TY - JOUR A1 - Grimm, Veronika A1 - Rückel, Bastian A1 - Sölch, Christian A1 - Zöttl, Gregor T1 - Regionally differentiated network fees to affect incentives for generation investment JF - Energy N2 - In this paper we propose an equilibrium model that allows to analyze subsidization schemes to affect locational choices for generation investment in electricity markets. Our framework takes into account generation investment decided by private investors and redispatch as well as network expansion decided by a regulated transmission system operator. In order to take into account the different objectives and decision variables of those agents, our approach uses a bi-level structure. We focus on the case of regionally differentiated network fees which have to be paid by generators (a so called g-component). The resulting investment and production decisions are compared to the outcome of an equilibrium model in the absence of such regionally differentiated investment incentives and to an overall optimal (first-best) benchmark. To illustrate possible economic effects, we calibrate our framework with data from the German electricity market. Our results reveal that while regionally differentiated network fees do have a significant impact on locational choice of generation capacities, we do not find significant effects on either welfare or network expansion. KW - Electricity Markets, Network Expansion, Generation Expansion, Investment Incentives, Computational Equilibrium Models Y1 - 2019 U6 - https://doi.org/10.1016/j.energy.2019.04.035 IS - 177 SP - 487 EP - 502 ER - TY - JOUR A1 - Grimm, Veronika A1 - Grübel, Julia A1 - Rückel, Bastian A1 - Sölch, Christian A1 - Zöttl, Gregor T1 - Storage investment and network expansion in distribution networks: The impact of regulatory frameworks JF - Applied Energy N2 - In this paper we propose a bi-level equilibrium model that allows to analyze the impact of different regulatory frameworks on storage and network investment in distribution networks. In our model, a regulated distribution system operator decides on network investment and operation while he anticipates the decisions of private agents on storage investment and operation. Since, especially in distribution networks, voltage stability and network losses have a decisive influence on network expansion and operation, we use a linearized AC power flow formulation to adequately account for these aspects. As adjustments of the current regulatory framework, we consider curtailment of renewable production, the introduction of a network fee based on the maximum renewable feed-in, and a subsidy scheme for storage investment. The performance of the different alternative frameworks is compared to the performance under rules that are commonly applied in various countries today, as well as to a system-optimal (first-best) benchmark. To illustrate the economic effects, we calibrate our model with data from the field project Smart Grid Solar. Our results reveal that curtailment and a redesign of network fees both have the potential to significantly reduce total system costs. On the contrary, investment subsidization of storage capacity has only a limited impact as long as the distribution system operator is not allowed to intervene in storage operation. KW - Computational Equilibrium Models; Electricity Markets; Investment Incentives; Distribution Network Expansion Planning; Storage Investment and Operation; Renewable Energy Production; (Self-) Consumption Y1 - 2019 U6 - https://doi.org/10.1016/j.apenergy.2019.114017 IS - 262 ER - TY - JOUR A1 - Grimm, Veronika A1 - Rückel, Bastian A1 - Sölch, Christian A1 - Zöttl, Gregor T1 - The impact of market design on transmission and generation investment in electricity markets JF - Energy Economics N2 - In this paper we propose an equilibrium model in order to analyze the impact of electricity market design on generation and transmission expansion in liberalized electricity markets. In a multi-level structure, our framework takes into account that generation investment and operation is decided by private investors, while network expansion and redispatch is decided by a regulated transmission system operator — as well as the different objectives of firms (profit maximization) and the regulator (welfare maximization). In order to illustrate the possibilities to quantify long term economic effects with our framework, we calibrate our model for the German electricity market. We consider various moderate adjustments of the market design: (i) the division of the market area into two price zones, (ii) the efficient curtailment of renewable production and (iii) a cost-benefit-driven balance between network expansion and network management measures. We then analyze the impact of these market designs on generation and transmission investment in case those design elements are anticipated upon network development planning. The resulting investment and production decisions are compared to a benchmark that reflects the current German electricity market design and to an overall optimal first-best benchmark. Our results reveal that price zones do have a significant impact on locational choice of generators and result in a reduced need for network expansion, but lead to only moderate annual welfare gains of approximately 0.9% of annual total system costs. Anticipation of optimal curtailment of renewables and a cost-benefit-driven use of redispatch operations upon network expansion planning, however, implies a welfare gain of over 4.9% of annual total system costs per year as compared to the existing market design, which equals 85% of the maximum possible welfare gain of the first-best benchmark. KW - Electricity Markets, Network Expansion, Generation Expansion, Investment Incentives, Market Design, Congestion Management, Computational Equilibrium Models Y1 - 2019 U6 - https://doi.org/10.1016/j.eneco.2020.104934 IS - 93 ER -