Integrated community energy systems (ICESs) emerged in the reform of local energy systems during the energy transition. Cost allocation within an ICES is one of the key issues determining the success of ICESs. The costs should be allocated fairly among the members of a local energy community. However, not much research has been directed towards cost allocation in local energy systems. In this paper, firstly, we compare ICESs with large power systems in terms of their physical and cost structure. Secondly, learning from experience with electricity tariff design, we derive cost allocation approaches for ICESs. To this end, we summarize tariff design objectives, cost allocation procedures and the underlying regulatory principles for major tariffication approaches and discuss how these concepts may be applied to cost allocation in ICESs. Discussions on the lessons learned so far and application issues in ICESs are included in this paper. This review paper paves the way for application of fair cost allocation in ICESs by providing a systemic framework.

In this paper, a segmented energy tariff design is proposed to incentivize consumers to flatten load demand. This energy tariff focuses on consumption levels instead of consumption periods. Energy storage is an effective strategy to help to maintain the imported energy from grid below the threshold without affecting the comfort of energy consuming. From economic perspective, both battery size and segmented energy prices should be considered to minimize the total energy cost. For the considered home battery system, when the threshold value and battery size is larger than 0.45 kWh and 3 kWh respectively, the imported energy from grid is zero. When the price ratio is larger than 9, it is beneficial for consumers to response to load flattening with battery to reduce energy cost. It is recommended that policy makers or electricity regulators take the tariff incentive into account to make it attractive for consumers to respond to load flattening.

Managing electric flexibility is of importance for reliable electricity supply, especially in a situation with increasing penetration of renewable electricity production. One of the capabilities of electricity smart grids is the possibility to incorporate distributed energy resources for provision of electric flexibility to the system. This paper presents an approach to determine the investment and short-term average costs of distributed energy resources to supply flexibility services in a local system, and compares those costs to the average costs in the Dutch markets for balancing and day-ahead flexibility. The approach in this paper is useful for techno-economic analysis of flexibility from distributed energy resources and the economic valuation of flexibility for trading in traditional markets. The analysis shows that local flexibility in many cases is much more expensive than centrally provided flexibility.

The decreasing costs of distributed energy resources and increasing need for flexibility have attracted the attention of many in community energy storage (CES) business. CES, however, is a complex sociotechnical system with a variety of technologies, actors, and interactions. In the changing energy landscape, two pathways for CES, namely, local and virtual, are prominent. The range of technical, economic, environmental, and institutional values differ in these pathways. This chapter analyzes business models of multivalue and multiactor CES and provides recommendations for enabling regulatory and governance conditions.

The deployment of offshore wind and power transmission in the European North Sea is accelerating. Stakeholders advocate regional governance for the European grid expansion, which may evolve into a pan-European governance and is key to developing integrated, hybrid offshore projects. However, such projects are still scarce. We thus analyze the governance of the North Sea offshore grid expansion using the dimensions of level, implementation obligation, and implementation discretion. Our exploratory approach identifies five challenges. The challenges relate to 1) the interaction of the European and regional levels; 2) the interaction of the national and regional levels; 3) the participation of non-European Union countries; 4) the dependence of regional planning on national development plans, which consider national interests; and 5) the interaction of cost allocation and European financing for Projects of Common Interest. The recent Clean Energy Package proposal extensively reforms the regulation of the European power system. The Package is part of the Energy Union strategy and focuses on the energy and climate policies’ governance and the power system operation. Thus, regional governance of offshore expansion is largely unaltered, and our identified challenges remain unaddressed.

The development of offshore transmission and wind power generation in the North Sea of Europe is advancing fast, but there are significant barriers to an integrated offshore grid in the region. This offshore grid is a multi-level, multi-actor system requiring a governance decision-making approach, but there is currently no proven governance framework for it, or for the expansion planning of the European power system in general. In addition, existing offshore expansion planning models do not endogenously include governance considerations, such as country vetoes to integrated lines. We develop a myopic Mixed-Integer Linear Programming model of offshore generation and transmission expansion planning to study the effect of integrated governance constraints. These constraints limit investments in integrated lines: non-conventional lines linking offshore wind farms to other countries or to other farms. Each constraint affects the system (including the main transmission corridors), transmission technologies and welfare distribution differently. We apply our model to a long-term case study of the 2030–2050 offshore expansion pathways using data from the e-Highway2050 project. Results confirm that the offshore grid is beneficial to society. Integrated governance constraints induce a modest loss of social welfare, but do not change significantly the existing welfare distribution asymmetry between countries and actor groups. They do strongly affect the interaction of line technologies and types (conventional or integrated), so the impact of the integrated governance constraints is more visible on the grid topology than on welfare levels and distribution. We highlight the need to consider technology and type interactions in expansion planning, especially between multiterminal HVDC and integrated transmission lines. Also, an offshore governance framework should address the use of multiterminal HVDC in a non-integrated grid, but this is a second-best option compared to an integrated grid.

In order to decarbonize the energy sector, there is a widespread consensus that the role of end-users in the energy system should change from passive consumption to active prosumption and engagement. This is of particular importance as an increasing number of technologies and business models are focusing on the end-users. These developments provide new opportunities for further technical and social innovation to smarter, flexible and integrated systems such as community energy systems (CESs). Through system integration and community engagement CESs assist in transition to a low-carbon energy system. Despite the high importance, there is limited knowledge on willingness of local citizens to participate in the local energy systems such as CESs as well as associated factors determining such willingness. Through a survey among 599 citizens in the Netherlands, this research analyses the impact of demographic, socio-economic, socio-institutional as well as environmental factors on willingness to participate in CESs. Factor and multi-variate regression analysis reveals that the environmental concern, renewables acceptance, energy independence, community trust, community resistance, education, energy related education and awareness about local energy initiatives are the most important factors in determining the citizens’ willingness to participate in CESs. Citizens should be empowered to take active role in steering the local energy initiatives.

HVDC innovations and the integration of power markets and renewables drive the development of a European Northern Seas offshore grid. This power transmission system performs two functions: interconnecting Northern European onshore power systems, and connecting offshore wind farms. Despite its benefits, the development of an integrated offshore grid combining the two functions is slow. The main reasons are the lack of cooperation and governance frameworks to overcome regional differences and distribute costs and benefits. These barriers were studied so far only qualitatively or through perfect foresight optimization models. We complement this by studying transmission expansion pathways of the grid, which are non-optimal and path dependent, using a novel and open-source simulation model for offshore transmission investments. Different expansion typologies are considered, which we find perform the grid functions with different levels of integration and transmission capacities. Besides these typology factors, modelling and simulation factors also affect the expansion selection. Typology, modelling and simulation factors interact to result in radically different offshore grid pathways, which exhibit strong path dependence. Thus, to avoid locking-out beneficial expansions for the Northern Seas offshore grid, planning should be regional and consider HVDC innovations. Then individual projects can be implemented based on their own merits.

Offshore wind will contribute to the decarbonization of European power systems, but is currently costlier than many other generation technologies. We assess the adequacy of market strategies available to private actors developing offshore wind farms in Europe, by employing the development and diffusion pattern model. The model includes two earlier phases in addition to the large-scale deployment phase of other diffusion models: the innovation and the market adaptation phases. During its development and diffusion offshore wind moved from experimentation to a dominant design (monopile foundations and a permanent magnet generator). Simultaneously, wind farms shifted from an experimental to a commercial purpose and grew from 10 to 316 MW on average. The turbine and wind farm development markets kept a high concentration throughout all phases. Also, the wind farm life cycle and supply chain became more integrated and drew less from the onshore wind and oil & gas sectors. This development and diffusion was shaped by the barriers of cost, project risk and complexity, capital requirements, and multi-disciplinarity. Wind farms developers combined three niche strategies to address these barriers: the subsidized, the geographic, and the demo, experiment and develop. The barriers make these niche strategies more adequate than strategies of mass-market (dominating a market) or wait-and-see (developing resources but waiting for uncertainty reduction before market entrance). Nonetheless, the barriers and market strategies changed during the development and diffusion pattern. Thus, cost and risk reductions decreased the importance of the subsidized niche, while the geographic niche becomes less important as offshore wind develops outside of Europe. The study also identified an increase in cooperation for wind farm development, as development became more international and with more frequent alliances. Wind farm developers and development and diffusion models research must consider how contemporary forms of cooperation improve or hinder the market strategies.

Integrated Community Energy Systems (ICESs) are emerging as a modern development to re-organize the local energy systems allowing integration of distributed energy resources (DERs) and engagement of local communities. Although local energy initiatives such as ICESs are rapidly emerging, assessment and evaluation are still lacking on the value these systems can provide both to the local communities as well as to the whole energy system. In this paper, we present a framework to assess the value of ICESs for local communities. We apply this framework to assess the value of ICES in Spain. For a block of 10 households, investments and operations of DERs together with local exchange is simulated in DER-CAM model. For the considered community size and local conditions, ICESs are beneficial to the alternative of solely being supplied from the grid. An ICES that gets remunerated the excess energy to the grid has higher benefits than the system where energy exports are not remunerated as currently in Spain.