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Germany is under increasing pressure to rapidly decarbonize its electricity system, while ensuring a secure and affordable electricity supply. In this context, energy storage systems (ESSs) can play a crucial role in enabling a high share of variable renewable electricity generation. To investigate the complex interplay of ESSs in the electricity system, bottom-up energy system optimization models have been utilized to create strategies for the decarbonization of electricity systems at minimum cost. Previous studies have used models to investigate the role of storage technologies in decarbonizing electricity systems. However, in most of them, key aspects pertaining to the optimal storage technology mix (what), the daily and seasonal operation of storage technologies (what), the timing of the investment (when), and their optimal placement (where) are omitted. In this work, we present MANGOelec, a model for the long-term optimal design of electricity systems that allows us to study all the what-where-when dimensions for ESSs. We apply the MANGOelec model to the German electricity system considering the horizon until 2050, as well as various scenarios to investigate the effects of several external factors like building rates of renewable generation technologies or grid expansion limitations on the optimal transformation pathways. The study results indicate that a mix of short- and long-term storage is needed, independent of external factors. For instance, battery storage potentials are close to fully exploited across all regions and the technology is solely used for daily operation. Hydrogen storage, on the other hand, is primarily installed in a small set of regions and operated exclusively as a seasonal storage option. Here, the results indicate that the demand for hydrogen storage capacity is substantial, reaching 2.7–5.9 TWh of hydrogen-based storage capacity in 2050 depending on the scenario. The results also suggest that independent of the storage technology chosen, their deployment commences after 2030 and is completed by 2045. In conclusion, the study shows that already existing ESSs provide sufficient flexibility at first but need to be expanded substantially after 2030 to enable a cost-optimal transition of the German electricity system. Moreover, it illustrates the need for ESSs in order to achieve the decarbonization goals of the German electricity system, which can provide valuable insights to energy planners and policy makers. • Role of energy storage systems in the German electricity system is investigated. • Modeling of daily and seasonal storage investments and operation in 2021–2050. • Quantification of regional and temporal patterns in energy storage installations. • High hydrogen-based seasonal storage demand in selected federal states is shown. [ABSTRACT FROM AUTHOR]

• Earlier phase-out of coal is not the best answer to achieve energy transition. • The 2050 plan and historical RES investments maxima are not enough to reach climate neutrality. • What is the effect of regional RES limits over Nationwide RES limits. • Where will be the states in Germany having major RES deployment. • Myopic optimization reveals new challenges for energy policy. This paper will introduce the open-source model MyPyPSA-Ger, a myopic optimization model developed to represent the German energy system with a detailed mapping of the electricity sector, on a highly disaggregated level, spatially and temporally, with regional differences and investment limitations. Furthermore, this paper will give new outlooks on the German federal government 2050 emissions goals of the electricity sector to become greenhouse gas neutral by proposing new CO 2 allowance strategies. Moreover, the regional differences in Germany will be discussed, their role and impact on the energy transition, and which regions and states will drive the renewable energy utilization forward. Following a scenario-based analysis, the results point out the major keystones of the energy transition path from 2020 to 2050. Solar, onshore wind, and gas-fired power plants will play a fundamental role in the future electricity systems. Biomass, run of river, and offshore wind technologies will be utilized in the system as base-load generation technologies. Solar and onshore wind will be installed almost everywhere in Germany. However, due to the nature of Germany's weather and geographical features, the southern and northern regions will play a more important role in the energy transition. Higher CO 2 allowance costs will help achieve the 1.5-degree-target of the electricity system and will allow for a rapid transition. Moreover, the more expensive, and the earlier the CO 2 tax is applied to the system, the less it will cost for the energy transition, and the more emissions will be saved throughout the transition period. An earlier phase-out of coal power plants is not necessary with high CO 2 taxes, due to the change in power plant's unit commitment, as they prioritize gas before coal power plants. Having moderate to low CO 2 allowance cost or no clear transition policy will be more expensive and the CO 2 budget will be exceeded. Nonetheless, even with no policy, renewables still dominate the energy mix of the future. However, maintaining the maximum historical installation rates of both national and regional levels, with the current emissions reduction strategy, will not be enough to reach the level of climate-neutral electricity system. Therefore, national and regional installation requirements to achieve the federal government emission reduction goals are determined. Energy strategies and decision makers will have to resolve great challenges in order to stay in line with the 1.5-degree-target. [ABSTRACT FROM AUTHOR]

• Electricity, hydrogen and methane system will be more integrated in the future. • The developed integrated model considers their interactions and interdependencies. • As proof-of-concept, the model is applied to the Dutch Infrastructure Outlook 2050. • Interweaving electricity, hydrogen and methane system will provide much needed flexibility. The future energy system is widely expected to show increasing levels of integration across differing energy carriers. Electricity, hydrogen, methane and heat systems may become increasingly interdependent due to coupling through conversion and hybrid energy technologies. Market parties, network operators, policy makers and regulators require tools to capture implications of possible techno-economic and institutional developments in one system for the operation of others. In this article, we provide an integrated electricity, hydrogen and methane systems modelling framework focusing on interdependencies between them. The proposed integrated electricity and (renewable) gas system model is a market equilibrium model with hourly price and volume interactions, considering ramp rates of conventional units, variability of intermittent renewables, conversion, transport as well as storage of electricity, hydrogen and methane. The integrated model is formulated as a linear program under the assumption of perfect competition. As proof-of-concept, the model has been applied to a test case consisting of 34 electricity nodes, 19 hydrogen nodes and 22 methane nodes, reflecting the regional governance scenario in the Dutch Infrastructure Outlook 2050 study. The case study also includes different sensitivity analyses with regard to variable renewable capacity, energy demand and biomass prices to illustrate model response to perturbations of its main drivers. This article demonstrates that the interweaving of electricity, hydrogen and methane systems can provide the required flexibility in the future energy system. [ABSTRACT FROM AUTHOR]

• Electricity and electrification is a viable solution for the energy transition. • Electricity triangle assures a consistent framework for the energy transition. • Multifaceted benefits: energetic, environmental and socio-economic. • Conceptualization of a set of metrics for impact assessment. • A real case study (Italy) considering its evolution up to 2050. Greenhouse gases along with pollution generated by the present energy paradigm widely based on fossil fuels are providing large impacts in terms of climate change and the health of human and biological systems at large. A shift in the energy paradigm, from fossil fuels to renewable energy, is urgently needed for nature and society. This is what we refer to as the energy transition. An old commodity – electricity – can play a new key role in the energy transition. That can happen through what we call the electricity triangle involving electricity generation from Renewable Energy Sources, exploitation of electricity as the main energy vector, and electrification of the final energy uses in all sectors. The possible deployment of the electricity triangle must be carefully assessed in all its possible implications, from technological, economic, societal and environmental perspectives. In this paper, we conceptualize the electricity triangle as a viable approach to the energy transition, and we propose a set of holistic metrics to assess its possible impacts. We apply the electricity triangle framework to the case of Italy based on sectorial studies on RES generation and electrification in building, industry and transport sectors. Our results indicate that Italy in 2050 has the potential to achieve 85.6% penetration of RES in its electricity supply, while 41%, 53% and 42% of the energy consumptions in transport, residential, and industry sectors will be electrified. Ultimately, this would lead to a 68% reduction in CO 2 emissions compared to current levels. [ABSTRACT FROM AUTHOR]

• Community storage systems are conceptualized as complex techno-economic system. • Optimization of the competition between simultaneous residential flexibility options. • Losses due to simultaneous application of flexibility options outweigh the benefits. • Sector coupling constitutes a greater competition factor than demand response. • Community storage systems will become economically profitable in the next few years. Community electricity storage systems for multiple applications promise benefits over household electricity storage systems. More economical flexibility options such as demand response and sector coupling might reduce the market size for storage facilities. This paper assesses the economic performance of community electricity storage systems by taking competitive flexibility options into account. For this purpose, an actor-related, scenario-based optimization framework is applied. The results are in line with the literature and show that community storage systems are economically more efficient than household storage systems. Relative storage capacity reductions of community storage systems over household storage systems are possible, as the demand and generation profiles are balanced out among end users. On average, storage capacity reductions of 9% per household are possible in the base scenario, resulting in lower specific investments. The simultaneous application of demand-side flexibility options such as sector coupling and demand response enable a further capacity reduction of the community storage size by up to 23%. At the same time, the competition between flexibility options leads to smaller benefits regarding the community storage flexibility potential, which reduces the market viability for these applications. In the worst case, the cannibalization effects reach up to 38% between the flexibility measures. The losses of the flexibility benefits outweigh the savings of the capacity reduction whereby sector coupling constitutes a far greater influencing factor than demand response. Overall, in consideration of the stated cost trends, the economies of scale, and the reduction possibilities, a profitable community storage model might be reached between 2025 and 2035. Future work should focus on the analysis of policy frameworks. [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]

• Integrated stakeholder preferences towards equality into electricity planning. • Framework for opportunity-focused approach for electricity planning. • Novel combination of economics, utility maximization, and least-cost frameworks. • Co-optimized generation and transmission investments under equality preferences. Access to electricity can lead to enhanced education, business, and healthcare opportunities. Governments in emerging economies are often faced with the challenge of increasing access to electricity and reducing system inequality, while operating under severe budget constraints. This paper develops a methodology for finding the optimal expansion of a power system under the objective of maximizing social benefit, as it relates to distributional equality for electricity access, subject to a budget constraint. This contrasts with traditional models, which minimize the cost of satisfying projected electricity demand. We formulate a generation expansion planning problem as a utility-maximization mixed-integer linear program and apply it to a case study analysis of a low-income country with limited electricity infrastructure. We focus our analysis on understanding how the optimal allocation of generation between centralized and distributed resources is impacted by stakeholder preferences toward equality and different budget levels. We find that a high preference for equality leads to lower overall electricity consumption levels, but improved electrification rates due to greater investment (300–750 km increase) in transmission infrastructure. If stakeholders move from a low to a high equality preference then they could see a 72–87% increase in energy access equality rating depending on the budget. Conversely, indifference to equality leads to higher overall consumption levels in urban areas but reduced electrification rates. This methodology can help decision makers evaluate the social trade-offs between improving energy access, reducing energy inequality and poverty, and increasing total electricity consumption when operating under budget constraints in their countries. [ABSTRACT FROM AUTHOR]

• Probabilistic simulation of security of electricity supply in central Europe. • Quasi-absolute levels of security of supply are unlikely to be maintained in future scenarios. • Sensitivity of security of supply towards meteorological influences is increasing. • Dependency on contributions from neighboring countries is growing. • Relevance to coordinate capacity planning on an international level is demonstrated. Against the backdrop of expansions of intermittent renewable energy capacity, planned nuclear phase-outs, and current debates on the additional mothballing of coal-fired power plants in central Europe, there is a substantial increase in uncertainty regarding security of electricity supply. In this context, we present a probabilistic and scenario-based analysis of impacts on security of supply for Germany as a case-study in the medium-term perspective (years 2020, 2022, and 2023). For our analysis, we introduce the energy security assessment module of the JERICHO energy system model from RWTH Aachen University. Our model allows for an hourly probabilistic simulation of security of supply and accounts for stochastic characteristics of (non-)availability of conventional generators, renewable feed-in, electricity demand, and import potentials from central-European countries. To increase the robustness of results, we use a comprehensive dataset of temperature, wind speeds, solar radiation and water levels from weather years 1986 to 2015 as input for our simulations. Our results indicate that Germany is unlikely to maintain its quasi-absolute levels of security of supply in the near future with a mean Loss of Load Expectation (LoLE) of up to 2.6 h in scenario year 2023. However, this does not necessarily imply that future levels of security of supply are insufficient. There is need for further assessments on identifying threshold levels for security of supply, which are economically efficient and acceptable for society. Our results also indicate that the sensitivity of security of supply for meteorological changes increases with reductions of conventional power plants. Finally, we demonstrate that the dependency of security of supply on imports from neighboring countries increases substantially calling for increased international coordination of national energy policies. [ABSTRACT FROM AUTHOR]