• Energy Research

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.

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.

In this paper we analyze a uniform price day-ahead electricity spot market that is followed by redispatch in the case of network congestion. We assume that the transmission system operator is incentivized to minimize redispatch cost and compare cost-based redispatch (CBR) to market-based redispatch (MBR) mechanisms. For networks with at least three nodes we show that in contrast to CBR, in the case of MBR incentives to minimize redispatch cost are in general not efficient in the context of our short-run analysis. This obtains both for pay-as-bid as well as locational marginal prices used for MBR compensation. As we demonstrate, moreover, in case of MBR the possibility of the transmission system operator to inefficiently reduce redispatch cost at the expense of decreased overall welfare can be driven both by the electricity supply side and the electricity demand side.Our results highlight a novel and important aspect regarding the design and the desirability of congestion management regimes in liberalized electricity markets.

In this paper we analyze a uniform price day-ahead electricity spot market that is followed by redispatch in the case of network congestion. We assume that the transmission system operator is incentivized to minimize redispatch cost and compare cost-based redispatch (CBR) to market-based redispatch (MBR) mechanisms. For networks with at least three nodes we show that in contrast to CBR, in the case of MBR incentives to minimize redispatch cost are in general not efficient in the context of our short-run analysis. This obtains both for pay-as-bid as well as locational marginal prices used for MBR compensation. As we demonstrate, moreover, in case of MBR the possibility of the transmission system operator to inefficiently reduce redispatch cost at the expense of decreased overall welfare can be driven both by the electricity supply side and the electricity demand side.Our results highlight a novel and important aspect regarding the design and the desirability of congestion management regimes in liberalized electricity markets.

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.

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.

Abstract Electric fuels (e-fuels) enable CO2-neutral mobility and are therefore an alternative to battery-powered electric vehicles. This paper compares the cost-effectiveness of Fischer-Tropsch diesel, methanol and Liquid Organic Hydrogen Carriers. The production costs of those fuels are to a large part driven by the energy-intensive electrolytic hydrogen production. In this paper, we apply a multi-level electricity market model to calculate future hourly electricity prices for various electricity market designs in Germany for the year 2035. We then assess the economic efficiency of the different fuels under various future market conditions. In particular, we use the electricity price vectors derived from an electricity market model calibrated for 2035 as an input for a mathematical model of the entire process chain from hydrogen production and chemical bonding to the energetic utilization of the fuels in a vehicle. Within this model, we perform a sensitivity analysis, which quantifies the impact of various parameters on the fuel production cost. Most importantly, we consider prices resulting from own model calculations for different energy market designs, the investment cost for the electrolysis systems and the carbon dioxide purchase price. The results suggest that the use of hydrogen, which is temporarily bound to Liquid Organic Hydrogen Carriers, is a favorable alternative to the more widely discussed synthetic diesel and methanol.