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We introduce a bottom-up modeling framework that allows both the decentral and central planning of an integrated energy system with high shares of renewable generation. We take into account the distribution network structure as well as the changing local consumption due to high electrification rates of building heat supply and the transportation sector. This approach allows the analysis of pathways in between a cost-optimal system design and an equitable spatial distribution of renewable generation and battery storage capacities within the system. In addition, we investigate the optimal combination of short- and medium-term battery storage technologies, namely lithium-ion and redox flow batteries. Our results for the case of Baden-Wuerttemberg, a state in southern Germany, show that a central planning of renewable generation and storage capacity requirements results in lower levelized costs of electricity than a decentral design, as expected. However, pathways in between the two planning paradigms can lead to a more equitable inclusion of communities in the energy transition at reasonable cost increases, which might increase acceptance. The results of this study are of significance for policy-makers and local stakeholders, as they must address the conflicts that arise on a local level when expansion targets are planned centrally. • Framework for modeling local electricity consumption, considering structural changes • Optimal combination of short- and medium-term storage technologies (LiB and RFB) • Costs, storage and renewable capacity requirements for decentral vs. central planning [ABSTRACT FROM AUTHOR]

• Energy yield simulation of vertical bifacial PV array in 12 European locations. • Comparison with a conventional PV array (monofacial, equator-oriented, tilted). • Evaluation of market revenues based on historic day-ahead market prices. • Evaluation of LCOE and net present value. • Evaluation of system cost reduction from a macroeconomic perspective for Germany. Thanks to the two diurnal generation peaks, vertical bifacial photovoltaic power plants (VBPV) with a north-south axis represent an option to meet the challenges of a mismatch between electricity demand and the generation profile of conventional photovoltaic systems (C-PV). Despite this promising characteristic, it is hardly possible to assess the technical and economic properties of VBPV on the basis of existing studies. The present work is a contribution to close this gap. Among other things, the conducted analyses included electricity generation, market revenues, levelized costs of electricity (LCOE) and the cost-reducing effect of VBPV in a national electricity system. C-PV was used as a benchmark in all analyses. Electricity generation was simulated at twelve European sites in four countries. It has been found that above a latitude of 50° VBPV generates more electricity than C-PV. Due to the higher investments, VBPV had higher LCOE at all locations investigated. The results also showed that VBPV can generate higher revenues in electricity markets with a high share of C-PV capacity, but that these additional revenues are not yet sufficient to compensate for the higher investments. With an optimising electricity market model, it was also found that VBPV can contribute to reducing system costs in an electricity system with high shares of C-PV capacity. Against the background of the increasing importance of PV for the electricity supply of most European countries, these findings are of particular importance. In summary, it can be said that VBPV has significant potential at both the business and macro-economic level and that decision makers should promote the market entry of this technology. [ABSTRACT FROM AUTHOR]