahr unterschiedlich, gleichzeitig führen technologische Entwicklungen dazu, dass eine reine Skalierung historischer Erzeugung zukünftige EE-Erzeugung systematisch unterschätzt. Es soll untersucht werden, ob die Verwendung von nur einem Wetterjahr dazu führt, dass, insbesondere bei Betrachtungszeiträumen von mehreren Jahrzehnten, es beim Vergleich zwischen verschiedenen Wetterjahren zu erheblichen Unterschieden in den Simulationsergebnissen , sowohl bei den Investitionen als auch bei den Marktpreisen, kommt. Ziel ist es die Unsicherheiten in Bezug auf EE-Erzeugung und Stromnachfrage im Agentenverhalten abzubilden. In Rahmen dieser Arbeit soll diese Unsicherheit in den Ergebnissen agentenbasierter Modelle, am Beispiel PowerACE, quantifiziert werden und dargelegt werden, ob die Verwendung von mehreren Wetterjahren oder die Nutzung synthetische Wetterjahren, also eine Kombination verschiedener Wetterjahre auf Erzeugungs- und Nachfrageseite, hier einen Vorteil bieten .

In recent years, electricity markets have been characterized by a growing share of fluctuating renewable energies, which has increased concerns about the security of electricity supply. As a consequence, existing market designs are adapted, and new capacity remuneration mechanisms are introduced. However, these mechanisms entail new challenges, and it is disputed whether they are indeed needed. In this article, an overview of the current debate on the necessity of capacity remuneration mechanisms is provided. Furthermore, initial experiences of real-world implementations are discussed, and common findings in the literature, categorized by their economic implications, are derived. Finally, shortcomings in existing research and open questions that need to be addressed in future works are pointed out.

Following Russia's invasion of Ukraine in 2022, European countries took significant steps to reduce their reliance on energy imports from Russia, particularly in the gas and coal sectors. At the same time, to import less primary energy in the future, some countries have adopted new renewable energy targets. The question is to what extent the increase in gas and coal prices can contribute to refinancing renewable energy on the electricity wholesale market. To investigate this, an agent-based approach is used to examine the market values of renewable energies in several European countries until 2040. It is shown that increased expansion targets have a more substantial negative impact on the market values of renewable energies than increased gas and coal prices have a positive effect. In addition, it is observed that the introduction of capacity markets does not significantly influence market values and wholesale electricity prices in the medium term. However, by 2040, lower electrici

The introduction of capacity remuneration mechanisms is being intensively discussed among European decision makers, as concerns about generation adequacy in the electricity sector are growing among stakeholders. Different mechanisms have already been implemented or will be introduced in the near future in several European countries. This policy brief focuses on selected experiences in Belgium, France, Spain, Sweden and the UK. The implementation of capacity remuneration mechanisms yielded mixed experiences so far, thus making them subject to repeated adjustments. Although the mechanisms seem to have achieved their goal of purchasing the targeted capacity volumes in different auctions, their efficiency has not yet been sufficiently assessed. While on the one hand some mechanisms are removed again (eg. capacity payments in Spain or the strategic reserve in Sweden), on the other hand new mechanisms are introduced (e.g. decentral obligation in France). The introduction of capacity remuneration mechanisms, however, should go alongside a Europe-wide coordination to avoid market distortions, as the introduction of a mechanism can interfere with the ongoing process of an integrated European electricity market and hinder cross-border electricity trading. At least the participation of interconnectors or capacities from non-domestic areas should be admitted within national mechanisms.

France wants to become carbon-neutral by 2050. Renewable energies and nuclear power are expected to make the main contribution to this goal. However, the average age of nuclear power plants is approaching 37 years of operation in 2022, which is likely to lead to increased outages and expensive maintenance. In addition, newer nuclear power plants are flexible to operate and thus compatible with high volatile feed-in from renewables. Nevertheless, it is controversially discussed whether nuclear power plants can still be operated competitively and whether new investments will be made in this technology. Using an agent-based simulation model of the European electricity market, the market impacts of possible nuclear investments are investigated based on two scenarios: a scenario with state-based investments and a scenario with market-based investments. The results of this investigation show that under our assumptions, even with state-based investments, carbon neutrality would not be achieved with the estimated nuclear power plant capacity. Under purely market-based assumptions, large amounts of gas-fired power plants would be installed, which would lead to an increase in France's carbon emissions. State-based investments in nuclear power plants, however, would have a dampening effect on neighboring spot market prices of up to 4.5 % on average.

In dieser Untersuchung wird mittels des agentenbasierten Simulationsmodells PowerACE die Wirkung von verschiedenen Kapazitätsmechanismen auf gekoppelte Marktgebiete betrachtet. Im Fokus liegen dabei die strategische Reserve in Deutschland und Belgien sowie der Kapazitätsmarkt in Frankreich. Die Ergebnisse zeigen, dass bei Einführung dieser Mechanismen Preiseffekte in Nachbarländern entstehen und daraus Änderungen im Investitionsverhalten in den gekoppelten Marktgebieten resultieren.