• Energy Research

This study is concerned with the national transposition of the European Renewable Energy Directive into Austrian law. The objective is to estimate the economic viability for residential customers when participating in a renewable energy community (REC), focused on PV electricity sharing. The developed simulation model considers the omission of certain electricity levies as well as the obligatory proximity constraint being linked to grid levels, thus introducing a stepwise reduction of per-unit grid charges as an incentive to keep the inner-community electricity transfer as local as possible. Results show that cost savings in residential RECs cover a broad range from 9 EUR/yr to 172 EUR/yr. The lowest savings are gained by customers without in-house PV systems, while owners of a private PV system make the most profits due to the possibility of selling as well as buying electricity within the borders of the REC. Generally, cost savings increase when the source is closer to the sink, as well as when more renewable electricity is available for inner-community electricity transfer. The presence of a commercial customer impacts savings for households insignificantly, but increases local self-consumption approximately by 10%. Despite the margin for residential participants to break even being narrow, energy community operators will have to raise a certain participation fee. Such participation fee would need to be as low as 2.5 EUR/month for customers without in-house PV systems in a purely residential REC, while other customers could still achieve a break-even when paying 5 EUR/month to 6.7 EUR/month in addition. Those results should alert policy makers to find additional support mechanisms to enhance customers’ motivations to participate if RECs are meant as a concept that should be adopted on a large scale.

This study is concerned with the national transposition of the European Renewable Energy Directive into Austrian law. The objective is to estimate the economic viability for residential customers when participating in a renewable energy community (REC), focused on PV electricity sharing. The developed simulation model considers the omission of certain electricity levies as well as the obligatory proximity constraint being linked to grid levels, thus introducing a stepwise reduction of per-unit grid charges as an incentive to keep the inner-community electricity transfer as local as possible. Results show that cost savings in residential RECs cover a broad range from 9 EUR/yr to 172 EUR/yr. The lowest savings are gained by customers without in-house PV systems, while owners of a private PV system make the most profits due to the possibility of selling as well as buying electricity within the borders of the REC. Generally, cost savings increase when the source is closer to the sink, as well as when more renewable electricity is available for inner-community electricity transfer. The presence of a commercial customer impacts savings for households insignificantly, but increases local self-consumption approximately by 10%. Despite the margin for residential participants to break even being narrow, energy community operators will have to raise a certain participation fee. Such participation fee would need to be as low as 2.5 EUR/month for customers without in-house PV systems in a purely residential REC, while other customers could still achieve a break-even when paying 5 EUR/month to 6.7 EUR/month in addition. Those results should alert policy makers to find additional support mechanisms to enhance customers’ motivations to participate if RECs are meant as a concept that should be adopted on a large scale.

Abstract This study investigates the profitability of implementing active and passive building retrofitting measures, either individually or combined, within the framework of contracting. Three contracting models are investigated: (i) Photovoltaic (PV) contracting, (ii) renovation contracting, (iii) PV and renovation contracting including a heating system change. Since this study’s practical approach focuses on the client (building owner), an optimisation model is developed that maximises the client’s net present value, subject to a guaranteed pay-off including profit for the contractor. An algorithm allows to exactly quantify the impact of renovation measures on the heat load. The results show that PV system contracting is profitable for contractors and clients, while the profitability of passive retrofitting measures (e.g. building envelope renovation) significantly depends on the additional costs for CO2 emissions as well as on the default heating system. The contracting framework itself decreases the profitability of retrofitting measures since the contractor as a third party awaits to gain profit as well. The significance of said impact depends heavily on the contractor’s expected interest rate. In conclusion, in order to boost the shares of holistically retrofitted buildings (with or without PV integration), increasing costs for CO2 emissions increase attractiveness for both the contractor, and the clients.

Abstract This study investigates the profitability of implementing active and passive building retrofitting measures, either individually or combined, within the framework of contracting. Three contracting models are investigated: (i) Photovoltaic (PV) contracting, (ii) renovation contracting, (iii) PV and renovation contracting including a heating system change. Since this study’s practical approach focuses on the client (building owner), an optimisation model is developed that maximises the client’s net present value, subject to a guaranteed pay-off including profit for the contractor. An algorithm allows to exactly quantify the impact of renovation measures on the heat load. The results show that PV system contracting is profitable for contractors and clients, while the profitability of passive retrofitting measures (e.g. building envelope renovation) significantly depends on the additional costs for CO2 emissions as well as on the default heating system. The contracting framework itself decreases the profitability of retrofitting measures since the contractor as a third party awaits to gain profit as well. The significance of said impact depends heavily on the contractor’s expected interest rate. In conclusion, in order to boost the shares of holistically retrofitted buildings (with or without PV integration), increasing costs for CO2 emissions increase attractiveness for both the contractor, and the clients.

Energy communities have been designed to promote sustainable development in the form of improved and affordable energy access, sustainable generation, and social inclusion. As their legislative background continues to evolve, future upgrades are expected to increase the benefits that these novel energy concepts offer. In Austria, from 2024 onwards, it will be possible to participate in more than one energy community at the same time; as such, it is necessary to evaluate the potential benefits for participants and the existing electricity grid. Thus, in this study, an optimization model is proposed to allocate the demand and production of each participant, generation unit, and storage initially belonging to different communities that are implemented under the same distribution transformer and engage in multiple participation. Both energy- and grid-related costs are minimized, and the benchmark independent energy community case is compared with the novel multiple participation. The influence of participants’ acceptance on providing flexibility (in the form of load shedding) is assessed through sensitivity analysis. The results show that, compared to the independent case, multiple participation could provide additional reductions in terms of emissions (3.5%), costs (up to 10%), and peak demand (up to 29%) at the transformer level. However, communities with higher generation shares could be individually disadvantaged compared to those with lower generation shares. Storage could also assist in reducing costs and peak demand, but at the cost of faster aging and with relatively small differences between the independent and multiple participation cases.

Energy communities have been designed to promote sustainable development in the form of improved and affordable energy access, sustainable generation, and social inclusion. As their legislative background continues to evolve, future upgrades are expected to increase the benefits that these novel energy concepts offer. In Austria, from 2024 onwards, it will be possible to participate in more than one energy community at the same time; as such, it is necessary to evaluate the potential benefits for participants and the existing electricity grid. Thus, in this study, an optimization model is proposed to allocate the demand and production of each participant, generation unit, and storage initially belonging to different communities that are implemented under the same distribution transformer and engage in multiple participation. Both energy- and grid-related costs are minimized, and the benchmark independent energy community case is compared with the novel multiple participation. The influence of participants’ acceptance on providing flexibility (in the form of load shedding) is assessed through sensitivity analysis. The results show that, compared to the independent case, multiple participation could provide additional reductions in terms of emissions (3.5%), costs (up to 10%), and peak demand (up to 29%) at the transformer level. However, communities with higher generation shares could be individually disadvantaged compared to those with lower generation shares. Storage could also assist in reducing costs and peak demand, but at the cost of faster aging and with relatively small differences between the independent and multiple participation cases.

While electricity-based energy communities (ECs) have received significant scientific attention, heat-based ECs have not gotten the attention they deserve. This paper builds upon the hypothesis that ECs could be a lever to increase the adoption rates of district heating and thus contribute significantly to decarbonise the heating sector. In order to unleash this presumed potential and close a research gap, a conceptual planning framework is introduced, encompassing EC-tailored heat infrastructure planning and cost sharing mechanisms to distribute the financial burden between individual participants based on transparent criteria. For the efficient and EC-suitable planning of a district heating grid, a shortest path problem is solved using Dijkstra’s algorithm. To address the issue of distributing investment costs among EC participants, eight different cost sharing scenarios are developed. These distinguish between costs for heat generation devices and costs for the heating grid, the latter being further sub-categorised into grid lines on the properties of participating parties and common/third property. The developed framework is then applied to a case study of eight residential buildings and three heat generation sites in a city area. Thereby it is found that the cost variance between different cost sharing scenarios lies between 19.1% and 42.6%. From converting heat infrastructure costs per property to annuities for a time horizon of 30 years, it can be concluded that such investments could remain a significant hurdle for private building owners unless suitable investment incentives are proposed by policy decision makers.

While electricity-based energy communities (ECs) have received significant scientific attention, heat-based ECs have not gotten the attention they deserve. This paper builds upon the hypothesis that ECs could be a lever to increase the adoption rates of district heating and thus contribute significantly to decarbonise the heating sector. In order to unleash this presumed potential and close a research gap, a conceptual planning framework is introduced, encompassing EC-tailored heat infrastructure planning and cost sharing mechanisms to distribute the financial burden between individual participants based on transparent criteria. For the efficient and EC-suitable planning of a district heating grid, a shortest path problem is solved using Dijkstra’s algorithm. To address the issue of distributing investment costs among EC participants, eight different cost sharing scenarios are developed. These distinguish between costs for heat generation devices and costs for the heating grid, the latter being further sub-categorised into grid lines on the properties of participating parties and common/third property. The developed framework is then applied to a case study of eight residential buildings and three heat generation sites in a city area. Thereby it is found that the cost variance between different cost sharing scenarios lies between 19.1% and 42.6%. From converting heat infrastructure costs per property to annuities for a time horizon of 30 years, it can be concluded that such investments could remain a significant hurdle for private building owners unless suitable investment incentives are proposed by policy decision makers.