• Energy Research

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.

Abstract 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.

Industrialized countries around the world have set ambitious climate targets and face the challenge that existing mechanisms for CO2 pricing alone are not sufficient to achieve the desired level of ambition. In a multi-level electricity market model that captures investments in grid and generation capacities as well as electricity trading, we analyze different policy approaches to curb emissions by phasing out emission-intensive technologies, expanding renewables or by simply tightening CO2 pricing. We extend existing modelling approaches to endogenize (welfare-optimal) expansion of renewable energy capacities, taking into account the respective grid expansion necessary for a particular expansion path. Applying the approach to the German electricity market shows that both, the strengthening of the incentives from emissions trading through a minimum CO2 price as well as a forced complete coal exit lead to a significant additional decrease in emissions. The stepwise coal phase-out as decided in Germany, on the other hand, does not come close to achieving this reduction in emissions, largely due to the sequence of the phase-out decided (first hard coal, then lignite). The avoided CO2 emissions are accompanied by significant welfare gains in the respective scenarios. Further welfare gains can be achieved through a system-optimal expansion of renewables, especially because grid expansion can be avoided. We also consider different ways to remunerate renewables for all scenarios. It turns out that the renewable generators’ revenues from the electricity market together with the revenues from CO2 pricing are fully sufficient to finance renewables.