Distributed energy resources in the electricity supply market: participation pathways, applications, challenges, and key recommendations—a European perspective

1 Introduction

Small- or medium-sized resources that are directly connected to the distribution network (low- or medium-voltage) rather than to the bulk transmission system are defined as distributed energy resources (DERs) (Dudjak et al., 2021; Adham et al., 2025). DERs comprise a set of devices that enable the integration of distributed generation and help address key challenges such as intermittency and limited dispatchability. Distribution energy markets refer to localized markets in which DERs can be bought and sold while interacting with the distribution grid (Calvillo et al., 2016; Cossent et al., 2009; Scrocca et al., 2026). DERs include both energy storage systems (ESSs) (such as batteries, flywheels, and superconducting magnetic energy storage) and flexible electrified loads such as electric vehicles (EVs), as well as generation units such as fuel cells, micro turbines, photovoltaics, and wind units. Different DER technologies, including both generation units and energy storage systems, are illustrated in Figure 1.

Moreover, to reduce carbon emissions and protect the environment, industrialized nations are experiencing increasing penetration of renewable and distributed energy resources in their power systems, particularly solar PV, wind generation, distributed storage and flexible electrified demand such as EVs and heat pumps (Akorede et al., 2010; Eid et al., 2016; Qadir et al., 2024; Zakeri et al., 2021). Socio-economic drivers, including the need for low-carbon electricity, local resilience and reduced dependence on fossil-fuel-based supply, have accelerated the deployment of RESs and DERs in recent years. Their integration into transmission and distribution networks is increasingly linked to decentralized-energy operation, storage deployment, local market participation and community-scale energy management (Dudjak et al., 2021; Calvillo et al., 2016; Basak et al., 2012; Eid et al., 2016). The growing penetration of RESs into the grid is closely connected with decentralized energy systems, in which local control supports local energy production and distribution. These systems are based on distributed renewable energy sources (DRESs) at a local jurisdiction to address local demand (Basak et al., 2012). Decentralized resources have comparative advantages over centralized energy systems by bringing generation nearer to end users, reducing complexity, cost, and inefficiencies and enhancing energy independence, increasing local resilience, and supporting a faster transition to net-zero emissions (Eid et al., 2016; Qadir et al., 2024). This is a fast-developing field that can stimulate innovation, give users greater control, and promote interaction among local communities. Together with the growing use of DER and grid-level digitalization, new paradigms of decentralized energy-exchange have arisen to sustain endogenous local resources and improve environmental outcomes, often presented as local energy markets. Local energy markets have recently become a focus of considerable attention in the literature due to their potential to facilitate a more active participation by end-users (Le Ray et al., 2016; Molderink et al., 2010; Taromboli et al., 2025). Mengelkamp et al. defined local energy markets as close and user-centric communities of users (prosumers and consumers) that are able to use a common market platform to help them trade electricity that has been produced locally (Mengelkamp and Weinhardt, 2018). The purpose of these markets is to enable the effective incorporation of DERs or DRESs into the energy system that can reduce costs, improve reliability, and create new revenue streams for consumers. Examples of user-centric market paradigms include peer-to-peer (P2P) trading, transitive energy (TE), and community self-consumption (CSC). All these approaches rely on information and communication technologies (ICT) to enable efficient and sustainable energy transactions (Teotia and Bhakar, 2016). Blockchain and other distributed ledger technologies are among the most widely adopted solutions for P2P market platforms (IRENA, 2020).

Despite this rapid evolution, the practical integration of DERs in distribution electricity markets remains difficult because the problem is inherently cross-domain. Distribution networks impose locational and operational constraints (congestion, voltage regulation, hosting capacity, protection), while markets define products and eligibility rules (time resolution, verification/baselines, minimum bid size, penalties), and real deployments reveal that DERs typically operate as portfolios with user-driven constraints (availability, aggregation needs, controllability limitations). As a result, conclusions drawn within a single strand (network studies, market design studies, or application case studies) often do not translate into actionable guidance on which DER portfolios can deliver which services, through which market/procurement layer, and under which TSO/DSO governance conditions. This review therefore synthesizes these strands into a consistent mapping from capability to services to market layer to governance requirements.

The literature relevant to DER participation in distribution electricity markets is extensive, but it is largely segmented: network-oriented work focuses on technical constraints; market-oriented work focuses on product definitions and participation rules; and application-oriented work reports case-specific outcomes that are difficult to compare across contexts. For decision-makers (DSOs/TSOs, regulators, aggregators, technology providers), the missing piece is often an explicit, evidence-based link between DER capability, service families, market/procurement layers, and governance roles. This review addresses that gap by providing an integrated European-focused synthesis of renewable-based DER portfolios and their participation pathways across distribution-level electricity markets.

1.1 Review design and synthesis method

This article adopts a structured review combined with an analytical synthesis of distributed-resource participation pathways. The review scope covers distributed resources and resource portfolios that can contribute to electricity-market participation, flexibility provision, and distribution-level system operation. The technological scope includes distributed photovoltaic generation, small wind, stationary storage, flexible demand, heat pumps, electric-vehicle smart charging, and vehicle-to-grid operation. The review also considers aggregation platforms, local energy markets, microgrids, and energy communities as coordination environments that influence resource observability, controllability, market access, and governance.

The geographical focus is Europe, because European electricity-market reform, demand-response regulation, independent aggregation, local flexibility procurement, and energy-community legislation provide a distinctive institutional context for distributed-resource participation (European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; ACER, 2025a). Non-European studies are included when they provide transferable evidence on distributed-resource capabilities, microgrid deployment, flexibility metrics, aggregation, market-design barriers, or community-scale implementation. Evidence from non-European contexts can also support the interpretation of renewable-energy integration barriers when it clarifies how resource deployment, infrastructure readiness, policy evolution and system reliability interact under practical energy-sector constraints (Shaikh et al., 2020).

The literature was selected according to four criteria. First, studies were considered when they addressed at least one of the following dimensions: distributed-resource capability, distribution-network constraints, electricity-market participation, local flexibility procurement, aggregation, demand response, energy communities, microgrids, or transmission–distribution coordination. Second, recent sources were prioritized for topics characterized by rapid technological, regulatory, or market evolution, particularly demand response, local flexibility markets, energy communities, aggregation, storage, electric vehicles, and European electricity-market reform. Third, foundational works were retained when they provided established definitions, widely adopted technical concepts, or reference frameworks for market design and distribution-network integration. Fourth, studies were selected when their findings supported the construction of the resource taxonomy, the market/service taxonomy, the governance mapping, or the participation-feasibility assessment.

The synthesis was developed in three stages. First, the literature was organized into distribution-network, market-design, and application-oriented strands. Second, these strands were translated into two linked taxonomies: a distributed-resource capability taxonomy and a market/service/governance taxonomy. Third, the two taxonomies were integrated into a capability-to-market mapping that relates resource classes and portfolios to feasible services, procurement layers, technical prerequisites, and governance conditions. To support comparative interpretation, the mapping is complemented by a participation-feasibility index based on controllability, response-time compatibility, duration adequacy, metering and telemetry readiness, baseline feasibility, aggregation requirements, locational relevance, and regulatory eligibility.

1.2 Novelty and motivation of the work

Existing review strands relevant to distributed energy resources (DERs) tend to address the topic from single entry points, such as: local energy markets and flexibility markets (Dudjak et al., 2021), real-time and balancing market participation for DERs and demand response, energy communities and local energy systems under European regulation (Eid et al., 2016), microgrids as an enabling architecture (Basak et al., 2012), or TSO–DSO coordination for flexible grid operation. As a consequence, actionable guidance is often fragmented across market layers (wholesale/balancing vs. retail vs. local flexibility), across services (energy vs. congestion/voltage/frequency), and across governance (TSO/DSO roles). A synthesis lens is therefore needed to connect physical capability, service definition, market layer, and governance into a single participation map.

The contribution of this article is structured around six outputs. First, it develops a distributed-resource taxonomy based on technology class, controllability, response-time range, duration, location, ownership model, and aggregation requirement. Second, it defines a market/service taxonomy that distinguishes wholesale, retail/community, local-flexibility, and balancing/ancillary-service layers, while separating service type from procuring or coordinating actor. Third, it introduces a governance dimension that explicitly accounts for the roles of transmission system operators, distribution system operators, suppliers, aggregators, market operators, energy communities, and local flexibility platforms. Fourth, it integrates these elements into a DER–Service–Market–Governance framework linking physical capability, service requirement, market access, and institutional coordination. Fifth, it develops a capability-to-market mapping matrix that identifies feasible participation pathways, technical prerequisites, and implementation barriers for representative resource portfolios. Sixth, it introduces a participation-feasibility index to compare the suitability of distributed-resource portfolios across different market and procurement layers.

These outputs are then used to derive key benefits and challenges and a European-oriented roadmap of short-, mid-, and long-term actions for regulators, DSOs/TSOs, aggregators, and technology providers. The relevance of this study is emphasized by the issue that climate change, increasing electrification, and concerns about distribution-grid constraints (congestion, voltage, hosting capacity) strengthen the need to move from purely centralized supply toward cleaner, flexible and resilient systems. Renewable-based DERs can reduce losses, increase local self-consumption, and provide flexibility services if their technical capabilities are matched to suitable market products and procurement schemes. However, large-scale adoption requires a clear understanding of

• what DERs can technically deliver,
• where value is captured across market layers, and
• which regulatory and digital prerequisites enable participation.

This review addresses these needs through the operational framework and mapping introduced above.

Table 1 positions the present review against representative strands of recent and foundational literature on local energy markets, local flexibility markets, microgrids, energy communities, demand response, aggregation, and transmission–distribution coordination. The comparison emphasizes the extent to which each strand links resource-level capabilities, market products, procurement layers, and governance actors. This positioning clarifies the role of the DER–Service–Market–Governance framework as an integrative structure for connecting technical feasibility, market participation, and European regulatory coordination.

TABLE 1. Current review positioning against existing research.

1.3 DSMG synthesis approach

This review is organized around a DER–Service–Market–Governance (DSMG) perspective, which reflects how distributed flexibility is actually created and valued in European power systems. In practice, DER impacts cannot be interpreted in isolation: what a DER can deliver depends on distribution-network operating constraints, what it is paid for depends on market products and procurement rules, and what is feasible in the field is revealed by deployment evidence and typical portfolios (rather than single technologies). The DSMG perspective is introduced here to make these dependencies explicit and to clarify how the subsequent sections connect to the integrative synthesis.

Within DSMG, the starting point is DER capability, i.e., the physically deliverable flexibility attributes of an asset or portfolio (controllability, response time, duration, and, crucially for distribution systems, locational relevance). The Electrical Power System Network strand provides the operational context in which these capabilities matter, including feeder-level congestion, voltage regulation needs, hosting-capacity limits, protection constraints, and the growing requirement for observability and controllability at the distribution level. These elements determine whether flexibility is meaningful locally (node/feeder-specific) or system-wide and set the technical boundary conditions for service provision.

In this review, flexibility is understood as the ability of a resource, portfolio or system to adjust active-power injection, active-power consumption, reactive-power exchange or operating schedule in response to expected or unexpected changes in generation, demand, network conditions or market signals, while preserving reliability and service constraints. Power-system flexibility therefore depends not only on installed capacity, but also on ramping capability, response time, duration, location, observability, controllability and the availability of suitable market or operational signals (Eltohamy et al., 2020; 2026). Distributed flexibility refers to the portion of this capability that is provided by distribution-connected resources, including photovoltaic systems, batteries, electric vehicles, heat pumps, flexible loads, microgrids and energy communities.

The next step is the translation of capability into service products and procurement layers. The Electricity Market strand therefore distinguishes between the market/procurement layers through which flexibility is exchanged (wholesale energy, balancing/ancillary services, retail/community schemes, local flexibility procurement) and the service families that define what is being delivered (e.g., energy shifting, peak reduction, congestion management, voltage/reactive support, frequency services). It also clarifies the role of the procuring actor (TSO, DSO, supplier, market operator), because eligibility, timing, minimum bid sizes, baseline definitions, settlement, and performance verification rules may render the same physical flexibility valuable in one layer but impractical or non-comparable in another.

The Applications strand anchors DSMG in real deployments, where DERs appear as portfolios and contexts such as PV coupled with stationary storage, EV fleets with controlled charging/V2G, demand response from buildings and industry, microgrids and energy communities, and hybrid combinations. Applications provide recurring evidence on availability, aggregation needs, user constraints, and implementation barriers (e.g., telemetry, data access, baseline construction, contractual limitations), which is essential to interpret “feasibility” beyond the device level.

The DSMG perspective is then made explicit in the integrative synthesis tables. Table 2 defines a DER taxonomy in terms of capability and controllability attributes relevant to distribution operation and flexibility provision; Table 3 defines a market/service taxonomy that separates procurement layers, service families, and procuring actors; and Table 4 integrates these taxonomies into a capability-to-market mapping matrix. The mapping reports, by DER class/portfolio, the services that are generally feasible across market layers together with the typical technical prerequisites (metering granularity, telemetry, controllability interfaces, baseline and verification requirements, aggregation) and the main barriers/risks that limit participation or reduce comparability across jurisdictions and case studies. This provides the structured bridge from the technical background and application evidence to the final synthesis and roadmap-oriented discussion.

TABLE 2. DER taxonomy based on capability and controllability classes for distributed resources and portfolios in the European context.

TABLE 3. Market/service taxonomy separating market layer, typical products, settlement logic, and procuring actor in the European context.

TABLE 4. DSMG integrated capability-to-market mapping matrix by DER class, service family, and market or procurement pathway.

1.4 Paper organization

The article is organized as follows. Section 1 defines the review scope, methodological approach, contribution, and positioning of the work. Section 2 discusses distributed renewable resources, distribution-network constraints, distributed-generation penetration issues, and the evolving roles of distribution and transmission system operators. Section 3 reviews electricity-market and procurement layers relevant to distributed-resource participation, including wholesale, retail/community, local flexibility, and balancing/ancillary-service mechanisms. Section 4 examines application contexts, including photovoltaic-storage portfolios, electric vehicles, flexible loads, microgrids, aggregation schemes, and energy communities. Section 5 presents the DER–Service–Market–Governance framework, the taxonomies, the capability-to-market mapping, and the participation-feasibility index. Section 6 applies the framework to an illustrative European portfolio comparison. Section 7 discusses benefits, barriers, and roadmap-oriented recommendations. Section 8 identifies limitations and future research needs. Section 9 concludes the paper.

2 Distributed resources in active distribution networks: hosting capacity, operational constraints, and digitalization

Distributed energy resources modify the operation of distribution networks by introducing variable local generation, flexible demand, bidirectional power flows, inverter-based control capabilities, and new requirements for observability, controllability, data exchange and coordination. In traditional radial distribution networks, power flows were mainly unidirectional from the transmission interface toward end users. With increasing deployment of photovoltaic systems, small wind units, stationary batteries, electric vehicles, heat pumps, and flexible demand, the same network can experience local generation surplus, reverse power flow, voltage rise, feeder congestion, altered short-circuit levels, protection-coordination challenges and power-quality issues (Gandhi et al., 2020; Qamar et al., 2023; Saxena et al., 2024; Tariq et al., 2021). These network effects are central to distributed-resource market participation, because a technically controllable resource cannot be considered fully available for market activation unless its operation remains compatible with local grid constraints, interconnection requirements and distribution-system-operator coordination procedures (Uzum et al., 2024; IEEE, 2018; Narang et al., 2021; Schwägerl et al., 2026). Consequently, this section first reviews the transition from passive distribution networks to active distribution-network operation, then discusses distributed-resource capability profiles, penetration and hosting-capacity metrics, voltage, thermal, reverse-flow and protection constraints, the evolving role of DSOs, and the digital infrastructure needed to make DER flexibility observable, controllable and verifiable in market and procurement mechanisms (EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025; European Commission, 2022; EU DSO Entity and ENTSO-E, 2024; Wickramasinghe et al., 2025).

2.1 Electrical power system network and transition toward distributed operation

Over the last century, the global power industry has undergone a transformation, with a shift toward mostly large-scale centralized energy systems that consume fossil fuels and have significant environmental implications. These systems are mainly controlled and managed by large investor-owned or state-owned businesses, driven by the social objective of achieving universal energy access due to the industry’s significant contribution to societal welfare and economic advancement. This centralized structure has also brought issues related to financing and the efficient operation of interconnected power systems (Sperling et al., 2011; Gui and MacGill, 2018). Figure 2 depicts the electrical power system network and its main components, namely, generation, transmission, distribution, and utilization. Each component plays a specific role. In this structure, the transmission network connects power generation to the distribution system, which is responsible for delivering electricity to end consumers, while primary energy sources serve as the starting point of the electricity-generation chain (Shaikh et al., 2020).

Additionally, distributed generation, including both renewable and non-renewable energy sources, can be integrated into the distribution network, providing benefits such as local generation, local control, energy trading among participants, and environmental and social advantages (Eid et al., 2016). Distributed generation (DG) systems provide local control over the production and distribution of energy by using available renewable energy systems (DRESs) to satisfy local energy demand (Basak et al., 2012). They can reduce complexity, costs, and inefficiencies and enhance energy autonomy and local resilience. Decentralized systems can foster innovation through the effective use of RESs, community participation, and participant empowerment. To support decentralized energy systems through renewable-energy sharing, energy savings, and enhanced energy flexibility, cooperative energy strategies such as energy sharing are beginning to emerge. The integration of local DRESs and the involvement of local communities represent effective ways to address changes in the local energy environment (Koirala et al., 2016a; Mendes et al., 2011).

The transition described above changes the function of the distribution network. Rather than acting only as the final delivery stage of centrally generated electricity, the distribution system becomes the physical layer where generation, storage, demand response, electrified end uses, and local market participation interact. This makes distribution-network constraints central to DER participation in electricity markets, because market activation must remain compatible with voltage, thermal, hosting-capacity, protection, and observability limits.

2.2 Distributed renewable energy sources and resource capability profiles

The term distributed energy resources (DERs) refers to a wide category of distributed technologies and operational measures that enable the incorporation of renewable energy sources (RESs) into power systems and alleviate challenges related to variability, uncertainty, and lack of dispatchability. Generally speaking, DERs consist of small-scale generation, storage, and flexible demand resources located close to consumption points, i.e., rooftop photovoltaic (PV) systems, behind-the-meter batteries, and controllable electric-vehicle charging infrastructure. Increasing environmental demands and the risks posed by climate change add urgency to the transformation of energy systems through the progressive substitution of traditional emission-intensive generation with RES-based energy. There is a variety of RES options, as shown in Figure 3 (Worku et al., 2024). These resources are generally associated with lower environmental impacts and greater sustainability, and have become increasingly relevant for decentralized and distributed energy-system development (Akorede et al., 2010; Kamran, 2018). In addition to decarbonization, the implementation of RESs may improve energy security, provide benefits for public health and wellbeing through reduced air pollution, create new employment opportunities, and promote technological innovation, supporting sustainable and inclusive development pathways (Shaikh et al., 2020). The resulting transition has increased the penetration of decentralized resources in electricity networks. Local decentralized energy resources can reduce losses and network inefficiencies, build local resilience, increase energy independence, and facilitate the transition to low- and eventually zero-carbon energy systems relative to purely centralized architectures by bringing generation closer to end users (Eid et al., 2016).

For economic, environmental, and energy-security motivations, many countries worldwide aim to increase the share of renewable energy in their electricity mixes. Accordingly, a wide range of incentives and support schemes has been introduced to accelerate RES deployment through decentralized and distributed generation, particularly consumer-sited solar PV, to help meet national renewable-energy targets (Qadir et al., 2024). European climate and electricity-market policy similarly frames decarbonization, consumer participation, storage, demand response and non-fossil flexibility as central elements of the energy transition (European Commission, 2023; 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; ACER, 2025a). The distribution and competitiveness of certain RES technologies depend on the geographical area; nevertheless, solar energy has become one of the most widely used renewable resources. The abundance and ubiquity of solar irradiation support solar technologies, which convert radiant solar energy into useful energy carriers (Shahsavari and Akbari, 2018). Solar photovoltaic (PV) is the predominant distributed technology among solar technologies because of falling prices and accelerated international deployment. Cumulative PV installations have increased rapidly, making PV one of the most widely deployed electricity-generation technologies, with continuous decreases in module costs and continuing improvements in performance (Gielen et al., 2016; International Energy Agency, 2024). In island, remote and rural regions affected by supply shortages, distributed renewable systems, floating PV options and PV-based mini-grids can support electrification and reliability goals (Esparza et al., 2024; Ahmad et al., 2022; Balakrishnan, 2006; Woldeyohannes et al., 2016; Yan et al., 2017). In 2022, solar PV generation was about 1,300 TWh, increasing by approximately 270 TWh, corresponding to about 26% growth. This was the largest annual increase among renewable technologies in that year, surpassing wind generation growth for the first time. The identified growth trend corresponds to the pattern needed according to the Net Zero Emissions by 2050 Scenario in 2023. PV capacity additions are expected to accelerate further given continued cost competitiveness, supply-chain expansion, and supportive policy frameworks, particularly across China, the United States, the European Union, and India. Consequently, in 2023 the PV “tracking status” was updated from “more effort needed” to “on track” (International Energy Agency, 2024). At the device level, distributed PV participation also depends on local power-electronic conversion and maximum-power-point tracking performance, since converter control affects usable energy extraction and operational stability under variable irradiance; perturb-and-observe MPPT and buck–boost converter strategies have therefore been examined as practical control options for photovoltaic systems (Shaikh et al., 2023; Bhan et al., 2021). At the portfolio level, rooftop renewable-energy selection in dense residential buildings may require multi-criteria evaluation of PV, small-wind and storage alternatives, because cost, energy reduction and avoided emissions do not necessarily identify the same preferred solution (Minelli et al., 2026).

From the perspective of active distribution-network operation, DERs should also be classified according to their capability profile, because their value for network operation and market participation depends on controllability, response time, duration, location, observability and activation constraints (Dudjak et al., 2021; Wang et al., 2015; Schwägerl et al., 2026). Variable distributed generation, such as photovoltaic and small wind systems, primarily provides energy injection whose availability depends on weather, resource variability and local operating conditions (Morales et al., 2012; Baghaee et al., 2017a; Gandhi et al., 2020). In small distributed wind systems, local resource quality and turbine design also affect practical energy yield, and recent optimization work on small horizontal-axis wind turbines shows that airfoil selection should be adapted to the wind potential of the target region (Akbari et al., 2022). Stationary batteries and electric vehicles provide bidirectional active-power flexibility, subject to state of charge, connection time, user constraints, converter rating, grid-level adaptability and degradation considerations (Müller et al., 2017). Flexible loads, including heat pumps, building heating, ventilation and air-conditioning systems, refrigeration, and industrial processes, provide demand-side flexibility through load shifting, modulation, or temporary curtailment. Inverter-interfaced resources can also provide reactive-power and voltage-support functions when allowed by grid codes, interconnection requirements, and control settings (Altayara et al., 2024; IEEE, 2018; Narang et al., 2021).

The relevant distinction for distribution-network operation is therefore not only the technology type but also the capability profile, because active distribution-network operation and flexibility-market participation require matching resource attributes with network constraints, market products and procurement requirements (Dudjak et al., 2021; Chondrogiannis et al., 2022; Wang et al., 2015; Schwägerl et al., 2026). A resource portfolio must be characterized by active-power controllability, reactive-power capability, response time, duration, ramping limit, location, metering resolution, communication interface, aggregation requirement, and the degree to which its activation affects feeder voltages and currents (Uzum et al., 2024; Altayara et al., 2024; IEEE, 2018; Narang et al., 2021; Schwägerl et al., 2026). These characteristics determine whether the resource can support energy shifting, peak reduction, congestion management, voltage control, balancing, ancillary services, or local flexibility procurement (Chondrogiannis et al., 2022; Wang et al., 2015; ENTSO-E, 2018; Hirst and Kirby, 1996).

2.3 Penetration metrics and hosting capacity

Distributed-generation penetration is often expressed as the ratio between installed distributed-generation capacity and a load or network-capacity reference. Penetration indicators are useful screening metrics for comparing feeders or scenarios, although they cannot by themselves determine whether a network can host additional distributed resources without violating operational limits (Gandhi et al., 2020; Qamar et al., 2023; Saxena et al., 2024). Two useful indicators are the peak-load penetration ratio and the minimum-load penetration ratio, as defined in Equations 1 and 2:

Π D G peak = ∑ i = 1 n P D G , i rated P L peak × 100 (1)

Π D G min = ∑ i = 1 n P D G , i rated P L min × 100 (2)

where P D G , i rated is the rated capacity of the i-th distributed generator, P L peak is the feeder or network peak load, and P L min is the minimum load. The second indicator is particularly relevant for photovoltaic-dominated feeders, because reverse power flow, voltage rise and local congestion commonly emerge during high-generation and low-demand periods (Gandhi et al., 2020; Qamar et al., 2023; Saxena et al., 2024).

Although penetration ratios are useful for comparing networks, they do not define a universal admissible limit. The same percentage of distributed generation can be acceptable in one feeder and problematic in another because hosting limits depend on topology, line impedance, transformer rating, voltage-control equipment, short-circuit strength, protection settings, load profile, generation simultaneity, observability and the availability of active network management (Gandhi et al., 2020; Qamar et al., 2023; Schwägerl et al., 2026). For this reason, hosting capacity is a more appropriate planning and operational concept. It is commonly interpreted as the maximum distributed-resource capacity that can be connected or activated without violating predefined network performance limits (Qamar et al., 2023; Schwägerl et al., 2026). In a compact form, hosting capacity can be expressed by Equation 3:

H C = max p , q ∑ i = 1 n P DER,i (3)

subject to the network constraints listed in Equation 4:

V min ≤ V j p , q ≤ V max , | I l p , q | ≤ I l max , S m p , q ≤ S m max , I s c , k min ≤ I s c , k p , q ≤ I s c , k max , C prot p , q = 1 . (4)

where V j is the voltage magnitude at node j, I l is the current in line l, S m is the loading of transformer or network component m, I s c , k is the short-circuit current at fault location k, and C prot represents compliance with protection-coordination requirements. The decision variables p and q represent active- and reactive-power injections or absorptions from distributed resources. This formulation highlights that distributed-resource participation is constrained not only by installed capacity but also by voltage limits, thermal limits, short-circuit margins, protection compatibility, controllability and interconnection requirements (Qamar et al., 2023; Saxena et al., 2024; Tariq et al., 2021; IEEE, 2018; Narang et al., 2021).

2.4 Voltage, thermal, and reverse-power-flow constraints

Voltage rise is one of the most common constraints in feeders with high photovoltaic or wind penetration (Gandhi et al., 2020; Qamar et al., 2023). In radial low- and medium-voltage networks, active-power injection at the end of a feeder can increase local voltage, especially when demand is low and line impedance is high (Gandhi et al., 2020; Saxena et al., 2024). This effect is location-dependent: a generator connected near the end of a weak feeder generally has greater voltage impact than the same generator connected close to the primary substation. Voltage sensitivity to active and reactive power is therefore an essential criterion for determining whether a distributed resource is suitable for local flexibility, voltage support, or market activation (Altayara et al., 2024; Qamar et al., 2023; Narang et al., 2021).

Thermal constraints arise when local injections, flexible loads, or market activations increase current through lines, cables, or transformers above rated limits (Qamar et al., 2023; Saxena et al., 2024). This can occur both during high generation, when reverse flows overload upstream components, and during high electrified demand, when heat pumps and electric-vehicle charging increase coincident load (Gandhi et al., 2020; Schwägerl et al., 2026). Reverse power flow also changes the operating conditions of voltage regulators, on-load tap changers, protection devices, and transformer interfaces (Gandhi et al., 2020; Saxena et al., 2024). Consequently, market-based activation of distributed resources must be coordinated with distribution-network constraints, particularly when the same portfolio is used for wholesale, balancing, and local services (Uzum et al., 2024; Schwägerl et al., 2026).

Advanced inverter functions, active-power curtailment, reactive-power control, coordinated storage operation, flexible demand, network reconfiguration and distributed energy resource management systems can increase hosting capacity (Altayara et al., 2024; Qamar et al., 2023; Trinh and Chung, 2024; Schwägerl et al., 2026). Dynamic operating envelopes can further support network-secure DER operation by defining time-varying export or import limits that reflect local grid conditions (Wickramasinghe et al., 2025). However, these measures introduce trade-offs between curtailment, losses, voltage quality, thermal loading, customer impact, and market revenue. A portfolio that is optimal from an energy-market perspective may therefore be suboptimal from a distribution-network perspective unless locational constraints are internalized in dispatch, procurement rules or operating envelopes (ENTSO-E and EU DSO Entity, 2025; Schwägerl et al., 2026; Wickramasinghe et al., 2025).

Distributed generation changes the magnitude, direction, and time profile of fault currents, which can affect the selectivity, sensitivity and speed of existing protection systems (Saxena et al., 2024; Tariq et al., 2021; Saber et al., 2017). Synchronous and rotating distributed generators can increase short-circuit current contributions, while inverter-based resources typically provide current-limited and control-dependent fault responses governed by interconnection and grid-code requirements (IEEE, 2018; Narang et al., 2021). These effects mean that distributed-generation penetration cannot be constrained by a universal percentage that is valid for all feeders; the admissible penetration depends on feeder topology, short-circuit strength, generator location, technology type, protection-device ratings and relay-coordination margins (Saber et al., 2017). Protection-related impacts include altered relay reach, protection blinding, sympathetic tripping, fuse-recloser miscoordination, unwanted islanding, reverse fault-current contribution, false tripping, and changes in the fault-current margin available for detecting downstream faults (Tariq et al., 2021; Saber et al., 2017).

For an existing feeder with unchanged protection devices, the admissible distributed-generation capacity may be lower than the voltage- or thermal-based hosting capacity if fault-current levels, interrupting ratings, relay coordination intervals, or anti-islanding requirements are violated (Saxena et al., 2024; Tariq et al., 2021; Saber et al., 2017). Protection-compatible hosting capacity can therefore be interpreted as the maximum distributed-generation capacity that preserves both normal-operation constraints and acceptable protection performance. This requires short-circuit and protection-coordination studies under different generation locations, technology types, operating states, inverter-control modes and fault scenarios (Tariq et al., 2021; IEEE, 2018; Narang et al., 2021; Saber et al., 2017).

Protection impacts are also relevant for market participation. When a distributed portfolio is activated for balancing, local flexibility, or ancillary services, its operating point may differ from the condition used in the original connection study (Uzum et al., 2024; Schwägerl et al., 2026). If activation changes feeder flows, voltage profiles, short-circuit levels or inverter control modes, it may also change protection margins. This creates a link between market dispatch, distribution-network security, and protection coordination. Accordingly, scalable distributed-resource participation requires technical rules that define when resources can be activated freely, when activation requires distribution-system-operator validation, and when local constraints must limit or reshape market bids through locational prequalification, flexibility-needs assessment or dynamic operating envelopes (EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025; Wickramasinghe et al., 2025).

2.5 Distribution system operator roles in active distribution networks

A grid operator, also referred to as a system operator, is responsible for ensuring the safe and dependable operation of the electrical grid. Grid operators monitor grid operation to ensure that electricity demand is continuously met while the system operates within its capacity limits (Apostolopoulou et al., 2016). To ensure that supply and demand are balanced and system security is maintained, grid operators also participate in ancillary-service markets. Transmission system operators (TSOs) and distribution system operators (DSOs) are the two categories of grid operators in Europe (Uzum et al., 2024). The distribution system operator (DSO) is a key entity in managing distribution energy markets, responsible for planning, operating, and ensuring the reliability of the distribution grid with high DER penetration (Renani et al., 2018). The DSO is in charge of delivering energy to customers in an economical, sustainable, and efficient manner. The DSO guarantees the long-term quality of electricity delivery services in the distribution network and maintains network security (Torbaghan et al., 2018). The local and regional energy distribution networks that deliver power to end customers are run, managed, and occasionally owned by DSOs. Low-voltage and medium-voltage networks make up the distribution grid. Thus, DSOs are in charge of linking renewable energy sources, facilitating flexibility, assisting with electrification, and enabling customers to participate in a more decentralized energy environment. The roles and responsibilities of the DSO are illustrated in Figure 4 (GridX, 2025; Camus Energy, 2024).

These responsibilities include tracking grid conditions, such as voltage, transformer load, congestion, and overall grid health, and rapidly deploying local assets in real time to satisfy distribution-system requirements (GridX, 2025; Valente et al., 2021; Prettico et al., 2016). They also include coordination with local resources to manage flexible loads and distributed energy resources (DERs) across a power-supply portfolio. This includes scheduling, estimating net load, and determining remuneration for resource owners and aggregators. DSOs may also leverage the value of DERs to monetize local assets for distribution-level grid services, such as deferring capital investments, managing distribution feeders, voltage maintenance, load balancing, peak-load mitigation, and backflow control, while also managing local grid conditions and enabling complex interactions between grid-connected energy resources (GridX, 2025; Camus Energy, 2024).

DER integration has also changed the roles of system operators, particularly TSOs and DSOs, because distributed generation, storage, flexible demand and aggregators increasingly affect both local distribution operation and system-level balancing (Uzum et al., 2024; Gerard et al., 2018; Birk et al., 2017). In traditional centralized power systems, electricity flow was mainly one-way: it originated in a limited number of large power plants and travelled through transmission and distribution networks to end users (Apostolopoulou et al., 2016; Prettico et al., 2016). However, the roles of grid operators are being redefined by the decarbonization and decentralization of energy systems, requiring increased cooperation between DSOs and TSOs (Uzum et al., 2024; Gerard et al., 2018). In systems with increasingly variable renewable energy sources and distributed energy resources, this cooperation becomes especially important because local distribution constraints can interact with wholesale, balancing and ancillary-service activation (Uzum et al., 2024; Birk et al., 2017; Schwägerl et al., 2026). DSOs now have more duties in the era of DER-inclusive power grids, such as managing peak loads and network congestion, coordinating local flexibility, enabling voltage support, and ensuring that DER activation remains compatible with distribution-network constraints (Renani et al., 2018; Torbaghan et al., 2018; GridX, 2025; Camus Energy, 2024; Schwägerl et al., 2026). Stakeholders must interact in innovative and coordinated ways to reduce the increased complexity of decentralized energy systems (Gerard et al., 2018; Birk et al., 2017). Additionally, the interaction between system operators and DERs, adapted from (Birk et al., 2017), is illustrated in Figure 5 (GridX, 2025).

High distributed-resource penetration increases the need for distribution-system observability and active operation (Schwägerl et al., 2026). Distribution system operators need access to network topology, load and generation forecasts, voltage and current measurements, transformer loading, resource availability, and activation schedules to assess whether DER operation remains compatible with local constraints (Prettico et al., 2016; Schwägerl et al., 2026). At low voltage, limited observability remains a major barrier because many small resources are connected behind the meter and are visible only through smart meters, aggregators, customer energy-management systems, or flexibility platforms (European Commission, 2022; EU DSO Entity and ENTSO-E, 2024). Without adequate observability, hosting-capacity estimates become conservative, flexibility procurement becomes difficult, and the risk of conflicting local and system-level activation increases (Uzum et al., 2024; EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025; Qamar et al., 2023).

Controllability is equally important. Flexible resources can support distribution-network operation only when control signals, response verification, fallback strategies, and customer constraints are clearly defined (Chondrogiannis et al., 2022; Wang et al., 2015; Schwägerl et al., 2026). Batteries, electric vehicles, and heat pumps can provide valuable flexibility, but their availability depends on user behavior, state of charge, thermal comfort limits, connection duration, and contractual arrangements (Le Ray et al., 2016; Molderink et al., 2010; Müller et al., 2017). Photovoltaic and wind inverters can provide reactive-power or active-power control, but their use must be coordinated with voltage limits, thermal limits, curtailment rules, interconnection requirements and compensation mechanisms (Altayara et al., 2024; IEEE, 2018; Narang et al., 2021).

The role of the distribution system operator is therefore evolving from passive network management toward active coordination of local resources (Uzum et al., 2024; Gerard et al., 2018; Schwägerl et al., 2026). This evolution requires advanced distribution management systems, distributed energy resource management systems, standardized data exchange, locational flexibility products, and coordination with transmission system operators (Uzum et al., 2024; EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025; European Commission, 2022; EU DSO Entity and ENTSO-E, 2024). In this context, hosting capacity is not only a planning indicator but also an operational and market-enabling concept (Qamar et al., 2023; Schwägerl et al., 2026). It determines where distributed resources can be connected, when they can be activated, which services they can provide, and how local network constraints should be reflected in market participation (EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025; Wickramasinghe et al., 2025).

2.6 Digitalization, observability and controllability in active distribution networks

Digitalization includes digitization processes as well as changes brought about by the incorporation of digital technologies into social, organizational, and economic processes. The advent of new technologies, innovation processes through digitization, and workforce adaptation and social inclusion all have an impact on the sustainability of the energy industry (Mihai et al., 2022). Since energy is essential to economic and social activities, the energy sector plays a crucial role in the transition of economies toward green models. By using renewable resources and reducing fossil-fuel use in energy production, CO₂ emissions can be lowered, contributing to environmental protection. Energy produced through such pathways is commonly referred to as green energy (Akorede et al., 2010; European Commission, 2023). Energy systems are already more secure, efficient, available, and durable thanks to digitization and energy-sector digital transformation (Varela, 2018; Trzaska et al., 2021; Borowski, 2021). Through data collection and analysis technologies, digitization offers opportunities to improve energy efficiency. To improve energy use, these data are converted into meaningful information using data-analysis technologies such as AI algorithms and are then transmitted to devices that can affect physical changes (Trzaska et al., 2021; Borowski, 2021; Singh et al., 2022). Based on the components of Industry 4.0, such as the Internet of Things (IoT), machine-to-machine (M2M) technology, and machine learning (ML), digitization supports an increasingly automated and digital energy industry. Sensors, RFID (radio-frequency identification), Wi-Fi or cellular links, and process-control systems, which are crucial for process automation and optimization, are primary components of digitally enabled monitoring and control architectures (Ahmed et al., 2025a; Singh et al., 2022). To enable this information exchange, the IoT and advanced software solutions are driving the energy sector toward the digital world (Singh et al., 2022). Grid operators are able to preserve equilibrium in an increasingly complex system by integrating signals from various market participants, forecasts, consumption patterns, and asset performance into comprehensive energy-management systems and by sharing insights with them. For example, DSOs may effectively monitor and control DERs, guaranteeing their optimal and grid-friendly behavior, by integrating grid signals into local energy-management systems. This integration supports both large-scale grid stability and local self-sufficiency optimization (GridX, 2025). A two-way energy flow with a multidirectional energy network between central grids and dispersed prosumers will replace the conventional one-way energy flow from centralized generation to end users due to the expanding availability of RESs and the rapid, ubiquitous connection of assets and actors, including peer-to-peer interactions (Chaudhuri, 2021). To monitor and regulate energy supply and demand, digital systems that integrate several energy sources will be used increasingly (Ahmed et al., 2025a). The use of AI algorithms in the energy industry makes it possible to control energy production and transmission in an ecosystem involving thousands of participants, including producers and consumers, in an effective and efficient manner (Mihai et al., 2022).

In the context of DER market participation, digitalization is not only an efficiency tool but also an enabling condition for flexibility activation. Smart meters, sensors, inverter communication interfaces, energy-management systems, distributed energy resource management systems, and flexibility platforms provide the data and control signals required to transform distributed assets into verifiable market resources (Ahmed et al., 2025a; Singh et al., 2022; European Commission, 2022; EU DSO Entity and ENTSO-E, 2024). These infrastructures support forecasting, scheduling, baseline definition, telemetry, response verification, and coordination between local and system-level services. Digitalization therefore directly affects the feasibility of DER participation in retail, local flexibility, balancing, and ancillary-service mechanisms (Chondrogiannis et al., 2022; Wang et al., 2015; Uzum et al., 2024).

At building and low-power IoT level, indoor photovoltaic energy harvesting can also support the deployment of autonomous sensors used for monitoring, occupancy detection, environmental measurements and local energy-management functions. Recent studies on indoor PV applications and maximum-power-point-controlled battery-free smart sensors show that small photovoltaic devices can harvest useful power from indoor lighting conditions, reducing battery dependence in distributed sensing architectures (Yufenyuy et al., 2024; 2026). Although these systems are not market-facing DERs by themselves, they can strengthen the sensing and data-acquisition layer required for digitalized buildings, smart renewable energy communities and verifiable demand-side flexibility.

At the same time, digitalization introduces new operational requirements. Data exchange must be reliable, interoperable, cyber-secure, and sufficiently granular for the target service (ENISA, 2024; Liu et al., 2024). Control architectures must account for communication delays, missing data, customer constraints, fallback operation, and privacy. These aspects are particularly relevant when DER portfolios are controlled through aggregators, energy communities, virtual power plants, or microgrid controllers. Therefore, the digitalization of the distribution network should be treated as part of the technical infrastructure for DER integration, together with hosting-capacity assessment, protection coordination, observability, and active network management (Qamar et al., 2023; Schwägerl et al., 2026).

Table 5 summarizes the main distribution-network constraints and enabling operational requirements associated with distributed-resource penetration, highlighting their implications for market participation.

TABLE 5. Distribution-network constraints relevant to distributed-resource penetration and market participation.

3 Electricity-market mechanisms and distributed-resource participation pathways

Electricity-market participation by distributed resources depends on the interaction between market architecture, product definition, system-operation needs, and the technical capabilities of the resource portfolio. Recent European electricity-market reform and institutional guidance emphasize the growing role of demand response, storage, consumer participation, non-fossil flexibility and flexibility-needs assessment in electricity-market design (European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; ACER, 2025a). In liberalized European electricity systems, electricity is exchanged through multiple layers, including wholesale day-ahead and intraday markets, balancing markets, ancillary-service procurement, retail contracts, local flexibility mechanisms, and community-based arrangements. These layers differ in time resolution, prequalification requirements, minimum bid size, settlement rules, baseline construction, telemetry requirements, and the role of the procuring or coordinating actor. Recent work on distributed resources, aggregation and demand response shows that controllability, response time, duration, observability, baseline definition and aggregation are recurring participation gates for small-scale flexibility resources (Adham et al., 2025; Božičević Vrhovčak and Malbašić, 2023; Ranaboldo et al., 2024). Consequently, the market value of distributed resources cannot be assessed only from installed capacity or annual energy production; it depends on the extent to which their technical and digital capabilities match the requirements of specific services and procurement mechanisms. When variable renewable producers participate directly in pool-based electricity markets, price formation and imbalance exposure become particularly relevant, as illustrated by wind-producer market-pricing studies (Morales et al., 2012).

The electrical systemś reorganization and deregulation in recent decades have altered the fundamental framework for system planning and operation. Depending on the local economic features and infrastructure requirements, various types of market architectures, pricing schemes and zonal or nodal market models are common in power systems worldwide (Wang et al., 2015; Borowski, 2020). Globally, electricity markets have been established in a number of ways. Nonetheless, there are several similarities between these implementations. The division of production, transmission, distribution, and retail activities is the first shared characteristic. While transmission is still a monopoly run by nonprofit organizations (system operators), markets encourage competition in generation and retail (Morales et al., 2014). An electricity market is a price-based mechanism for trading electricity. Organized power exchanges and market platforms are therefore central to the evolution of European electricity-market architecture (Europex, 2017). Supply and demand influence these prices. One method of distributing power to customers and rewarding producers is through markets. They serve as a substitute for methods of allocating electricity that are centrally planned. Economic conditions are never ideal in the real world. Nonetheless, there are significant advantages to moving away from centrally controlled power distribution and toward a market-based strategy (N-SIDE, 2023). The move towards a low carbon economy entails an ever-increasing role for DERs, better efficiency and electrification of transport and other sectors. End users will play a more significant role and have more chances to participate in the electricity market as DERs, electricity storage, electric vehicles (EVs), and information and communication technology (ICT) development (Crasta et al., 2020). The motivations of electricity markets generally consider three perspectives; Market Operators, aiming to increase economic efficiency, System Operators aiming to maintain the system dependability, stability and safety and the Green policies, aiming to boost the use of RESs (Morales et al., 2014).

In the European context, this general market evolution is now increasingly connected with the activation of non-fossil flexibility from demand response, storage, distributed generation, electric vehicles, and aggregated small-scale resources (European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b). This evolution is driven by the growing penetration of variable renewable generation, increasing electrification of end uses, congestion in distribution networks, and the need to reduce reliance on fossil-based balancing and reserve capacity (ACER, 2025a; ENTSO-E and EU DSO Entity, 2025). The 2024 reform of the European electricity-market design reinforces the role of demand response, storage, consumer participation, and flexibility-needs assessment, while recent regulatory and institutional work highlights the importance of removing barriers to market access for demand-side and distributed resources (European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; ACER, 2025a; ENTSO-E and EU DSO Entity, 2025). In this context, aggregators, energy communities, local flexibility platforms, and digital energy-management systems become essential interfaces between small distributed assets and market or system-operation requirements (Božičević Vrhovčak and Malbašić, 2023; Taromboli et al., 2025; EU DSO Entity, 2026; European Commission, 2022; EU DSO Entity and ENTSO-E, 2024).

The remainder of this section is organized around six participation routes. First, wholesale and balancing-market mechanisms are discussed to clarify how DER portfolios can contribute to energy trading, portfolio adjustment and real-time balancing. Second, retail markets, dynamic tariffs and aggregation are examined as the most direct route for small consumers, prosumers and behind-the-meter resources. Third, local markets, energy communities and microgrid-based arrangements are considered as coordination environments for local energy sharing, self-consumption and distributed flexibility. Fourth, ancillary and system-support services are analysed to identify the technical conditions under which DERs can provide frequency, reserve, voltage-support and restoration-related services. Fifth, the comparative role of DERs across market and procurement mechanisms is summarized to highlight differences in suitability, prerequisites and participation constraints. Sixth, the section closes by linking these mechanisms to the DSMG perspective, showing that DER participation depends on the match between resource capability, service requirements, market access and governance coordination.

3.1 Wholesale and balancing-market participation

Wholesale electricity markets include forward, day-ahead and intraday trading, while balancing markets are used by transmission system operators to maintain real-time system balance. Distributed resources may participate directly only when they meet product-size, telemetry, scheduling, forecasting, and balance-responsibility requirements. In practice, participation is usually mediated by aggregators, suppliers, balance-responsible parties, virtual power plants, or energy-service companies. Photovoltaic systems and small wind units are mainly exposed to wholesale prices through energy sales, self-consumption optimization, or aggregation, whereas batteries, flexible demand, heat pumps, and electric vehicles can also exploit temporal price differences by shifting, storing, or modulating demand (Adham et al., 2025; Božičević Vrhovčak and Malbašić, 2023).

3.1.1 Wholesale markets

Wholesale electricity markets typically include forward or long-term markets, day-ahead markets, intraday markets, and balancing or real-time markets, each operating at different time horizons and serving different risk-management or system-operation functions (Morales et al., 2014; Conejo et al., 2010). The Intraday Market (IDM) is used for trading closer to real-time operation, while the Day-ahead Market (DAM) clears electricity for the following delivery day and is central to short-term scheduling in liberalized electricity systems (Conejo et al., 2010; European Commission, 2025a). In Europe, day-ahead and intraday trading are also shaped by market-coupling, capacity-allocation and congestion-management rules, including the role of nominated electricity market operators (NEMOs) (European Commission, 2025a; 2015). Participation in the IDM and DAM can include generators, suppliers, aggregators, large consumers, and storage operators; these markets are often used for portfolio optimization, short-term adjustment and exposure management by balance-responsible parties and flexibility providers (Morales et al., 2014; Conejo et al., 2010). For long-term markets, participation can include generators, suppliers, traders, large industrial consumers, and financial players; these markets are mainly used to hedge future price risk and manage cross-border capacity exposure (Morales et al., 2014; Conejo et al., 2010). In the balancing market or real-time market, TSOs acquire balancing energy and reserves to maintain system balance and frequency control during operation (ENTSO-E, 2018). BSPs are units or portfolios providing balancing energy or capacity, including generators, demand response, storage and aggregators, whereas BRPs are entities financially responsible for imbalances between their injections and off-takes (ENTSO-E, 2018).

The main contribution of distributed portfolios in wholesale and balancing contexts is not limited to energy injection. Aggregated demand response and storage can modify net load profiles, reduce imbalance exposure, support intraday portfolio adjustment, and provide balancing energy or reserve products when prequalification conditions are satisfied (Wang et al., 2015; Božičević Vrhovčak and Malbašić, 2023; Ranaboldo et al., 2024). Nevertheless, wholesale participation remains constrained by forecast uncertainty, small asset size, transaction costs, balancing responsibility, customer availability, telemetry requirements, and the need to coordinate resource activation with distribution-network limits (Wang et al., 2015; Uzum et al., 2024; Božičević Vrhovčak and Malbašić, 2023). These constraints are particularly relevant when flexibility located in distribution grids is used for system-level services, because activation by the transmission-level market may create or worsen local congestion or voltage problems unless transmission–distribution coordination is ensured (Uzum et al., 2024; Gerard et al., 2018; Schwägerl et al., 2026).

3.2 Retail markets, dynamic tariffs, and aggregation

Retail markets provide the most direct participation route for small consumers and prosumers, especially when they participate through suppliers, dynamic contracts, aggregators or community-based arrangements (European Parliament and Council of the European Union, 2019; smartEn, 2022). Dynamic electricity contracts, time-of-use tariffs, self-consumption schemes, and supplier-based flexibility services allow distributed resources to respond to price signals without necessarily entering wholesale or balancing markets as independent market actors (Le Ray et al., 2016; European Parliament and Council of the European Union, 2019). Such arrangements can be particularly relevant for residential photovoltaic systems, behind-the-meter batteries, heat pumps, electric-vehicle charging, and flexible building loads. Their system value, however, depends on whether tariff signals are sufficiently granular and aligned with actual system conditions (Le Ray et al., 2016; Wang et al., 2015). Building energy-management systems, HVAC controllers and appliance-level thermal inertia can also contribute to demand-side flexibility. Recent reviews show that machine learning, reinforcement learning and artificial neural networks are increasingly used to improve building energy-management systems, renewable-energy utilization and adaptive control of flexible building loads (Kaya et al., 2025; Michailidis et al., 2025; 2024). Recent work on symbolic discrete controller synthesis for HVAC systems shows how energy-management objectives can be combined with thermal-comfort constraints, while broader reviews of machine-learning applications in buildings highlight the growing importance of predictive and data-driven control for grid-responsive operation (Kurucan et al., 2026; Michailidis et al., 2026). In addition, residential freezers and similar thermostatically controlled appliances may provide short-term frequency-regulation potential when their thermal inertia, user constraints and aggregation requirements are properly represented (Lewicki et al., 2026).

3.2.1 Retail markets

Directive 2019/944 mainly contains retail/consumer-facing rules covering supplier switching, dynamic and time-of-use pricing, and demand response and aggregators. In supplier switching, customers are free to select their suppliers; they can change providers in as little as 3 weeks (and in some cases as little as 24 h) without facing any unfair obstacles. In dynamic and time-of-use pricing, Member States must allow contracts that reflect wholesale prices and smart metering, enabling consumers to indirectly engage in wholesale markets. In demand response (DR) and aggregators, independent aggregators can supply DR without supplier consent (subject to compensation procedures), and DR must be able to participate in electricity markets, including wholesale and balancing markets, without discrimination (European Parliament and Council of the European Union, 2019). Participation can take the form of joining energy communities, becoming a supplier, or acting as an independent aggregator.

Aggregation extends retail participation by pooling the flexibility of many small resources into a marketable portfolio. The aggregator performs forecasting, optimization, bidding, dispatch coordination, measurement and verification, and customer remuneration; this role is central for demand response and small-scale distributed resources because individual assets are often too small, uncertain or operationally constrained to meet market-access requirements alone (Božičević Vrhovčak and Malbašić, 2023). Aggregation can also reduce transaction costs and improve portfolio reliability by exploiting diversity among loads, storage devices, electric vehicles and local renewable generation. However, recent European demand-response and aggregation literature shows that participation remains constrained by regulatory heterogeneity, incomplete metering-data access, unclear compensation mechanisms, baseline uncertainty, limited smart-meter penetration and potential conflicts between suppliers, balance-responsible parties, aggregators and system operators (ACER, 2025a; Ranaboldo et al., 2024).

3.3 Local flexibility procurement

Local flexibility procurement refers to mechanisms through which distribution system operators acquire active or reactive power modifications from distributed resources to manage congestion, voltage constraints, transformer loading, reverse power flow and reinforcement deferral (Scrocca et al., 2026; EU DSO Entity, 2026). Unlike wholesale or balancing products, local flexibility has an explicitly locational value: the same resource may be highly valuable in one feeder and almost irrelevant in another. Reactive-power management and inverter-based voltage support further show that the value of distributed resources depends on both electrical location and controllable active/reactive-power capability (Altayara et al., 2024). Therefore, local flexibility requires distribution-network observability, locational qualification, product standardization, baseline definition and coordination between market activation and grid-security constraints.

3.3.1 Local markets

Local markets, or flexibility markets, aim to enable DSOs to procure local flexibility (variation in generation/consumption) from DERs in order to control congestion, voltage, and avoid grid reinforcement (Gestore Mercati Energetici (GME), 2023). DERs (PV, wind, CHP, etc.), flexible loads (EV charging, HVAC, industrial operations), energy storage systems, aggregators, and energy communities can participate. DSOs obtaining local auxiliary services from DERs using a specialized market platform are specifically described by Italian local flexibility market regulations and pilot frameworks (European Parliament and Council of the European Union, 2019; ARERA, 2023). Practically, local market participation typically refers to a community, aggregator, or flexibility service provider submitting a bid for local flexibility products to the DSO and, increasingly, providing services to the TSO using the same assets. Communities are classified as Citizen Energy Communities (CECs) under Directive 2019/944 (European Parliament and Council of the European Union, 2019) and Renewable Energy Communities (RECs) under Directive 2018/2001 (Parliament and of the European Union, 2018), offering economic, environmental, and social benefits and involving local stakeholders.

European local flexibility markets are still heterogeneous in design and maturity, and the literature shows differences in market concepts, clearing models, platform architecture and operational coordination (Jin et al., 2020; Scrocca et al., 2026; EU DSO Entity, 2026). Existing approaches differ in procurement timing, product standardization, platform architecture, clearing method, activation rules, settlement procedures, and the extent to which flexibility is coordinated with transmission-level balancing and congestion-management needs (Jin et al., 2020; Forouli et al., 2022; Scrocca et al., 2026; EU DSO Entity, 2026). Distributed photovoltaic inverters, batteries, electric vehicles, controllable heat pumps, flexible buildings, and industrial demand response can contribute to local services when they are observable, controllable, and connected at electrically relevant nodes. Batteries and controllable loads are generally more suitable for active-power congestion management and peak reduction, while inverter-based resources may also contribute to voltage and reactive-power support if grid codes, control interfaces, and compensation schemes are defined (Altayara et al., 2024). For stationary batteries and building-integrated storage, reliable state-of-charge estimation and supervisory control are essential prerequisites for dispatchable flexibility, aggregation and safe renewable integration (Kurucan et al., 2025). At neighbourhood scale, distributed storage can also be used to reduce winter peak demand and reshape local load profiles, reinforcing the role of storage not only as a self-consumption device but also as a grid-support resource (Coban et al., 2026).

3.4 Energy communities, local energy markets, and microgrid-based coordination

Energy communities, local energy markets, and microgrids provide coordination environments for distributed resources rather than a separate physical resource class (Dudjak et al., 2021; Basak et al., 2012; Koirala et al., 2016b). Their market relevance arises from their capacity to aggregate heterogeneous assets, align local generation and demand, increase self-consumption, improve resilience, and create a governance structure for shared investment, operation, and benefit allocation (Eid et al., 2016; Koirala et al., 2016b; Ahmed et al., 2024a). In the European context, citizen energy communities and renewable energy communities are embedded in the regulatory framework established by Directive 2019/944 and Directive 2018/2001, which gives active consumers a formal role in producing, consuming, sharing, storing, and selling energy (European Parliament and Council of the European Union, 2019; Parliament and of the European Union, 2018). However, implementation remains heterogeneous across Member States and depends on national transposition, market-access rules, grid-tariff design and aggregation arrangements (Taromboli et al., 2025; European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b). The technological configuration of renewable energy communities should therefore be interpreted as a combination of generation, storage, demand response, energy management, energy sharing and EV-related functions, rather than as a single renewable-generation asset (Ahmed et al., 2024a; 2025b).

From a market-participation perspective, community and microgrid arrangements can operate at different levels. At the local level, they can optimize self-consumption, peer-to-peer exchange, collective storage, and internal flexibility (Dudjak et al., 2021; Taromboli et al., 2025). At the distribution-network level, they may provide congestion relief, voltage support, peak reduction, and flexibility services to the distribution system operator (Chondrogiannis et al., 2022; EU DSO Entity, 2026). At the system level, they may participate through an aggregator or virtual power plant in wholesale, balancing, or reserve markets (Wang et al., 2015; Božičević Vrhovčak and Malbašić, 2023). The feasibility of these pathways depends on metering architecture, contractual design, data governance, internal control strategy, distribution-network constraints, and the ability to allocate costs and benefits transparently among participants (Muttaqee et al., 2025; Shahzad et al., 2023).

3.5 Ancillary and system-support services

Ancillary and system-support services include frequency containment, frequency restoration, replacement reserves, voltage control, reactive-power support, congestion management, black-start capability, and system restoration services (Hirst and Kirby, 1996). Transmission system operators traditionally procure several of these services from large conventional generators through reserve and balancing mechanisms (ENTSO-E, 2018). Distributed resources can increasingly contribute when product definitions, prequalification procedures, telemetry, response-time requirements, and aggregation rules allow their participation. Batteries, electric vehicles and aggregated demand response are suitable for active-power flexibility at different response times, while photovoltaic and wind inverters can contribute to reactive-power and voltage-related services when their control capabilities are enabled and appropriately coordinated (Wang et al., 2015; Comi and Elnour, 2024; Altayara et al., 2024).

3.5.1 Ancillary services

In practice, ancillary services are system-support services that TSOs, and in some cases DSOs for local services, procure to maintain supply quality, frequency stability, voltage control and operational security (ENTSO-E, 2018; Hirst and Kirby, 1996). Large imbalances between load and generation can endanger secure system operation and require balancing, reserve activation or emergency control actions. In the event of a system failure, emergency schemes may disconnect selected generation or loads to prevent wider collapse, while black-start and restoration resources can support grid re-energization after a blackout (Hirst and Kirby, 1996). For these reasons, the FERC (United States Federal Energy Regulatory Commission) defines generic ancillary services into six groups, which are shown in Figure 6 (Manabe, 2016).

European ancillary-service participation by distributed resources depends on the product definitions and prequalification rules adopted by each system operator. DER portfolios can contribute only when their response time, duration, controllability, telemetry, aggregation structure, and verification method are aligned with the service requirement (ENTSO-E, 2018; Wang et al., 2015). This is especially relevant for batteries, vehicle-to-grid fleets, aggregated demand response, and inverter-based resources, which may provide fast active-power response or voltage/reactive-power support under appropriate technical and regulatory conditions (Comi and Elnour, 2024; Altayara et al., 2024).

The operational challenge is that ancillary-service activation may have both system-wide and local impacts. A resource activated for balancing or reserve provision may change feeder flows, voltage profiles, transformer loading, or reverse power-flow conditions. Therefore, distributed-resource participation in system-support services requires coordination between transmission and distribution system operators, especially when services are stacked across local and system-level markets (Uzum et al., 2024; EU DSO Entity, 2026). Flexibility-needs assessment, local network prequalification, grid-safe bid forwarding, standardized data exchange, and transparent settlement procedures are central prerequisites for scalable participation (ENTSO-E and EU DSO Entity, 2025).

3.6 Comparative role of DERs across market and procurement mechanisms

Discussing DERs, both renewable and non-renewable, it is important to highlight that their role differs across wholesale, retail, local-flexibility and ancillary-service contexts. A detailed comparison is presented in Table 6, covering suitability, applications, advantages, disadvantages, and representative distributed-resource portfolios across market types (Wang et al., 2015; ENTSO-E, 2018; European Parliament and Council of the European Union, 2019; smartEn, 2022).

TABLE 6. Comparison of markets and ancillary services for DERs.

Table 6 separates market and procurement mechanisms, coordinating actors, services, suitable distributed-resource portfolios, technical and regulatory prerequisites, and participation constraints. This distinction is useful because DER suitability depends not only on the market category, but also on telemetry, aggregation, baseline construction, locational qualification, prequalification, and TSO–DSO coordination (Chondrogiannis et al., 2022; Uzum et al., 2024; EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025).

Table 6 shows that the applicability and value of DERs vary depending on operational needs and technological capabilities across market contexts (Wang et al., 2015). In wholesale markets, DERs may access higher-value opportunities, but aggregation and stringent performance requirements are often necessary; therefore, participation is generally easier through aggregated solar, wind, flexible-load, or hybrid PV-storage portfolios (Wang et al., 2015; Božičević Vrhovčak and Malbašić, 2023). Although revenue potential is often more limited, rooftop solar, small wind and behind-the-meter batteries primarily benefit from retail markets through easier entry, self-consumption and direct bill savings (European Parliament and Council of the European Union, 2019). Local energy markets and local-flexibility mechanisms are particularly relevant for rooftop PV, community solar, distributed batteries and flexible loads because they can value local balancing, peer-to-peer exchange, congestion management and DSO flexibility services (Dudjak et al., 2021; Chondrogiannis et al., 2022; EU DSO Entity, 2026). Ancillary services are well suited to fast-responding technologies such as battery storage, V2G fleets and inverter-based resources when they satisfy telemetry, prequalification and response requirements (ENTSO-E, 2018; Comi and Elnour, 2024; Altayara et al., 2024).

The comparison above indicates the broad suitability of different market mechanisms, but it does not explicitly identify the participation gates that determine whether a DER portfolio can actually provide a given service. For this reason, Table 7 reformulates the comparison from a participation-pathway perspective. The table links each market or procurement mechanism to the main coordinating actor, typical services, suitable resource portfolios, technical and regulatory prerequisites, and participation constraints, reflecting the importance of prequalification, metering, baseline definition, aggregation and TSO–DSO coordination (Chondrogiannis et al., 2022; Uzum et al., 2024; ENTSO-E, 2018; ENTSO-E and EU DSO Entity, 2025). This makes the comparison directly usable within the DSMG framework.

TABLE 7. European electricity-market and procurement mechanisms for distributed-resource participation.

Table 7 clarifies that DER participation is not determined only by whether a market is wholesale, retail, local, or ancillary. It depends on the match between resource capabilities and product requirements (Chondrogiannis et al., 2022; Wang et al., 2015). For example, PV-only resources may be effective in energy production and self-consumption, but their flexibility value is limited without storage, curtailment, inverter control, or aggregation (Gandhi et al., 2020; Altayara et al., 2024). Conversely, batteries, EV fleets, flexible loads, and coordinated portfolios can provide higher-value services when they satisfy telemetry, response-time, baseline, and prequalification requirements (Comi and Elnour, 2024; Božičević Vrhovčak and Malbašić, 2023; ENTSO-E, 2018). Local flexibility and ancillary-service participation therefore require a stronger link between market design and distribution-network operation than traditional energy-market participation (Uzum et al., 2024; EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025).

4 Applications

DER applications should be interpreted not only as sectoral deployments of small-scale generation, storage and controllable demand, but also as practical contexts in which distributed resources are converted into energy value, flexibility, resilience and local system services. Since the 1990s, DER deployment has expanded considerably as technology costs have decreased and distributed generation, storage, electric vehicles, flexible demand and digital control have become more widely available across end-use sectors (Merino et al., 2021). This expansion is changing the role of distribution networks because DERs are no longer passive behind-the-meter assets; when suitably aggregated and controlled, they can contribute to services that were historically provided mainly by large centralized power plants, including portfolio balancing, demand response, reserve provision and local network support (Wang et al., 2015; Merino et al., 2021; Baghaee et al., 2016).

In the European context, the application of DERs is also shaped by the regulatory recognition of active consumers, demand response, aggregation, citizen energy communities and renewable energy communities. These frameworks connect residential prosumers, commercial and industrial users, energy communities and local flexibility providers with broader market and system-operation objectives (European Parliament and Council of the European Union, 2019; Parliament and of the European Union, 2018; Taromboli et al., 2025). Therefore, the following subsections do not treat residential, commercial, industrial, agricultural, rural, microgrid, community and critical-infrastructure applications as isolated examples. Instead, they show how different application contexts determine the available resource portfolios, ownership structures, controllability levels, resilience needs, aggregation requirements and possible participation pathways in retail, local-flexibility, balancing and ancillary-service mechanisms (Chondrogiannis et al., 2022; Wang et al., 2015; EU DSO Entity, 2026).

4.1 Residential

In the residential sector, DERs are transformative because they allow households to produce, store, and control their own electricity. The most popular residential DER technology is rooftop solar PV systems, which can significantly lower energy costs while boosting energy independence for households (Bragolusi and D’Alpaos, 2021). PV generation provides benefits for the environment and economy, which can be factored into market prices. As a result, there is increasing interest in determining the value that PV systems provide to the market pricing of solar homes, that is, residences that are outfitted with PV generation plants (Bagalini et al., 2019). Solar PV systems are being deployed at increasing rates in residential buildings, with many advantages and different configurations (Axaopoulos and Fylladitakis, 2013; Cucchiella et al., 2018). Different types of loads in residential settings include heating and cooling systems, other loads (fans, refrigerators, and washing machines), and EV charging systems. All these loads could be supplied from RESs like PV systems. Moreover, another benefit can be increased energy independence. Aside from that, energy storage systems (ESS) can be a strategy to increase this independence, as the economic feasibility of PV systems is generally associated with the share of self-consumption in a developed market (Prajapati and Fernandez, 2019). Residential DERs are therefore a key component of future decentralized energy models because they enable households to adopt self-consumption strategies, participate in demand response through suitable control or aggregation schemes, and contribute to local flexibility when properly coordinated (Le Ray et al., 2016; Molderink et al., 2010; Wang et al., 2015).

4.2 Commercial and industrial

DERs promote cost savings, dependability, and operational efficiency in the commercial and industrial sectors. For the commercial sector, such as shopping malls, hotels, warehouses, banks, theatres, and cinemas, appliances and loads usually include lighting systems, heating and cooling systems, office loads, elevators and escalators, and HVAC systems. PV for these types of loads can be a pivotal solution, with the benefits of decreased operating expenses, savings due to self-consumption, improved corporate sustainability, and increased property value (Park and Lappas, 2017; Hwang et al., 2012). The installation and mounting structure for these plants can include rooftop systems, building-integrated PV (BIPV), façade or vertically oriented solutions, and parking-area PV structures (Prajapati and Fernandez, 2019; Hwang et al., 2012; Minelli et al., 2026). Recent building-envelope studies further show that photovoltaic façades, solar collectors integrated into the envelope and photovoltaic smart-window technologies can expand the design space for building-applied and building-integrated renewable generation, particularly in Mediterranean or urban building contexts (Shi and Lin, 2026; Kaya and Beyhan, 2021; 2026). The industrial sector is one of the main parts of the economy that requires energy for its appliances and loads (Mekhilef et al., 2011). Industrial loads are often heavy and high capacity, such as heavy machinery, high-pressure pumps and motors, lighting systems, HVAC systems, and production lines, and their controllable operation can provide a relevant flexibility opportunity in smart-grid contexts (Gholian et al., 2016; Mekhilef et al., 2011). RESs and PV for industry can be a pivotal solution, with the benefits of decreased electricity costs, savings due to self-consumption, improved sustainability, and enhanced energy security (Hoffmann, 2006; Kumar et al., 2022). Overall, DERs can improve sustainability performance, energy flexibility and resilience in commercial and industrial facilities when PV, storage and controllable loads are integrated with suitable energy-management or smart-grid control strategies (Park and Lappas, 2017; Hwang et al., 2012; Gholian et al., 2016; Mekhilef et al., 2011).

4.3 Agricultural

By lowering energy costs and increasing productivity, DERs provide agricultural enterprises with distinct value, particularly in rural locations with inadequate grid infrastructure. Agrivoltaic systems are particularly relevant in this context because they combine agricultural land use with photovoltaic generation, creating potential synergies between food production, local renewable electricity and land-use efficiency (Maity et al., 2025). Diesel pumps are replaced by solar-powered irrigation systems, which reduce operating costs and their negative effects on the environment. Solar PV technologies are very important in the contemporary agricultural systems because they are economical, independent and sustainable to various applications, in addition to providing higher production and efficiency (Ahmed et al., 2025c; Gorjian et al., 2020a). These systems have various characteristics, including reliability, autonomy, durability, scalability, and cost-effectiveness. Different loads for agricultural systems can be supplied by solar PV, including irrigation (pumps, sprinkler systems, and drip irrigation), heating and cooling systems (fans for cooling and heating plants), lighting (farm buildings, fields, and animal shelters), electric fencing, animal husbandry, and crop drying and processing applications (Devabhaktuni et al., 2013; Gorjian et al., 2020b; Ahmad et al., 2022). Beyond direct PV supply, agricultural DER portfolios may include storage, hybrid renewable systems and locally available bioenergy resources, allowing farms, greenhouses and livestock facilities to reduce dependence on costly or unreliable grid connections. These solutions can support mechanization, improve energy security and contribute to more sustainable agricultural operation when they are adapted to local resource availability and load profiles (Kumar et al., 2022; Ahmed et al., 2025c; Gorjian et al., 2020a; Ahmad et al., 2022).

4.4 Remote and rural

According to recent SDG 7 tracking, hundreds of millions of people still lack access to electricity, with the gap concentrated mainly in rural and remote areas. In 2022, about 685 million people were without electricity access, while IEA estimates indicate that the number remained below 750 million in 2023 (International Energy Agency et al., 2024). The majority of these individuals reside in rural and isolated locations, where the absence of power is seriously harming the environment, economic growth, and quality of life (Das et al., 2020). Most of the energy is from centralized fossil-fuel-based power plants, and it is challenging to provide energy supply to all end users in remote and rural areas (Balakrishnan, 2006). DERs are essential for increasing access to electricity in distant, off-grid, and underprivileged areas (Woldeyohannes et al., 2016). Where grid extension is economically or geographically impractical, mini-grids powered by solar PV, micro-hydro, or hybrid renewable systems offer dependable electricity. For remote homes, solar home systems provide inexpensive electricity for appliances, basic lighting, and phone charging. By reducing reliance on diesel generators and kerosene lamps, these systems improve household expenses, safety, and health. By facilitating modern healthcare, education, communication, and microenterprises, DER-powered rural electrification can support socioeconomic development in remote and vulnerable communities (Ahmad et al., 2022; Balakrishnan, 2006; Woldeyohannes et al., 2016). DER-based mini-grids and optimized off-grid hybrid renewable systems are recognized as important routes for expanding decentralized electricity access where grid extension is slow, costly or geographically difficult (Ahmad et al., 2022; Woldeyohannes et al., 2016; Yan et al., 2017; Coban, 2024).

4.5 Microgrids

Microgrids are local energy systems that can operate independently or in parallel with the main grid, often utilizing DERs (Yan et al., 2017; Mathew et al., 2022). RES technologies are the cornerstone of microgrids due to several reasons, including decentralized local power generation, reduced reliance on centralized systems, environmental and economic benefits, and resilience through improved MG independence and reliability (García Vera et al., 2019; Adefarati and Bansal, 2019; Aziz et al., 2020). RESs such as PV are widely used in various MG applications, including residential MGs for homes and small businesses (loads: lighting, appliances, heating, cooling, and electronics), commercial MGs to supply power to commercial buildings and industrial facilities (loads: lighting, HVAC systems, office equipment, retail operations, and industrial processes), remote and island communities to provide electricity to areas without grid access, and military and disaster relief applications providing power in remote or disaster-stricken areas (Narayanan et al., 2020; Akinyele and Rayudu, 2016; Gutiérrez-Oliva et al., 2022). Load categories can include industrial loads (machinery, production processes, and large electrical equipment), agricultural loads (pumping, irrigation, processing, and storage), and public infrastructure loads (streetlights, traffic signals, water pumping, and wastewater treatment) (Tarife et al., 2022; Simoes et al., 2021). Microgrid operation also requires uncertainty-aware modelling of correlated wind/PV resources and coordinated control strategies for hybrid AC/DC architectures (Baghaee et al., 2017a; b). Data-driven and machine-learning approaches have also been proposed to improve the modelling of microgrid distributed energy resources, particularly when renewable generation and flexible loads must be represented under uncertain operating conditions (Carpintero Rentería, 2021).

4.6 Community energy projects

Community energy projects are initiatives that allow communities to create and manage their own DERs, and to sell and share energy within their jurisdiction (Bartolini et al., 2020; Syed et al., 2020). Energy communities have made substantial progress in Europe and are ready to play a key role in establishing a strong decentralized and adaptive Energy Union (EU) in which individuals have greater influence. With its inclusion in the Clean Energy Package and, notably, RED II (Directive 2018/2001), the concept of renewable energy communities (RECs) and their establishment was introduced, focusing on the use of RESs with the primary purpose of providing social, economic, and environmental benefits to members (Parliament and of the European Union, 2018; Ahmed et al., 2024b). In the transition toward sustainable development, these communities play a critical role in supporting individuals worldwide. RESs provide numerous choices to promote active involvement of the community members which are decision-making processes, investment opportunities, ownership models, local energy exchange platforms, and economic incentives (Koirala et al., 2016b; Ahmed et al., 2024b; Walker, 2008; Walker and Devine-Wright, 2008). The individual households can become local communities, which are in prime position to map the local energy requirements and to gear people to common goals, such as self-sufficiency (Viti et al., 2020; Walker, 2008), resilience, autonomy (Walker et al., 2010; Rae and Bradley, 2012) and sustainability (Walker and Devine-Wright, 2008). Furthermore, their functions change to that of an average consumer to prosumers who participate in local energy production and distribution, demand response strategies and energy saving mechanisms (Okundamiya et al., 2014).

4.7 Critical infrastructure

DERs can enhance the resilience and reliability of critical infrastructure, including hospitals, emergency rooms, data centers, airports, telecommunication stations, and military installations, when they are integrated into appropriately designed hybrid renewable, storage and backup-power architectures (Jahangir et al., 2021; Fraczek et al., 2022). For PV-based critical-infrastructure systems, equipment standards, installation requirements, licensing and certification rules are also essential to ensure safe and reliable deployment (Anderson et al., 2011). DER-enabled microgrids comprising solar PV, energy storage, and backup renewable generation are available to supply power in the event of main-grid failure, natural disasters, or cyber incidents. This will decrease the use of diesel backups and will serve to ensure that the life-saving equipment in hospitals runs without interruption. Microgrids that use DERs are employed in the military environment to enhance energy security and to reduce vulnerability. DERs play a significant role in enhancing the resilience of communities and the country as a whole as it helps in establishing emergency shelters and centers of disaster response. This is not only beneficial to the continuity of services but also to the mitigation of the effects of climate change. Diesel engine generators can also be substituted by DER-based MGs in remote locations, accelerating decarbonization in the long-term and increasing energy sustainability (Cook et al., 2020). Accordingly, DER-enabled microgrids and emergency-energy systems can contribute to neighbourhood and national resilience by supporting emergency shelters, disaster-response centres and continuity of critical services (Rehak et al., 2022; Cook et al., 2020).

Taken together, these applications show that DER value depends strongly on context. In residential buildings, the main drivers are self-consumption, bill savings, demand response and household-level flexibility. In commercial and industrial facilities, DERs are more closely connected with operational continuity, peak-load management, energy-cost reduction and controllable-load flexibility. In agriculture and rural electrification, distributed renewables and mini-grids can support energy access, productive uses of electricity and reduced dependence on diesel or weak grid infrastructure. Microgrids and energy communities add a further coordination function by combining generation, storage, demand response, internal energy sharing, collective governance and potential interaction with external markets. Critical-infrastructure applications emphasize resilience, service continuity and emergency operation (Yan et al., 2017; Mathew et al., 2022; Rehak et al., 2022).

From a European market-participation perspective, these differences are important because the same physical technology can have very different value depending on ownership, location, aggregation, metering, controllability and regulatory access. A rooftop PV system may primarily support self-consumption unless it is combined with storage, inverter control or aggregation, while batteries, EV fleets and flexible loads can provide higher-value flexibility only when telemetry, response-time, baseline and prequalification requirements are satisfied (Wang et al., 2015; Comi and Elnour, 2024; Altayara et al., 2024). Similarly, a community or microgrid becomes market-relevant only when internal governance, metering, data exchange and DSO coordination are sufficiently developed (European Parliament and Council of the European Union, 2019; Parliament and of the European Union, 2018; EU DSO Entity, 2026). Overall, this section provides the application-side evidence for the DSMG framework developed in the next section: DER participation is not determined by technology type alone, but by the match between resource capability, sectoral context, market mechanism and governance arrangement (Uzum et al., 2024; ENTSO-E and EU DSO Entity, 2025).

5 DSMG synthesis: analytical framework, taxonomies, and capability-to-market mapping

Sections 2–4 reviewed DER participation in distribution electricity markets from three complementary angles; the distribution-network reality (constraints, locational value, observability/controllability needs), the market reality (layers, products, eligibility and verification), and the deployment reality (DERs appearing as portfolios with user and operational constraints). However, these strands are often treated in isolation in the literature, network studies emphasize hosting capacity, congestion and voltage sensitivity (Cossent et al., 2009; Horowitz et al., 2018a; EUR-Lex, 2025), market studies emphasize product definitions, qualification and settlement rules (Wang et al., 2015; Morales et al., 2014; Conejo et al., 2010; ENTSO-E, 2018), and application studies report outcomes that are difficult to compare across jurisdictions and portfolio types (Merino et al., 2021; Baghaee et al., 2016; Ahmed et al., 2024b; Yan et al., 2017; Mathew et al., 2022). To translate the review into actionable, comparable guidance, this section consolidates the evidence into a single DER–Service–Market–Governance (DSMG) synthesis.

The DSMG perspective reflects how flexibility is actually created and valued at distribution level in Europe: what a DER can deliver is constrained by network physics and locational relevance (Uzum et al., 2024; Gerard et al., 2018); what it can be paid for depends on the market layer and product design (timing, minimum sizes, baselines, penal-ties, telemetry) (Wang et al., 2015; ENTSO-E, 2018; European Parliament and Council of the European Union, 2019; smartEn, 2022); and what is feasible in practice depends on portfolio composition, aggregation, controllability interfaces, and user-driven availability (Baghaee et al., 2016; Mathew et al., 2022; García Vera et al., 2019). Meaningful interpretation therefore requires an explicit mapping from resource capability to service family, market or procurement pathway, and governance actor.

The DSMG synthesis is structured around three analytical objects. The first is a distributed-resource taxonomy that groups resource portfolios according to capability and controllability attributes relevant to distribution-level operation. The second is a market/service taxonomy that separates market or procurement pathway, service family, product requirements, and procuring actor. The third is a capability-to-market mapping matrix that combines the resource and market taxonomies to identify feasible participation pathways, technical prerequisites, governance conditions, and implementation barriers. Together, these objects provide the basis for the participation-feasibility index introduced in the following subsection (Chondrogiannis et al., 2022; Wang et al., 2015; Uzum et al., 2024).

These objects are not a substitute for country-specific rulebooks; rather, they provide an evidence-informed synthesis of typical feasibility and comparability across European contexts, where differences in DSO/TSO roles and market design often explain diverging results in the literature (Uzum et al., 2024; Gerard et al., 2018; Chondrogiannis et al., 2022).

5.1 Synthesis derivation method

To ensure that the DSMG synthesis is transparent and reproducible, the taxonomies and mapping matrices in this section are constructed through the following four-step procedure, which translates the evidence from Sections 3–4 into an explicit capability-to-market representation.

Step 1: Portfolio abstraction from applications. The applications reviewed in Section 4 show that DERs rarely act alone: they appear as portfolios such as PV + Storage, EV fleets with smart charging/V2G, flexible loads under aggregation, microgrids, and energy communities (Merino et al., 2021; Baghaee et al., 2016; Ahmed et al., 2024b; Yan et al., 2017; Mathew et al., 2022). These recurring portfolios provide the empirical “units” for synthesis, consistent with microgrid and DER integration perspectives (Basak et al., 2012; Mathew et al., 2022).

Step 2: Capability and controllability classification. From these portfolios capability dimensions relevant to service provision—dispatchability/controllability, response time, duration/energy constraints, and (crucially at distribution level) locational relevance—are extracted to form the DER taxonomy in Table 2. This aligns with the distribution-level operational focus emphasized in DER integration and PV distribution impact work (Horowitz et al., 2018a; EUR-Lex, 2025; El-Khattam and Salama, 2004).

Step 3: Market/service normalization. Section 3 covered wholesale and forward timeframes (Conejo et al., 2010), balancing and reserve procurement (ENTSO-E, 2018), retail rules and demand-response enablers under EU regulation (European Parliament and Council of the European Union, 2019), and emerging local flexibility procurement (Chondrogiannis et al., 2022; smartEn, 2022). These are normalized into a market/service taxonomy (Table 3) that disentangles market or procurement pathway, product family, and procuring actor. This separation is essential because participation is often gated more by verification and governance rules than by raw technical potential (Chondrogiannis et al., 2022; Wang et al., 2015; ENTSO-E, 2018).

Step 4: Integrated mapping. Finally, Table 4 is built by matching:

• DER capability/controllability (Table 2),
• Product requirements and time horizons (Table 3),
• Measurement and verification feasibility (metering, telemetry, baseline logic), and
• Aggregation/locational constraints (minimum bid sizes; node/feeder dependence).

This directly reflects the review strands on TSO–DSO coordination and distribution-level constraints (Uzum et al., 2024; Gerard et al., 2018) and the market eligibility logic in real-time/balancing contexts (Wang et al., 2015; ENTSO-E, 2018).

Figure 7 summarizes the implementation workflow of the DSMG framework. The workflow starts from the evidence reviewed in the distribution-network, market/procurement and application sections, translates this evidence into DER capability, market/service/governance and service-requirement taxonomies, and then constructs the capability-to-market mapping. The same structure supports the rule-based suitability scores, the participation-feasibility index, the illustrative European portfolio comparison, the bottleneck interpretation and the roadmap-oriented recommendations.

5.2 Synthesis interpretation

The DSMG mapping is intended to support consistent interpretation of the literature by translating heterogeneous evidence into a structured capability-to-market perspective. In practical terms, it clarifies which DER portfolios are technically credible for specific services, where feasibility is most often constrained by telemetry, baseline definitions, minimum bid sizes or aggregation requirements, and whether the service value is primarily local or system-wide (Chondrogiannis et al., 2022; Wang et al., 2015). This distinction is important because DSO-oriented services usually address feeder or node constraints, whereas TSO-oriented services are mainly designed for system balancing and security (Uzum et al., 2024; Gerard et al., 2018).

Accordingly, Table 4 enables three complementary readings. First, it highlights capability-to-service alignment, distinguishing services that require fast, dispatchable response from those compatible with slower or inverter-limited resources. Second, it makes explicit the recurrent participation gates that frequently limit deployment-to-market translation, including telemetry readiness, controllability interfaces, baseline construction, verification rules and aggregation thresholds (Wang et al., 2015; ENTSO-E, 2018). Third, it exposes governance-sensitive intersections where differences in DSO versus TSO procurement objectives, locational qualification and product design can explain why apparently similar DER technologies yield divergent outcomes across jurisdictions and pilots (Chondrogiannis et al., 2022; Uzum et al., 2024).

5.3 DSMG taxonomies

5.3.1 DER taxonomy (capability and controllability classes)

Table 2 captures the “capability side” of DSMG: it classifies renewable-based DERs and typical DER portfolios by controllability and dispatchability, response-time class, metering/telemetry requirements, aggregation needs, and locational constraints—attributes repeatedly highlighted as decisive for distribution-level service provision and comparability (Uzum et al., 2024; Horowitz et al., 2018a; EUR-Lex, 2025; El-Khattam and Salama, 2004). Importantly, the taxonomy is portfolio-oriented (consistent with Section 4): microgrids and energy communities are represented as portfolio actors rather than single devices, reflecting observed practice (Basak et al., 2012; Mathew et al., 2022; Bartolini et al., 2020; Syed et al., 2020).

The capability dimensions in Table 2 are not descriptive only; they directly determine whether a DER class can credibly participate in specific products and be compared across studies. First, controllability and response time indicate whether an asset (or portfolio) can follow activation signals within the time windows required by reserves and balancing energy, where the ability to track dispatch instructions and sustain performance is decisive for eligibility and value creation (ENTSO-E, 2018; Wang et al., 2015). Second, metering/telemetry and baseline feasibility determine whether delivered flexibility can be measured, verified, and settled—an issue that becomes critical for demand response and aggregated flexibility, where performance is often assessed against counterfactual baselines and where insufficient measurement granularity or missing telemetry can invalidate participation or compromise comparability across cases (Wang et al., 2015; European Parliament and Council of the European Union, 2019; smartEn, 2022). Third, the locational constraint explicitly distinguishes services that are meaningful only at node/feeder scale (e.g., congestion relief and voltage support in distribution grids) from services that are valued system-wide (e.g., balancing and frequency-related services). This distinction matters because distribution-level services are intrinsically tied to local network states and DSO operational needs, whereas TSO products are typically designed around system-wide balancing objectives (Uzum et al., 2024; Gerard et al., 2018; Chondrogiannis et al., 2022). Taken together, these dimensions form the direct inputs used to populate the prerequisite codes and suitability logic in the integrated DSMG mapping (Table 4), ensuring that the synthesis follows a clear “capability to service to market layer to governance” reasoning.

5.3.2 Market/service taxonomy: venue, product, and procuring actor

Section 3 showed that “participation in electricity markets” is not a single concept but a set of distinct venues with different rules. Table 3 formalizes this by separating three orthogonal dimensions:

• Market or procurement venue (wholesale/forward, balancing/ancillary, retail/community, local flexibility procurement),
• Service/product family (energy, reserves/balancing energy, congestion management, voltage/reactive support, demand response/energy shifting), and.
• Procuring actor and governance (TSO, DSO, supplier/retailer, market operator/platform).

This structure is consistent with real-time market participation logic for DER/DR (Wang et al., 2015), balancing market procurement and verification requirements (ENTSO-E, 2018), EU retail/consumer and aggregation rules (European Parliament and Council of the European Union, 2019; smartEn, 2022), energy community definitions (European Parliament and Council of the European Union, 2019; Parliament and of the European Union, 2018), and local flexibility market development in Europe (Chondrogiannis et al., 2022; European Parliament and Council of the European Union, 2019). The significance is practical: it explains why the same physical flexibility can be monetized in one layer but excluded or non-comparable in another due to baseline, telemetry, prequalification, or minimum-size constraints (Wang et al., 2015; ENTSO-E, 2018; Chondrogiannis et al., 2022).

Table 3 clarifies that “market participation” is not a single pathway but a set of procurement environments with distinct operational and verification logics, which DSMG treats as separate layers to avoid mixing incompatible evidence. Wholesale participation is primarily schedule- and portfolio-oriented and, in practice, is often mediated through BRPs or aggregators; as a result, feasibility depends strongly on settlement grade metering, forecasting performance, and the ability to manage portfolio imbalances under market timelines (Conejo et al., 2010; ENTSO-E, 2018; European Commission, 2015). Balancing and ancillary services, by contrast, are structured around prequalification and performance-based delivery: response time, availability obligations, and high-resolution telemetry are central, and these requirements explain why fast and controllable portfolios (often aggregated) are typically favored in such products (ENTSO-E, 2018; Wang et al., 2015). Retail/community schemes are consumer-facing and enabled by EU directives and metering frameworks; they often represent the entry point for smaller actors, but when demand response is involved, verification commonly relies on program-specific baseline definitions and measurement rules, which can materially affect comparability across studies and jurisdictions (European Parliament and Council of the European Union, 2019; smartEn, 2022; Parliament and of the European Union, 2018). Finally, local flexibility procurement is explicitly locational and commonly platform-based, reflecting DSO objectives related to congestion management and voltage support; participation therefore tends to hinge on aggregation (to meet minimum volumes) and on local measurement/qualification procedures that confirm deliverability within the relevant network area (Chondrogiannis et al., 2022; European Parliament and Council of the European Union, 2019). These distinctions are exactly why DSMG separates “layer–product–actor”: the same physical capability (Table 2) can be monetized, verified, or even made eligible in different ways depending on the procurement layer, and this layer-specific logic is then embedded in the integrated mapping matrix (Table 4).

5.3.3 DSMG framework and integrated capability-to-market mapping

With Tables 2, 3 established, the DSMG synthesis becomes operational through the integrated capability-to-market mapping reported in Table 4 and visualized in Figure 8. Conceptually, each entry in Table 4 corresponds to the intersection.

(DER class/portfolio) × (service family) × (market/procurement layer), and therefore reflects not only what is technically possible at device level, but what is feasible under the constraints highlighted throughout the review. In particular, feasibility is jointly shaped by distribution-network physics and the locational nature of value at distribution level (Uzum et al., 2024; Gerard et al., 2018; Horowitz et al., 2018a; EUR-Lex, 2025), market verification and settlement rules (including prequalification, metering granularity, telemetry, and performance assessment) (Wang et al., 2015; ENTSO-E, 2018), and deployment realities, where DERs operate as portfolios with availability, user, and aggregation constraints (Baghaee et al., 2016; Yan et al., 2017; Mathew et al., 2022). Figure 9 summarizes the DSMG structure by linking the three evidence strands reviewed in the previous sections: distribution-network constraints, market and procurement requirements, and deployment conditions. The framework shows how distributed-resource capabilities are translated into service provision only when technical feasibility, market eligibility, measurement and verification, aggregation and governance requirements are simultaneously satisfied.

To keep the mapping replicable, Table 4 uses a rule-based suitability score that synthesizes four factors repeatedly cited as decisive in market participation for DER/DR: controllability/dispatchability, response-time match, measurability/telemetry, and aggregation feasibility relative to minimum bid/qualification thresholds (Chondrogiannis et al., 2022; Wang et al., 2015; ENTSO-E, 2018). This does not replace official eligibility criteria but supports consistent cross-study comparison, one of the core gaps identified in Section 1.

In Table 4, “Suitability” is a rule-based score (0–8) computed as the sum of four criteria, as shown in Equation 5:

S total = S ctrl + S temp + S meas + S agg , S ctrl , S temp , S meas , S agg ∈ 0,1,2 . (5)

where:

• S ctrl (Controllability/dispatchability match)
• 2 = directly dispatchable/setpoint-following (or portfolio dispatchable via EMS/aggregator)
• 1 = partially controllable (curtailment-only, SoC/comfort-limited shifting, constrained dispatch)
• 0 = essentially non-controllable for the service
• S temp (Temporal/operational match: response time and duration/firmness where relevant)
• 2 = matches typical activation window and duration/firmness needs of the service
• 1 = borderline/conditional (only some operating states, limited duration, slower ramps)
• 0 = mismatch
• S meas (Measurability/telemetry match for verification and settlement)
• 2 = typical metering/telemetry is sufficient for the service’s M&V (settlement or near-real-time)
• 1 = partially sufficient (requires upgrades/additional telemetry/site instrumentation)
• 0 = insufficient for credible settlement/verification
• S agg (Aggregation/qualification feasibility relative to minimum size and participation gates)
• 2 = typically qualifies with low friction (asset already large enough OR aggregation is standard/straightforward)
• 1 = aggregation feasible but with friction (heterogeneity, baselines, enrollment, operational uncertainty)
• 0 = qualification unlikely in typical practice

The score is mapped to Low (0–2), Medium (3–4), High (5–6), and Very High (7–8).

Supplementary Material Appendix A reports the service requirement profiles and the component-score breakdown used to compute all entries in Table 4.

Tables 2–4 together explain why DER participation pathways differ systematically across markets and services, and why results reported in the literature are often not directly transferable across jurisdictions or procurement contexts. Figure 8 visualizes the suitability values reported in the DSMG integrated capability-to-market mapping.

First, fast and dispatchable resources (most notably stationary battery storage and V2G-capable EV fleets under aggregation) tend to be structurally advantaged in balancing and reserve products. These venues typically prioritize activation speed, tracking performance, availability obligations, and high-resolution telemetry, so assets that can be directly dispatched and verified in near real time have a clearer qualification pathway and a more robust settlement logic than resources whose flexibility is indirect or slow (ENTSO-E, 2018; Wang et al., 2015). Even when other DERs can technically contribute, market participation frequently depends on whether the required control and monitoring interfaces exist at scale, which the prerequisite logic in Table 4 makes explicit.

Second, locational services such as congestion management and voltage/reactive support naturally align with distribution-level procurement because their value is intrinsically tied to feeder/node conditions, hosting-capacity limits, and local network sensitivities. For these services, feasibility cannot be inferred from generic DER capability alone: it depends on whether the DER is located in the relevant constraint area, whether the DSO has sufficient observability to confirm impact, and whether local qualification and dispatch arrangements exist. This is why DSO-led mechanisms and local flexibility markets emerge as central enablers for unlocking DER value at scale, especially under high DER penetration where distribution upgrade costs and operational limits become binding (EUR-Lex, 2025).

Third, retail and community schemes frequently represent the initial market entry point for single prosumers and small portfolios because participation barriers are comparatively low and access is largely mediated through consumer-facing arrangements such as self-consumption, dynamic pricing, net billing, and community sharing frameworks. In the EU context, these pathways are explicitly supported by retail-market and community-energy legislation, which enables participation without requiring the same degree of prequalification, telemetry intensity, or minimum bid sizes typical of wholesale and reserve products (European Parliament and Council of the European Union, 2019; smartEn, 2022; Parliament and of the European Union, 2018). However, Tables 2–4 also show that while retail/community routes are accessible, the set of services that can be monetized there is narrower unless aggregation and advanced control unlock additional stacking opportunities.

Fourth, aggregation and baseline design appear repeatedly as cross-cutting gating factors that determine whether flexibility can move from “technically possible” to “marketable and comparable.” For demand response and flexible-load portfolios, baseline construction and verification rules directly affect settlement credibility and the interpretability of outcomes across studies, while aggregation is often necessary to overcome minimum bid-size thresholds and to form portfolios with predictable availability (Wang et al., 2015; European Parliament and Council of the European Union, 2019; smartEn, 2022). The synthesis therefore clarifies why many promising DER applications remain confined to pilots: without standardized measurement, baselines, and data access, reported benefits cannot be generalized or reliably scaled.

Overall, Table 4 reinforces a central conclusion of the review: no single market layer fits all DER classes, and scaling DER participation requires tight alignment between technical capability and product design, supported by robust metering/telemetry and baseline rules, and by clear DSO–TSO coordination that prevents inconsistent procurement signals and unlocks service stacking where appropriate (Chondrogiannis et al., 2022). These findings provide the logical bridge to the subsequent discussion of benefits, challenges, and the roadmap-oriented recommendations.

Having established the DSMG framework and the integrated capability-to-market mapping, the review can now interpret DER value in a way that is consistent across network physics, market rules, and deployment evidence. In particular, the mapping clarifies which services are technically feasible, which market layers provide credible participation pathways, and where feasibility is most often constrained by verification, aggregation, or locational qualification requirements (Chondrogiannis et al., 2022). Building on this evidence-based structure, the following section applies the DSMG framework to an illustrative European portfolio comparison before the benefits, barriers, and roadmap-oriented recommendations are synthesized.

5.4 Participation-feasibility index for DSMG-based assessment

The DER–Service–Market–Governance framework can be expressed as a structured compatibility assessment between a distributed-resource portfolio and a given market or procurement pathway. This analytical layer is useful because distributed-resource participation is not determined by resource availability alone. A portfolio must also satisfy service-specific technical requirements, market-access conditions, measurement and verification rules, distribution-network constraints, and governance arrangements. Therefore, the feasibility of a participation pathway is represented here as a multi-criteria compatibility problem rather than as a single technical or economic parameter (Eltohamy et al., 2020; Kaushik et al., 2022; Hadi et al., 2022; Kara et al., 2022).

Let a denote a distributed-resource portfolio and m denote a market or procurement pathway. The participation feasibility of portfolio a in pathway m is evaluated through a normalized score P F I a , m, defined as:

P F I a , m = ∑ c = 1 C w c s a , m , c . (6)

where s a , m , c ∈ [ 0,1 ] is the normalized score of portfolio a under pathway m for criterion c, w c is the corresponding criterion weight, C is the total number of criteria, and ∑ c = 1 C w c = 1. The index ranges from 0 to 1, where values close to 1 indicate high compatibility between resource capability, service requirement, market access, and governance conditions. The formulation is not intended to replace detailed power-flow studies, market-clearing simulations, or country-specific regulatory assessment. Instead, it provides a transparent screening tool to compare participation pathways and identify the criteria that most strongly limit resource participation.

Eight criteria are considered because they reflect the main technical, digital, market, and governance conditions emerging from the DSMG synthesis. The corresponding score vector is defined in Equation 7:

s a , m = s CON , s R T , s DUR , s LOC , s TEL , s BASE , s AGG , s REG . (7)

where s CON is controllability, s R T is response-time compatibility, s DUR is duration adequacy, s LOC is locational relevance and grid compatibility, s TEL is metering and telemetry readiness, s BASE is baseline and verification feasibility, s AGG is aggregation and portfolio scalability, and s REG is regulatory and market eligibility. These criteria connect the physical attributes of distributed resources with the product and governance requirements of wholesale, retail/community, local-flexibility, and balancing/ancillary-service pathways.

The criteria are scored using a five-level ordinal scale converted into normalized values:

s a , m , c ∈ 0,0.25 , 0.50 , 0.75 , 1.00 . (8)

A score of 0 indicates that the portfolio is generally unsuitable for the pathway or that a mandatory participation condition is absent. A score of 0.25 indicates low compatibility, where participation would require substantial technical, digital, contractual or regulatory changes. A score of 0.50 indicates moderate compatibility, where participation is possible but constrained by relevant barriers. A score of 0.75 indicates good compatibility, with some remaining limitations. A score of 1.00 indicates high compatibility, where the portfolio’s capabilities and enabling conditions are well aligned with the pathway requirements.

Table 8 defines the criteria used in the participation-feasibility index.

TABLE 8. Criteria used in the DSMG participation-feasibility index.

A weighted-sum formulation is adopted because the index is intended as a transparent screening and comparison tool. This form allows individual criteria to be inspected directly and enables sensitivity analysis on the relative importance of technical capability, digital readiness, market access, and governance conditions. More complex multi-criteria methods can be used when higher-resolution data are available; however, for a review-based synthesis and illustrative portfolio comparison, the weighted-sum model provides a reproducible first-order assessment (Ji et al., 2023; Watróbski et al., 2019).

The default formulation uses equal weights, as defined in Equation 9:

w c = 1 C . (9)

where C = 8. Equal weighting is appropriate when the objective is to compare participation pathways without imposing a specific stakeholder preference. However, distributed-resource participation can be evaluated from different perspectives. A distribution system operator may prioritize locational relevance, grid compatibility, observability and controllability; an aggregator may prioritize scalability, telemetry, baseline feasibility and market eligibility; a regulator may prioritize market access, verification, consumer participation and system-level efficiency. Therefore, sensitivity analysis can be performed by varying the weight vector, as shown in Equation 10:

w r = w CON r , w R T r , w DUR r , w LOC r , w TEL r , w BASE r , w AGG r , w REG r . (10)

where r denotes the weighting perspective. The ranking stability of portfolio a under pathway m is then evaluated by comparing the score and rank variation across weighting scenarios:

Δ P F I a , m = P F I a , m max − P F I a , m min , (11)

R S a , m = 1 − r a n k a , m max − r a n k a , m min N − 1 . (12)

where N is the number of compared portfolios. R S a , m ranges from 0 to 1. Values close to 1 indicate that the relative suitability of the portfolio is stable across stakeholder perspectives, whereas lower values indicate that the portfolio ranking is sensitive to the selected weighting structure.

Table 9 reports the weighting scenarios used for sensitivity analysis.

TABLE 9. Weighting scenarios for DSMG participation-feasibility assessment.

The DSO-oriented scenario gives greater importance to locational relevance, controllability and telemetry because distribution-level activation must remain compatible with voltage limits, thermal loading, hosting capacity and protection constraints (Qamar et al., 2023; Schwägerl et al., 2026). The aggregator-oriented scenario gives greater importance to aggregation scalability, metering/telemetry readiness, baseline feasibility and regulatory eligibility because the commercial viability of aggregated portfolios depends on the ability to pool small resources, verify delivery, and access market products (Wang et al., 2015; Božičević Vrhovčak and Malbašić, 2023). The regulatory-readiness scenario emphasizes eligibility, baseline/verification feasibility, telemetry and locational compatibility because market participation must be transparent, measurable and consistent with system-operation responsibilities (European Parliament and Council of the European Union, 2019; ENTSO-E and EU DSO Entity, 2025).

For practical implementation, the DSMG assessment follows five steps:

• Define the distributed-resource portfolio a, including technology mix, rated capacity, controllability, duration, location, ownership and aggregation structure;
• Define the target market or procurement pathway m, including product type, procuring actor, activation time, minimum bid size, telemetry requirements, baseline method, settlement rule and locational qualification;
• Assign criterion scores s a , m , c using the scoring scale in Equation 8 and the definitions in Table 8;
• Compute P F I a , m using Equation 6 under the equal-weight and stakeholder-oriented weighting scenarios;
• Evaluate ranking stability through Equations 11, 12, and identify the criteria that act as participation bottlenecks.

The participation-feasibility index therefore transforms the DSMG framework from a conceptual mapping into an operational screening method. It preserves the multi-dimensional nature of distributed-resource participation while avoiding the misleading assumption that a single technical characteristic, such as installed capacity or response time, can determine market suitability. In the following section, the index is applied to representative European distributed-resource portfolios to compare their suitability across wholesale, retail/community, local-flexibility and balancing/ancillary-service pathways.

6 DSMG-based illustrative European portfolio comparison

The DER–Service–Market–Governance framework is applied here to compare representative distributed-resource portfolios across the main electricity-market and procurement pathways discussed in the previous sections. The purpose of the assessment is to show how the participation-feasibility index can translate the qualitative DSMG mapping into a reproducible portfolio comparison. The assessment is not based on a single national market simulation, because European local flexibility, aggregation, balancing and community-energy arrangements remain heterogeneous across Member States (Scrocca et al., 2026; Taromboli et al., 2025). The four pathways reflect the European market-design and demand-response context, in which storage, aggregation, consumer participation and non-fossil flexibility are increasingly emphasized (European Commission, 2024; ACER, 2025a). They also reflect local flexibility and TSO–DSO coordination evidence, where distributed-resource activation depends on network location, data exchange and operational validation (EU DSO Entity, 2026; ENTSO-E and EU DSO Entity, 2025). The selected portfolios are informed by distributed-flexibility literature and represent common combinations of photovoltaic generation, storage, electric vehicles, flexible demand and coordinated local-resource portfolios (Riaz and Mancarella, 2022).

The comparison considers five representative distributed-resource portfolios:

• Photovoltaic generation without dedicated storage or flexible control;
• Photovoltaic generation coupled with stationary battery storage;
• Electric-vehicle smart charging and vehicle-to-grid fleets;
• Flexible loads, including heat pumps, building energy management systems, and industrial demand response;
• A coordinated local portfolio combining distributed generation, storage, electric vehicles and flexible demand through an aggregator, energy community, microgrid controller, or virtual power plant.

These portfolios are evaluated across four participation pathways: wholesale and intraday energy participation, retail/community participation, local flexibility procurement, and balancing/ancillary-service participation. The assessment uses the eight DSMG criteria defined in Section 5: controllability, response-time compatibility, duration adequacy, locational relevance and grid compatibility, metering and telemetry readiness, baseline and verification feasibility, aggregation and portfolio scalability, and regulatory and market eligibility.

6.1 Portfolio assumptions

The portfolio definitions used in the illustrative assessment are reported in Table 10. The assumptions are consistent with European evidence showing that distributed flexibility is increasingly activated through aggregation, local flexibility platforms, TSO–DSO coordination mechanisms, and community-scale resource coordination (Riaz and Mancarella, 2022; CoordiNet Consortium, 2022; OneNet Consortium, 2023). The selected portfolios are not intended to represent all possible distributed-resource configurations. They are chosen because they cover the main capability profiles relevant to electricity-market participation: non-dispatchable generation, dispatchable storage-coupled generation, mobile storage, flexible demand, and coordinated multi-resource portfolios.

TABLE 10. Representative distributed-resource portfolios used in the DSMG assessment.

The EV smart-charging and V2G portfolio is included because electric vehicles can act as flexible demand, mobile storage and, when bidirectional operation is enabled, grid-support resources. Recent transport-decarbonization and EV-grid studies show that EV flexibility depends on charging infrastructure, user availability, battery degradation, network impacts and the economic conditions of market participation, including balancing-market opportunities (Reddy et al., 2024; Lewicki and Coban, 2025; Lewicki et al., 2024). Therefore, in the DSMG assessment, the EV/V2G portfolio is treated as a high-potential but strongly conditional resource class, whose feasibility depends on aggregation, telemetry, connection duration, state-of-charge constraints, and regulatory eligibility.

6.2 Scoring procedure

For each portfolio a and market pathway m, the eight DSMG criteria are scored on the normalized five-level scale introduced in Section 5:

s a , m , c ∈ { 0,0.25 , 0.50 , 0.75 , 1.00 }

The equal-weight participation-feasibility index is then calculated as:

P F I a , m = 1 8 ∑ c = 1 8 s a , m , c

The score vectors used for the assessment are reported in Table 11. The order of criteria is:

s CON , s R T , s DUR , s LOC , s TEL , s BASE , s AGG , s REG

TABLE 11. Criterion scores used for the DSMG portfolio assessment.

where s CON is controllability, s R T is response-time compatibility, s DUR is duration adequacy, s LOC is locational relevance and grid compatibility, s TEL is metering and telemetry readiness, s BASE is baseline and verification feasibility, s AGG is aggregation and portfolio scalability, and s REG is regulatory and market eligibility.

6.3 Equal-weight participation-feasibility results

Table 12 reports the equal-weight participation-feasibility index for each portfolio and pathway. The values should be interpreted as relative compatibility scores rather than absolute market revenues. A high score indicates that the portfolio is technically and institutionally well aligned with the target pathway. A lower score indicates that one or more participation gates are weak, such as controllability, duration, telemetry, baseline verification, aggregation, locational qualification, or regulatory eligibility.

TABLE 12. Equal-weight DSMG participation-feasibility index for representative European distributed-resource portfolios.

Figure 10 visualizes the equal-weight participation-feasibility index values reported in Table 12.

The results show three main patterns. First, PV-only portfolios obtain the lowest scores across all pathways. This does not indicate low value of photovoltaic generation as an energy resource; rather, it reflects the limited controllability and duration of PV-only portfolios when they are assessed as flexibility providers. PV-only resources can support self-consumption and renewable-energy production, while inverter standards and control functions can enable voltage-related services under appropriate grid-code and control conditions (IEEE, 2018; Narang et al., 2021). At high penetration, PV integration also depends on power-quality requirements and grid-code compliance, because inverter behaviour affects voltage quality, harmonic distortion and operational compatibility with distribution networks (Honrubia-Escribano et al., 2015; Gandhi et al., 2020; IEEE, 2018). However, their participation in balancing, ancillary services or dispatchable local flexibility remains limited unless they are combined with storage, curtailment mechanisms, advanced inverter control or aggregation (Riaz and Mancarella, 2022).

Second, PV coupled with battery storage substantially increases participation feasibility. Storage improves controllability, response time, duration, baseline predictability and the possibility of shifting local renewable production toward higher-value periods or constrained network conditions, which are key dimensions in distributed-flexibility characterization (Adham et al., 2025; Riaz and Mancarella, 2022). For this reason, PV + battery portfolios obtain high scores in local flexibility and balancing/ancillary-service pathways. European demonstration evidence also shows that storage-equipped distributed portfolios can become relevant for flexibility procurement when telemetry, aggregation and market-access conditions are satisfied (OneNet Consortium, 2023). Their remaining limitations are mainly economic and operational rather than purely technical, including battery degradation, cycling strategy, market-access conditions and revenue-stacking uncertainty.

Third, coordinated local portfolios obtain the highest overall scores because they combine complementary resource characteristics. Photovoltaic generation contributes local renewable energy, batteries provide fast and dispatchable flexibility, electric vehicles add scalable but availability-constrained storage, and flexible loads provide demand-side modulation (Riaz and Mancarella, 2022). Energy communities and microgrid-based arrangements can provide governance and internal coordination structures for such heterogeneous portfolios (Muttaqee et al., 2025; Shahzad et al., 2023; Taromboli et al., 2025). When these assets are coordinated by an aggregator, energy community, microgrid controller or virtual power plant, the portfolio can improve internal balancing, diversify availability, reach minimum bid sizes and participate in multiple market or procurement pathways. European flexibility initiatives such as CoordiNet, OneNet and EDGE illustrate how distributed portfolios can be tested through flexibility platforms, DSO procurement procedures and coordinated activation models (CoordiNet Consortium, 2022; OneNet Consortium, 2023; E-Distribuzione, 2025).

6.4 Interpretation by market pathway

Wholesale and intraday participation is most suitable for portfolios that can forecast, schedule, aggregate, and adjust net injections or withdrawals (Conejo et al., 2010; Wang et al., 2015). PV-only portfolios can participate through energy sales and self-consumption optimization, but their limited dispatchability constrains their flexibility value. PV + battery and coordinated portfolios are more suitable because storage and aggregation reduce forecast imbalance and increase controllable response (Riaz and Mancarella, 2022). EV fleets and flexible loads can also support wholesale exposure through price-responsive demand, but their performance depends strongly on user availability, contractual design, and automation.

Retail and community pathways show the highest compatibility for coordinated local portfolios. This result reflects the role of internal coordination, collective self-consumption, dynamic tariffs, shared storage, and local benefit allocation. Energy communities and microgrid-based arrangements are particularly relevant when they pool heterogeneous resources and establish a governance structure for investment, operation, metering, and benefit sharing (Parliament and of the European Union, 2018; Taromboli et al., 2025). However, their practical performance depends on national implementation rules, data access, internal settlement design, and the ability to interact with external markets or flexibility procurement mechanisms (European Parliament and Council of the European Union, 2019; EU DSO Entity, 2026).

Local flexibility procurement is most compatible with portfolios that combine controllability and locational relevance. The highest scores are obtained by coordinated local portfolios and PV + battery systems, because they can modify active-power flows at specific nodes and potentially support congestion management, voltage control, and transformer loading reduction (EU DSO Entity, 2026). EV fleets and flexible loads also perform well when they are located in constrained areas and can be aggregated with reliable telemetry and verification. The result is consistent with European local flexibility experience, where the value of flexibility is not generic but depends on network location, activation period, and the specific operational need of the distribution system operator (Scrocca et al., 2026; CoordiNet Consortium, 2022). Platform and pilot experiences such as GOPACS and EDGE further illustrate the practical importance of locational qualification, DSO procurement rules and data exchange (GOPACS, 2026; E-Distribuzione, 2025).

Balancing and ancillary-service participation favors fast, controllable, aggregated resources. Batteries, V2G fleets and coordinated portfolios score highly because they can provide rapid active-power modulation, and recent EV-fleet studies confirm that managed charging and V2G participation can affect both urban-network operation and balancing-market economics when aggregation and market rules are properly represented (Lewicki and Coban, 2025; Lewicki et al., 2024). However, the activation of distribution-connected resources for system-wide services requires coordination with distribution-network constraints. A portfolio suitable for balancing from the transmission-system perspective may be unavailable or partially constrained from the distribution-system perspective if its activation creates voltage violations, congestion, or protection-related risks (ENTSO-E and EU DSO Entity, 2025; Wen et al., 2025).

6.5 Bottleneck interpretation from DSMG criterion scores

The DSMG score vectors can also be used to identify the criteria that most strongly limit each portfolio. The resulting portfolio-specific bottlenecks are summarized in Table 13. To keep the interpretation transparent, bottlenecks are identified by averaging each criterion score across the four participation pathways considered in Table 11, as defined in Equation 13:

s ̄ p , c = 1 M ∑ m = 1 M s p , m , c , (13)

TABLE 13. Main participation bottlenecks derived from the DSMG criterion scores.

where p is the portfolio, c is the DSMG criterion, and M = 4 is the number of market or procurement pathways. The main bottleneck criteria are those with the lowest average score for each portfolio. This procedure does not replace detailed techno-economic or regulatory assessment, but it makes explicit which DSMG criteria most constrain participation in the illustrative comparison.

This interpretation confirms that distributed-resource participation should be treated as a portfolio and governance problem rather than only as a technology problem. Technical capability is necessary but insufficient. Participation becomes scalable when controllability is combined with digital observability, aggregation, market eligibility, locational qualification, baseline verification and coordination between transmission- and distribution-level operation (Wang et al., 2015; Uzum et al., 2024).

6.6 Stakeholder-oriented interpretation of weighting scenarios

Although the illustrative comparison in this section reports equal-weight participation-feasibility results, the weighting scenarios introduced in Section 5.4 indicate how the interpretation of portfolio suitability could change under different stakeholder perspectives. A DSO-oriented perspective would assign greater importance to locational relevance, controllability and telemetry, because distribution-level activation must remain compatible with feeder constraints, voltage limits and local observability. Under this perspective, coordinated local portfolios and PV + battery systems would be expected to remain strong candidates for local flexibility because they can modify active-power flows at specific network locations.

An aggregator-oriented perspective would give greater importance to aggregation scalability, metering, telemetry, baseline feasibility and market eligibility. This would increase the relative attractiveness of EV fleets, flexible loads and mixed local portfolios when they can be pooled into reliable, verifiable and marketable resources. A regulatory-readiness perspective would instead emphasize clear eligibility rules, transparent verification and compatibility with system-operation responsibilities. These qualitative observations suggest that portfolio ranking is likely to depend on the stakeholder perspective, but a full numerical sensitivity analysis would require recalculating the participation-feasibility index under each weighting scenario and reporting the resulting score and rank variations.

6.7 Implications for the DSMG framework

The illustrative application supports the need to connect resource attributes, service requirements, market pathways and governance conditions in a single analytical structure. Installed capacity or annual energy production alone does not determine market suitability. PV-only systems may have high renewable-energy output but limited flexibility feasibility when they lack storage, curtailment capability, advanced inverter control or aggregation. Conversely, resources with lower installed generation capacity, such as flexible loads or EV fleets, may provide high flexibility value when they are located in constrained network areas, aggregated into reliable portfolios, equipped with suitable control and telemetry, and connected to appropriate market products. Similarly, energy communities and microgrids are relevant not because they represent additional resource technologies, but because they provide coordination environments that can combine heterogeneous assets, manage local constraints, allocate benefits, and interface with external market or procurement mechanisms.

The DSMG-based assessment therefore provides three practical contributions. First, it identifies which portfolio types are most compatible with each participation pathway under the adopted scoring assumptions. Second, it reveals the technical, digital and regulatory criteria that constrain participation, including controllability, response time, duration, locational relevance, telemetry, baseline verification, aggregation and market eligibility. Third, it supports roadmap development by showing whether barriers are mainly related to resource capability, network location, metering and telemetry, baseline construction, aggregation, or governance and regulatory access. These insights provide the basis for the benefit, challenge and recommendation synthesis developed in the following section.

7 Key benefits, challenges, and roadmap-oriented recommendations

The previous sections showed that distributed-resource participation depends on the interaction between resource capability, market-access conditions, distribution-network constraints, aggregation arrangements, and governance responsibilities. Therefore, the benefits and challenges of distributed energy resources should not be interpreted only at the technology level. They should also be evaluated through the market and operational pathways through which distributed portfolios provide value. This section uses the DSMG perspective to synthesize the economic, environmental, technical, social, regulatory, financial and operational implications of DER participation, and to translate the main barriers into roadmap-oriented enabling actions.

7.1 Economic, environmental, technical, and social benefits

From a DSMG perspective, DER benefits materialize through specific value streams across retail and community schemes, local flexibility procurement, wholesale participation, and balancing or ancillary-service mechanisms. The main benefits include lower energy costs, reduced emissions, local network support, improved resilience, consumer participation, and new flexibility services. However, these benefits are not automatic. They depend on the same participation conditions identified in the DSMG mapping, including observability, controllability, aggregation, baseline verification, locational qualification, and market eligibility (Chondrogiannis et al., 2022; Wang et al., 2015; Uzum et al., 2024). This subsection therefore summarizes the multi-dimensional benefits of renewable-based DER portfolios while keeping the link between technology, service pathway and governance context explicit.

The DSMG synthesis and the illustrative portfolio comparison indicate that distributed-resource participation creates value only when technical capability, market access, measurement and verification, aggregation, and governance are aligned. A PV-only portfolio may provide significant renewable generation but limited dispatchable flexibility. Conversely, a smaller portfolio of flexible loads, batteries, or electric vehicles may provide high operational value if it is located in a constrained area and coordinated through an aggregator or local flexibility platform. Therefore, DER benefits should be assessed through the combined lens of energy contribution, flexibility capability, locational value, digital readiness, and market accessibility.

From a DSMG perspective, the relevance of DER portfolios is best interpreted through their ability to reduce the externalities of fossil-based supply and provide locally deployable capacity and flexibility that can be valued across distribution-level planning and operation. When DERs displace fossil generation, associated GHG and air-pollutant emissions can decrease, depending on the marginal generation mix and operating conditions (Akorede et al., 2010). From a network-planning perspective, DERs can supply part of the demand locally, which may reduce the need for new transmission and distribution (T&D) infrastructure and support more efficient sizing of distribution assets (El-Khattam and Salama, 2004). Additional system-level value stems from improved operational flexibility and reliability: DERs can be rapidly deployed and scaled to follow demand, improve voltage and frequency performance when properly integrated, and increase resilience by sustaining critical loads during outages. Furthermore, locating generation close to demand centers can reduce long-distance power flows and associated losses (Dynamic Ratings, 2025). At the same time, Gómez San Román highlighted that higher DER penetration increases the importance of robust cybersecurity and secure control interfaces, while coordinated DER operation may also contribute to resilience under cyber or extreme-event conditions (Gómez San Román, 2017). Solar PV and other DER technologies are therefore expected to play a central role in future power systems, contributing to deep decarbonization and, in many contexts, higher public acceptance (Rahdan et al., 2024). The main benefits of DERs for distribution networks are summarized in Figure 11.

At the system and market level, distributed-resource portfolios contribute through five main channels. The first is renewable-energy integration, because photovoltaic and wind resources reduce the need for fossil-based generation, while storage, electric vehicles, flexible loads, and demand response can shift demand or supply in time, reducing curtailment and improving the utilization of variable renewable generation (Adham et al., 2025; Kaushik et al., 2022; Le Coq et al., 2025). The second is distribution-network support, because observable and controllable resources located in constrained feeders can provide congestion management, voltage support, transformer-loading reduction, peak shaving, and reinforcement deferral (Qamar et al., 2023; Saxena et al., 2024; EU DSO Entity, 2026). The third is system-level flexibility, because aggregated batteries, electric vehicles, flexible buildings, heat pumps, and industrial demand response can contribute to balancing and ancillary services when they satisfy response-time, telemetry, prequalification, and baseline requirements (Božičević Vrhovčak and Malbašić, 2023; Ranaboldo et al., 2024; Hadi et al., 2022; EU DSO Entity and ENTSO-E, 2024). The fourth is consumer and community participation, because dynamic retail contracts, aggregation, renewable energy communities, citizen energy communities, and local energy markets can transform consumers into active participants when contractual rules, data access, settlement, and benefit allocation are transparent (European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; Taromboli et al., 2025; Mathieu et al., 2025). The fifth is resilience and operational adaptability, because microgrids, energy communities, and coordinated local portfolios can improve local balancing, islanding capability, emergency operation, and recovery from disturbances when supported by appropriate protection, control, and cybersecurity arrangements (Muttaqee et al., 2025; Shahzad et al., 2023; ENISA, 2024; Liu et al., 2024).

7.1.1 Economic benefits

By reducing consumer electricity costs, creating jobs, and deferring grid infrastructure upgrades, DERs can deliver significant economic value (Calvillo et al., 2016; Wang et al., 2015; El-Khattam and Salama, 2004). DER owners can reduce utility expenditures by producing electricity close to the point of consumption (El-Khattam and Salama, 2004). Depending on the regulatory framework, additional revenues may be obtained through energy export or participation in local or regional markets (Wang et al., 2015; Calvillo et al., 2016; Eid et al., 2016). The renewable DER industry also contributes to employment in installation, engineering, operation and maintenance, and manufacturing (Kumar et al., 2022; Gielen et al., 2016). From a network perspective, DERs can relieve the congestion and lower the peak demand, which may assist utilities to evade or defer costly reinforcements in their transmission and distribution (El-Khattam and Salama, 2004; Cossent et al., 2009; Wang et al., 2015). In addition, new forms of business like peer-to-peer trading, virtual power plants, and demand response have the potential to increase economic activity and diversify the source of income (Teotia and Bhakar, 2016). Shared PV and storage setups and energy-community business profiles may further enhance value sharing and minimize grid dependence in a variety of economic scenarios, community and multi-user sites (Viti et al., 2020; Walker, 2008; Zakeri et al., 2021).

From a DSMG perspective, these economic benefits depend on the ability to monetize multiple value streams without creating conflicts among them. Retail savings, energy export, local congestion management, voltage support, balancing services, and ancillary-service revenues may all be technically available to the same portfolio, but they are not automatically stackable. Revenue stacking requires clear service priority, availability reservation, telemetry, settlement rules, and coordination between local and system-level activation (ENTSO-E and EU DSO Entity, 2025; Wen et al., 2025; EU DSO Entity and ENTSO-E, 2024).

7.1.2 Environmental benefits

DERs offer significant environmental benefits by cutting GHG emissions, air pollution, and fossil fuel dependence (Akorede et al., 2010; Shahsavari and Akbari, 2018; Gielen et al., 2016). Renewable DER technologies such as solar PV, wind, biomass/biogas-based generation and micro-hydropower can contribute to a cleaner energy mix, improve local air quality and support climate-change mitigation, with associated public-health co-benefits (Akorede et al., 2010; Shahsavari and Akbari, 2018; Kirubakaran et al., 2009). Isolated or weak-grid settings also offer an opportunity to reduce reliance on diesel generation through DER-based mini-grids and microgrids, supporting decarbonization and more sustainable local energy supply (Ahmad et al., 2022; Das et al., 2020; Yan et al., 2017; Mathew et al., 2022).

The environmental impact of DERs also depends on operational coordination. Renewable generation produces the greatest system value when it is not only installed but also integrated into flexible portfolios that reduce curtailment, align local production with demand, and lower the need for fossil-based balancing. Storage, demand response, electric vehicles, and heat pumps can therefore increase the effective environmental value of renewable DERs when they shift consumption or supply toward periods of high renewable availability (Adham et al., 2025; Kaushik et al., 2022; Le Coq et al., 2025).

7.1.3 Technical benefits

DERs have the capability to increase grid resilience and reliability and minimize transmission losses (Basak et al., 2012; Cook et al., 2020; El-Khattam and Salama, 2004). In high-loss distribution systems, comparatively simple infrastructure modifications can be combined with DERs like PV, especially where these are backed up by sophisticated control and power-electronic interfaces (Basak et al., 2012; Honrubia-Escribano et al., 2015; Apostolopoulou et al., 2016). Moreover, the projected rise in distributed electricity demand by heat pumps and EVs can partially be countered by an increase in distributed generation (El-Khattam and Salama, 2004; Rahdan et al., 2024). Microgrids powered by DERs have the ability to offer continuity of supply during blackouts, extreme weather or broader grid disruptions (Basak et al., 2012; Ahmed et al., 2024b; Das et al., 2020). These capabilities enable the grid modernization process when coordinated (e.g., by means of aggregation and flexibility scheduling), and assist in a transition to more cost-effective, adaptive and intelligent electricity systems (Torbaghan et al., 2018; Wang et al., 2015; Uzum et al., 2024).

Technically, the main benefit of DERs emerges when resource controllability is aligned with network needs. Batteries, EV charging systems, heat pumps, flexible loads, and inverter-based generation can support peak reduction, voltage regulation, congestion management, and local balancing when they are observable, controllable, and connected at electrically relevant nodes. Cold thermal storage and PCM-based air-conditioning systems can also increase the flexibility of building cooling loads by shifting part of the cooling demand in time, although their contribution to electricity-market participation depends on controllability, storage duration and verification of the delivered load shift (Afsharpanah et al., 2022). However, these same resources can also create operational stress if they are activated without considering voltage limits, thermal limits, hosting capacity, short-circuit levels, and protection coordination (Qamar et al., 2023; Saxena et al., 2024; EU DSO Entity, 2026).

7.1.4 Social benefits

DERs can increase involvement in the energy economy by empowering households, communities, and small businesses to produce, store, and trade electricity as well as enhance local acceptance and control of the transition (Koirala et al., 2016b; Gui and MacGill, 2018; Okundamiya et al., 2014; Rae and Bradley, 2012). With mini-grids, solar home systems, and methane-digester-based technologies, energy poverty can be lowered in rural and remote regions and more people can access basic services, including healthcare, education, and communications (O’Shaughnessy, 2021; Fox, 2023). Meanwhile, the social uptake requires trust, the sense of fairness, and local-appropriate incentives, which have been found as conditional factors again and again to stimulate the durable involvement of the community (Walker et al., 2010; Rae and Bradley, 2012; Okundamiya et al., 2014).

The social dimension is especially important for energy communities, microgrids, and aggregation-based participation. These arrangements may increase local acceptance and distribute benefits more broadly, but they can also reproduce inequalities if participation is limited to consumers with capital, suitable buildings, digital literacy, or flexible assets. Therefore, consumer protection, transparent benefit allocation, accessible financing, data rights, and inclusive governance are necessary conditions for socially robust DER participation (Taromboli et al., 2025; Urban et al., 2025).

Key mechanisms that enable DERs to create environmental, economic, technical, and social value are the minimization of CO₂ emissions and energy expenses and improving grid stability (Akorede et al., 2010; El-Khattam and Salama, 2004; Rahdan et al., 2024). In addition to job creation, the deployment of DER may also lead to a reduction in the need for large centralized grid investments, transferring a part of the capacity development to the distribution edge and allowing the local market coordination and valorization of flexibility (Wang et al., 2015; Dudjak et al., 2021; Eid et al., 2016; Cossent et al., 2009). In addition, the solutions can make the local resilience stronger and allow communities to be more actively involved in the creation of clean energy value (Koirala et al., 2016b; Walker, 2008; Koirala et al., 2016a). All these benefits, in general, highlight the functionality of DERs as empowerment resources to a more equitable, flexible, and sustainable electricity system (Koirala et al., 2016b; Rahdan et al., 2024; Wang et al., 2015).

7.2 Technical, regulatory, financial, and operational challenges

Despite these benefits, the DSMG framework shows that DER participation is constrained by barriers arising across four interconnected dimensions. Resource-related barriers concern controllability, duration, response time, degradation, and user availability. Network-related barriers concern voltage rise, congestion, hosting capacity, reverse power flow, short-circuit levels, and protection coordination. Market-related barriers concern product definition, minimum bid size, prequalification, baselines, settlement, telemetry, and revenue stacking. Governance-related barriers concern actor roles, TSO–DSO coordination, aggregator responsibilities, energy-community rules, data access, cybersecurity, and consumer protection.

Variable renewable DERs such as distributed solar PV and wind have high deployment potential, but their integration can create operational challenges when generation is intermittent, spatially concentrated, or poorly coordinated with local demand (Gandhi et al., 2020; Gielen et al., 2016; International Energy Agency, 2024). At distribution level, high DER penetration can affect voltage profiles, reverse power flows, equipment loading, protection settings and power quality, with impacts that vary strongly by feeder topology, local demand, inverter settings and hosting capacity (Qamar et al., 2023; Saxena et al., 2024; Tariq et al., 2021). These challenges are not only technical: they also determine whether DER flexibility can be safely activated in market or procurement mechanisms. A portfolio that is attractive from a wholesale or balancing perspective may be locally constrained if its activation worsens congestion, voltage violations or protection risks.

Several challenges may also affect the overall growth of DER technologies in the distribution energy market. Variable renewable energy technologies, including distributed customer-adopted installations like solar and wind, have enormous growth potential in recent years (Gielen et al., 2016; International Energy Agency, 2024; Gorjian et al., 2020a). The intermittency of these technologies is, in fact, the primary obstacle to their integration; in order to maintain the instantaneous balance of generation and demand, other resources must quickly adjust their power production. Power systems will require more flexible generation capacity due to both anticipated and unforeseen fluctuations in variable technologies power output (Gómez San Román, 2017). Another challenge could be of the impact of DERs like PV on grid voltage, frequency, and costs has been examined in a number of studies. However, there is substantial ambiguity in the results of such studies due to the complexity of distribution grids, with some indicating very minimal effects due to PV, others demonstrating network improvement costs for varying PV penetration levels (Horowitz et al., 2018a; Gandhi et al., 2020; EUR-Lex, 2025; Horowitz et al., 2018b). According to (Dynamic Ratings, 2025), DERs have many advantages, but integrating them into the energy grid is not without its difficulties. Among the major obstacles are Grid Integration as it can be difficult to integrate DERs into the current grid system, Energy Storage and Management like the DERs, such as solar and wind, are frequently sporadic, producing electricity only when the sun shines or the wind blows. Grid resilience and dependability may also be hampered by DERs’ decentralized architecture. The local energy supply may be impacted if specific DERs encounter technical problems or outages. Demand response and load management is also the main challenge as the DERs have a big impact on data security and privacy as well as patterns of electricity consumption. DERs challenges are addressed in detail in the next section.

The first group of barriers is related to distribution-network constraints. High penetration of distributed generation and electrified demand can cause voltage rise, thermal overloading, reverse power flow, short-circuit-current variation, protection-coordination issues, phase unbalance, and power-quality problems (Qamar et al., 2023; Saxena et al., 2024; Tariq et al., 2021). These constraints are location-specific and cannot be solved by a uniform penetration threshold. They require hosting-capacity assessment, feeder-level observability, active/reactive power control, adaptive protection, and coordination between connection studies and market activation rules.

The second barrier is the mismatch between market activation and grid feasibility. A resource portfolio may be suitable for wholesale trading or balancing from a system-level perspective, but its activation may create congestion or voltage violations in the distribution network. This is particularly relevant when aggregators control many behind-the-meter resources without sufficient visibility of local network conditions. Grid-safe flexibility activation therefore requires mechanisms for distribution-system-operator validation, locational prequalification, bid filtering, or coordinated activation between transmission and distribution system operators (ENTSO-E and EU DSO Entity, 2025; EU DSO Entity and ENTSO-E, 2024; ACER, 2025b).

The third barrier concerns observability and controllability. Many distributed resources are connected behind the meter and are not directly visible to the distribution system operator. Smart meters, telemetry, standardized data exchange, and interoperable control interfaces are required to convert distributed assets into verifiable flexibility resources (European Commission, 2022; EU DSO Entity and ENTSO-E, 2024). However, digital infrastructure is unevenly deployed across Member States and across voltage levels. Limited observability leads to conservative hosting-capacity estimates, weak local-flexibility procurement, higher verification uncertainty, and reduced trust among market actors.

The fourth barrier is baseline and measurement uncertainty. Demand response, flexible loads, and electric-vehicle charging require an estimate of what consumption would have been without activation. Baseline errors can create settlement disputes, overestimate delivered flexibility, or discourage participation. Baseline definition is especially complex for weather-sensitive loads, industrial processes, residential portfolios, and energy-community arrangements. For this reason, flexibility products should be designed with transparent baseline methods, data-quality requirements, and verification rules appropriate to the resource type (ACER, 2025a; Božičević Vrhovčak and Malbašić, 2023; Ranaboldo et al., 2024; Mathieu et al., 2025).

7.2.1 Technical challenges

From a distribution-network perspective, the most persistent technical barrier to large-scale DER integration is the mismatch between variable, inverter-based generation and distribution grids that were historically designed for largely predictable, one-directional flows. High penetrations of rooftop PV and distributed wind can create voltage fluctuations along feeders, with overvoltage around midday under strong PV injection and under voltage during evening demand peaks when local generation drops. This effect is amplified by the spatial concentration of prosumers on the same feeder and by limited on-line observability of low-voltage networks, making traditional voltage regulation strategies less effective (Gandhi et al., 2020; Alboaouh and Mohagheghi, 2020; Horowitz et al., 2018a; EUR-Lex, 2025).

A closely related issue is the emergence of bidirectional power flows. When local generation exceeds local demand, power can be exported upstream toward the medium-voltage network, violating the traditional operating assumption that power flows from transmission to distribution and then to end users. Reverse flows complicate protection coordination, because legacy protection schemes may be less sensitive or may miscoordinate when fault currents and flow directions differ from those expected. Bidirectional flows can also overload equipment that was sized for downstream delivery, particularly in feeders with high simultaneous PV output, thereby increasing reinforcement needs and operational complexity (Horowitz et al., 2018a; EUR-Lex, 2025; Horowitz et al., 2018b).

Short-circuit-current impacts are particularly important because the acceptable penetration of distributed generation in an existing distribution network may be constrained by the protection system before voltage or thermal limits are reached. Therefore, statements about admissible DER penetration should not be expressed as a fixed universal percentage unless they are supported by feeder-specific short-circuit and protection-coordination studies (Saber et al., 2017).

Intermittency and variability of renewable DERs remain a fundamental challenge, because solar and wind output fluctuates with irradiance, cloud cover, wind speed, and seasonal patterns. Maintaining real-time balance between generation and demand therefore requires additional flexibility from dispatchable assets, storage, and demand response, and also increases the need for fast operational actions and coordinated control. In systems with growing shares of variable DERs, the requirement for flexible capacity increases under both anticipated and unanticipated ramps, stressing conventional resources and motivating the integration of storage and demand-side flexibility portfolios (Gómez San Román, 2017; Wang et al., 2015).

Finally, the lack of grid visibility and real-time monitoring in many distribution networks limits the ability of DSOs and utilities to operate DER-rich grids efficiently. Compared to transmission systems, distribution systems are usually less densely sensorized and less telemonitored which limits situational awareness of DER outputs and operating states as well as local constraints. This constraint has an impact on fault location and restorability but has a direct effect on the possibility to execute dynamic DER dispatch, congestion management, and local balancing services directly the services emphasized as locationally valuable in distribution-level settings (Uzum et al., 2024; Prettico et al., 2016; Chondrogiannis et al., 2022).

These technical barriers confirm that DER integration cannot be evaluated only by installed capacity or annual energy production. The same DER portfolio can be beneficial or problematic depending on feeder location, coincidence with local demand, inverter settings, protection configuration, telemetry availability, and activation rules. Therefore, local network constraints must be embedded into DER market participation through hosting-capacity assessment, local prequalification, grid-safe dispatch, and TSO–DSO coordination.

7.2.2 Regulatory challenges

The regulation and policy frameworks may either hasten the implementation of DERs or be a constant impediment to faster implementation and make DERs unable to deliver system value beyond self-consumption. One of the early regulatory issues is the existence of weak or orphaned DER regulations such as non-harmonized interconnection, incomplete permitting, and diverse technical regulations between utilities and between regions. In areas where the regulatory provisions were tailored to centralized regimes, the involvement of DER in markets and procurement schemes may be limited by obsolete beliefs concerning system operation, metering and distribution of responsibility. The willingness of the distribution regulation to large penetrations of DER has been identified as a primary precondition to whether DER integration will become efficient results as opposed to fragmented implementation under a European view (Cossent et al., 2009; Eid et al., 2016).

The second issue is the limited market access available to small DER owners and prosumers. Wholesale and ancillary-service contexts are frequently restricted by the sizes of minimum bids and qualification requirements on the one hand and the necessity to work via aggregators or BRPs or special market platforms, on the other hand. In the case of ambiguous aggregation rules (or in the case that distribution-level flexibility markets are in their early stages) DERs can be left in retail net metering/net billing facilities, which restrains the economic information that would otherwise encourage flexibility and service delivery. This issue is especially topical in the EU context where local flexibility markets are developing, where the institutional interfaces between DSOs and TSOs, as well as market platforms, have a critical influence on the practical pathways of participation. (Wang et al., 2015; Chondrogiannis et al., 2022; Uzum et al., 2024; Gerard et al., 2018).

The third regulatory issue is related to unpredictable compensation arrangements and valuation procedures. Economic arguments in favor of DER investment are also vulnerable to compensation schemes on exported energy, and grid services (e.g., voltage support, congestion relief, peak shaving), but the scheme of valuation is heterogeneous. Net metering and export remuneration reforms will decrease revenues and create more uncertainty, and less dynamic tariffs and time-of-use structures will undermine flexibility incentives. Simultaneously, the conflict of grid rates, connection costs, and cost distribution between the proprietors of DERs and network operators may bring about the reluctance to invest and establish obstacles to expanding flexibility portfolios (European Parliament and Council of the European Union, 2019; smartEn, 2022; Eid et al., 2016; Wang et al., 2015).

Market participation by distributed resources remains constrained by heterogeneous national implementation, minimum bid sizes, prequalification rules, telemetry requirements, settlement procedures, and the legal status of independent aggregation. These barriers are particularly important for small-scale resources, because individual assets rarely satisfy market-access conditions without aggregation (ACER, 2025a; Božičević Vrhovčak and Malbašić, 2023; EU DSO Entity and ENTSO-E, 2024). Aggregators can reduce transaction costs and diversify individual uncertainty, but their role requires clear rules on data access, balance responsibility, supplier compensation, customer consent, and remuneration of delivered flexibility.

Energy communities and microgrid-based arrangements introduce additional governance challenges. Their effectiveness depends not only on technology but also on internal decision-making, metering architecture, benefit sharing, investment responsibility, contractual design, and interaction with external markets. In Europe, the regulatory basis for renewable energy communities and citizen energy communities is established, but implementation conditions differ across Member States (European Commission, 2024; European Parliament and Council of the European Union, 2024a; European Parliament and Council of the European Union, 2024b; Taromboli et al., 2025). This heterogeneity affects the ability of communities to participate in local flexibility, aggregation, balancing, or peer-to-peer exchange under comparable conditions.

7.2.3 Financial challenges

Although technology prices have dropped, one of the most obvious obstacles to the adoption of DER, despite recent cost reductions, is related to residential users and small commercial actors. Capital expenditure of PV, wind micro-turbines, batteries, and smart inverter/control infrastructure may remain high even when installation, permitting and balance-of-system components are considered. This challenge is multiplied in low-income settings and in developing areas, where short-term affordability has the potential to override when long-term energy savings are a possibility. In addition, capital budgeting limits may cause delay in deployment even in cases where the operating case is robust (e.g., microgrids, hybrid portfolios) (Merino et al., 2021; El-Khattam and Salama, 2004).

Diffusion is also capped by the availability of funds. Poor financing facilities come about due to an uncertainty or inability of lenders to determine the cash flows of DER when lenders realize them as unforeseeable or unreliable, especially during policy endeavors or indecisive market admissions. Access to credit may be out of the question in a rural or remote location (where DERs can be of high welfare value), and custom models like leasing, pay-as-you-go plans or microloans may not be mature or widely available enough. Practically, this forms a disconnect between technical feasibility and bankability and slows down the roll out of mini-grids and community based portfolios which otherwise can be used to meet access and resilience goals (Das et al., 2020).

Another financial constraint is the uncertainty of payback periods, which is instigated by fluctuating power costs, fluctuating compensation arrangements, and performance risks, caused by weather, users, and local grid limitations. Maintenance (especially involving storage and multifaceted hybrid systems) may be more than anticipated and changing grid restrictions may limit export capacity or enhance curtailment. This uncertainty directly interrelates with the uncertainty in regulation, and with the inability to scale portfolios that depend on stacking many value streams (retail savings, flexibility payments, ancillary services) and so discourages investment and may complicate scaling portfolios (Wang et al., 2015; Chondrogiannis et al., 2022; EUR-Lex, 2025).

Financial viability is therefore closely linked to market design. DER portfolios with strong technical potential may remain unattractive if remuneration is uncertain, if flexibility payments are too small, if baseline rules are unclear, or if different value streams cannot be combined. Conversely, stable aggregation frameworks, transparent local flexibility products, and predictable compensation for grid services can improve bankability and reduce the gap between technical feasibility and investment feasibility (ENTSO-E and EU DSO Entity, 2025; Wen et al., 2025; EU DSO Entity and ENTSO-E, 2024).

7.2.4 Other challenges

Cybersecurity and susceptibility of IoT-related vulnerabilities are becoming a non-negligible operational risk as the DER deployments grow to be more interconnected and digital. DER controllers, smart inverters, advanced meters, and EV charging infrastructure increasingly rely on communication networks and software platforms. Weak authentication, outdated firmware, or poor security practices can enable unauthorized access, manipulation of DER output, data compromise, or disruption of coordinated control. Coordinated attacks on a large number of small assets could have aggregate effects on grid stability in the worst case, especially in the distribution networks that are already low-observability and low-operational-margin networks. The necessity to enhance cybersecurity is thus bound to the larger process of digitalization of the energy sector and increasing involvement of software-based coordination (Mihai et al., 2022; Ahmed et al., 2025a; Singh et al., 2022; Gómez San Román, 2017).

Simultaneously, the shift needs institutional preparedness and human-resource capacity. The DER integration requires power electronics, protection, communication, cybersecurity, software platform, and data analytics skills. There has been a shortage of technicians and engineers capable of designing, installing, operating, and maintaining DER-rich systems in many regions (especially in those where DER deployment is increasing faster than training capacity). Skill deficiencies raise the risk of inadequate system design, installations, and inefficient operation, as well as dragging the pace of implementation of new features like coordinated flexibility delivery and involvement in market-based programs. This issue is particularly applicable when it comes to microgrids, community portfolios, and digital platforms that are likely to become more important in local energy transitions (Basak et al., 2012; Singh et al., 2022; Mathew et al., 2022).

Cybersecurity and data governance are cross-cutting barriers because distributed flexibility requires communication between smart meters, inverters, batteries, electric vehicles, building controllers, aggregators, market platforms, and system operators. This increases the attack surface of the electricity system and creates risks related to availability, data integrity, unauthorized control, privacy, and cascading operational impacts (ENISA, 2024; Liu et al., 2024). Cyber-resilient participation therefore requires secure communication protocols, authentication, intrusion detection, fallback control strategies, privacy-preserving data exchange, and clear allocation of responsibility among actors.

In general, the effective DER integration is not limited to one bottleneck but rather the system of technical, regulatory, financial, and operational issues is coupled. Technical problems, which include intermittency, variable voltage, reverse flows, and restricted grid visibility complicate the work of distribution (Gandhi et al., 2020; Horowitz et al., 2018a; EUR-Lex, 2025; Horowitz et al., 2018b), as regulatory obstacles (ambiguous regulations, limited market entry, and insecure payment) inhibit the DER potential-verified service translation (Cossent et al., 2009; Chondrogiannis et al., 2022; Wang et al., 2015; European Parliament and Council of the European Union, 2019; smartEn, 2022). Financial constraints, including high upfront costs, limited financing, and uncertain paybacks, further weaken investor and consumer confidence (Merino et al., 2021; Das et al., 2020; EUR-Lex, 2025). Finally, cybersecurity risks and workforce skill needs add an additional layer of operational fragility that must be addressed to unlock DER value at scale in a secure, equitable, and market-compatible way (Mihai et al., 2022; Singh et al., 2022; Gómez San Román, 2017). Key challenges are also illustrated in Figure 12.

Table 14 summarizes the main barriers identified above and translates them into enabling actions using the DSMG structure.

TABLE 14. DSMG-based barriers and enabling actions for distributed-resource participation.

The table shows that distributed-resource participation cannot be scaled by addressing only one layer. For instance, improving battery response time does not ensure market participation if telemetry, baseline rules, aggregation, and local grid validation are missing. Similarly, creating a local flexibility market does not guarantee liquidity if resource owners lack automation, if aggregators lack data access, if local grid validation is not available, or if product definitions are not compatible with resource capabilities.

7.3 Discussion and key recommendations

The integration of DER portfolios into electricity markets is no longer a purely technological agenda. The DSMG framework clarifies why DER value is created, or blocked, at the intersection of resource capability, service requirements, market-product rules, distribution-network constraints and governance arrangements. Many barriers identified in this section are therefore cross-dimensional by nature. Voltage and congestion constraints are local and network-dependent, whereas balancing and reserve procurement are system-wide and telemetry-intensive. Similarly, small prosumers can often enter through retail or community schemes, while wholesale and ancillary-service participation usually requires aggregation, prequalification and strict verification. A coherent roadmap therefore requires coordinated progress in grid modernization, market design, regulation, cybersecurity and inclusive participation mechanisms (Chondrogiannis et al., 2022; Wang et al., 2015; Uzum et al., 2024; International Energy Agency, 2023).

The following recommendations are organized according to the main DSMG bottlenecks identified in the review: distribution-network readiness, measurement and verification, regulatory access, locational market design, digital interoperability, cybersecurity and inclusive participation.

• A first implication of DSMG is that technical upgrades must be targeted to the services that policymakers and operators expect DERs to provide. At high penetration, inverter-based resources (PV, wind) and prosumer portfolios stress distribution feeders through bidirectional flows and voltage excursions, increasing the value of local flexibility and advanced control at the DSO level (Horowitz et al., 2018a; EUR-Lex, 2025; Horowitz et al., 2018b). Consequently, enabling technologies should prioritize smart inverters with grid-support functions, local observability (advanced metering, feeder monitoring, and controllable interfaces), and storage/EV flexibility that can respond at the timescales relevant to congestion, voltage support, and local balancing (Gandhi et al., 2020; Uzum et al., 2024; Chondrogiannis et al., 2022; Horowitz et al., 2018a). At the same time, where the goal is participation in balancing and reserve products, DSMG highlights the importance of fast controllability and high-resolution telemetry, because these products are prequalification- and performance-driven by design (Wang et al., 2015; ENTSO-E, 2018). This directly motivates investments in interoperable digital communication standards and DER control interfaces, as well as aggregation-ready energy management systems that can meet activation and verification requirements across products (Mihai et al., 2022; Singh et al., 2022; Wang et al., 2015; Vamvakas et al., 2023).
• Second, DSMG makes explicit that visibility, measurement, and verification are not secondary details but central participation gates. Several of the feasibility “collapse points” identified by the mapping stem from limited distribution-level monitoring and from difficulties in verifying performance for demand response and flexibility portfolios. To enhance grid-wide visibility, a deployment of metering is not sufficient, as well as data exchange pathways and operational coordination among actors, especially when the local flexibility (DSO-procured) and system balancing (TSO-procured) is taking advantage of overlapping assets (Chondrogiannis et al., 2022; Uzum et al., 2024; Gerard et al., 2018). In parallel, the literature on real-time market integration emphasizes that baselines, telemetry and settlement logic fundamentally shape whether demand-side resources can be treated as credible market participants (Wang et al., 2015). Accordingly, robust demand response programs should be paired with transparent baseline definitions and measurement rules, so that flexibility delivery can be settled consistently and compared across case studies and jurisdictions, one of the key gaps that DSMG was designed to address (Wang et al., 2015; European Parliament and Council of the European Union, 2019; smartEn, 2022).
• Third, regulatory innovation should be framed as “market access engineering” across DSMG layers, rather than as isolated policy adjustments. Harmonized interconnection processes and clearer distribution-level operating rules reduce friction at the network layer (Cossent et al., 2009; Horowitz et al., 2018a; EUR-Lex, 2025), while retail/community provisions under EU directives provide the consumer-facing foundation for participation by small prosumers and community portfolios (European Parliament and Council of the European Union, 2019; Parliament and of the European Union, 2018). However, DSMG also shows that scaling beyond retail savings depends on enabling aggregation and verified service provision. Policies should therefore explicitly support aggregator participation, clarify roles and responsibilities across BRPs/BSPs where applicable, and provide predictable pathways for DER portfolios to stack value streams (retail savings, local flexibility, and (where feasible) balancing/ancillary participation) (Eid et al., 2016; Chondrogiannis et al., 2022; Wang et al., 2015; Uzum et al., 2024). In addition, because increasing digitalization expands the attack surface of DER-rich systems, regulatory frameworks should treat cybersecurity as a core enabling condition for DER integration rather than a purely IT concern (Mihai et al., 2022; Singh et al., 2022; Gómez San Román, 2017).
• Fourth, DSMG indicates that market reforms must reflect the “time–place” nature of value, especially at distribution level. Wholesale markets and forward products reward schedule-based portfolio management and forecasting, while balancing and reserves reward response speed and verified availability; by contrast, congestion management and voltage support are inherently locational and therefore require local qualification and observability (Chondrogiannis et al., 2022; Wang et al., 2015; ENTSO-E, 2018). This implies two complementary reforms. The first is the systematic development of local flexibility procurement mechanisms (often platform-based) that allow DSOs to procure congestion and voltage support in a transparent and comparable way across feeders and congestion areas (Chondrogiannis et al., 2022; European Parliament and Council of the European Union, 2019). The second is the standardization of valuation and settlement principles so that DER services are rewarded according to when and where they help the system, reducing the mismatch between technical potential and monetizable value that repeatedly appears in market-integration discussions (Eid et al., 2016; Chondrogiannis et al., 2022; Wang et al., 2015). In parallel, performance-based utility regulation and clearer TSO–DSO coordination frameworks can reduce contradictory incentives and improve the efficiency of procurement when the same DER portfolios can serve multiple layers (Uzum et al., 2024; Gerard et al., 2018).
• Fifth, DSMG stresses that scaling depends on interoperability and secure communications, and is not an optional attribute. The standard data models and the security control channels are required in DER participation, especially VPP-like coordination, or community portfolios or aggregation. Lack of robust protection makes more connectivity a threat to customer privacy and grid integrity undermining social acceptance and operational confidence (Mihai et al., 2022; Ahmed et al., 2025a; Singh et al., 2022; Gómez San Román, 2017). Therefore, cybersecurity-by-design and privacy-respecting data governance should be embedded into DER digitalization strategies and platform rules, especially for market-facing services that require frequent communication and verification (Wang et al., 2015; Mihai et al., 2022).
• Finally, DSMG highlights that social inclusion is structurally linked to market design. Retail/community schemes often serve as the entry point for small actors because barriers are lower and participation is aligned with consumer protections and metering frameworks (European Parliament and Council of the European Union, 2019; smartEn, 2022; Parliament and of the European Union, 2018); however, the mapping also shows that higher-value services frequently require aggregation, telemetry, and advanced control. If these enabling conditions are not made accessible, participation and benefits will concentrate among better-resourced actors, weakening the social legitimacy of the transition. Consequently, inclusive financing and ownership models (micro-credit, leasing, community investment structures, and green financing instruments) should be aligned with community energy strategies and rural electrification approaches that have demonstrated value in practice (Koirala et al., 2016b; Ahmad et al., 2022; Das et al., 2020; Balakrishnan, 2006; Walker, 2008). Public awareness initiatives and workforce training programs are equally important, because DER performance and safety depend on skilled design, installation, and operation, particularly as systems become more digital and service-oriented (Basak et al., 2012; Singh et al., 2022; Mathew et al., 2022).

Taken together, the DSMG perspective reframes the recommendations as a coordinated package: strengthen distribution-level observability and control where value is locational; enable verified participation pathways through baselines, telemetry and aggregation; improve TSO–DSO governance to avoid fragmented procurement; embed cybersecurity and data governance into flexibility platforms; and ensure that market rules and financing models allow broad participation. In this integrated scheme, DERs should be treated not only as distributed generation assets, but as controllable, verifiable and governable flexibility resources that can support a resilient, decentralized and sustainable electricity system (Chondrogiannis et al., 2022; Uzum et al., 2024; Rahdan et al., 2024).

The roadmap in Table 15 translates these recommendations into short-, medium-, and long-term actions. Short-term actions should focus on removing participation barriers that do not require fundamental market redesign. Medium-term actions should integrate local and system-level flexibility through improved coordination and digital infrastructure. Long-term actions should move toward interoperable, cyber-resilient, multi-pathway flexibility ecosystems in which distributed resources can provide services across retail, local, wholesale, balancing, and resilience-oriented pathways.

TABLE 15. Roadmap for European distributed-resource participation in electricity markets.

The roadmap indicates that the priority is not simply to increase the number of distributed resources connected to the grid. The priority is to increase the share of resources that are observable, controllable, verifiable, cyber-secure, and capable of participating in market or procurement mechanisms without compromising local network operation. In this sense, the relevant transition is from passive distributed-resource penetration toward coordinated distributed flexibility.

7.4 Policy and research implications

The European market framework creates favorable conditions for distributed flexibility, but implementation depends on the translation of high-level principles into operational rules. Demand response, aggregation, storage, and non-fossil flexibility require harmonized product definitions, transparent prequalification, data access, consumer protection, and coordination between system operators (European Commission, 2024; ACER, 2025a; EU DSO Entity and ENTSO-E, 2024). The ongoing development of demand-response network-code provisions is particularly relevant because it can reduce fragmentation in market access and clarify the roles of aggregators, system operators, and distributed-resource owners (EU DSO Entity and ENTSO-E, 2024; ACER, 2025b; European Commission, 2025b).

From a technical perspective, future research should integrate market modelling with distribution-network feasibility. Many flexibility studies evaluate economic participation without representing voltage, thermal, and protection constraints in sufficient detail. Conversely, many hosting-capacity studies evaluate technical limits without considering market products, aggregator behavior, or settlement rules. The DSMG framework suggests that future models should combine power-flow constraints, flexibility-product requirements, baseline uncertainty, aggregation behavior, and TSO–DSO coordination in a single assessment environment.

From a governance perspective, more work is needed on benefit allocation, social acceptance, and participation equity. Energy communities and microgrids can support decentralization and local resilience, but they may also reproduce inequalities if participation is limited to consumers with capital, suitable roofs, digital literacy, or flexible assets. Policies should therefore consider not only technical and market efficiency, but also accessibility, consumer protection, and fair distribution of benefits.

From a cybersecurity perspective, distributed flexibility requires the electricity sector to treat data exchange and control infrastructure as critical operational assets. Cybersecurity cannot be added after market mechanisms are designed; it must be embedded in telemetry, control, settlement, platform access, and fallback-operation procedures. The increasing reliance on aggregators and digital platforms makes cyber-resilience a prerequisite for large-scale distributed-resource participation rather than a secondary technical requirement (ENISA, 2024; Liu et al., 2024).

Overall, the DSMG-based synthesis indicates that the most robust participation pathways are those in which distributed resources are aggregated into controllable portfolios, connected to transparent market products, validated against local network constraints, and governed through clear TSO–DSO–aggregator coordination. This provides the basis for the final conclusions.

8 Limitations and future research

8.1 Limitations

The proposed DSMG framework is intended as a structured synthesis and screening tool rather than as a replacement for detailed engineering, economic or regulatory assessment. The participation-feasibility index provides a way to compare portfolios and market pathways, but its scores depend on the selected criteria, the weighting assumptions and the interpretation of available evidence. Therefore, the index should be used as an initial diagnostic tool to identify participation bottlenecks, not as a definitive measure of economic profitability or technical feasibility. In particular, the scoring values used in the illustrative comparison should be interpreted as rule-based assumptions derived from the review synthesis, rather than as empirically calibrated coefficients or statistically validated performance indicators.

A second limitation concerns the heterogeneity of European electricity markets. Although the review adopts a European perspective, market rules, local-flexibility mechanisms, aggregation models, smart-meter deployment, energy-community implementation and DSO procurement practices differ substantially across Member States. Consequently, a portfolio that is feasible in one country or demonstration project may face different regulatory or technical barriers elsewhere. The DSMG framework can support comparison across contexts, but country-specific validation remains necessary.

A third limitation is related to the illustrative portfolio comparison. The assessment compares representative portfolio types rather than actual projects with measured operation, market revenues and network constraints. The results therefore indicate relative compatibility with participation pathways, not realized financial performance. Future applications should calibrate the DSMG scores using empirical data from aggregators, local flexibility platforms, distribution-system operators, energy communities and market pilots.

A fourth limitation concerns distribution-network modelling. The review discusses hosting capacity, voltage constraints, thermal limits, reverse power flow, short-circuit levels and protection coordination, but it does not perform feeder-level power-flow or protection simulations. Detailed project-level assessment should integrate load-flow analysis, short-circuit studies, protection coordination, stochastic generation and demand profiles, and operational constraints imposed by local grid codes.

A fifth limitation concerns social and behavioral aspects. The participation of flexible demand, electric vehicles, heat pumps and community portfolios depends on user preferences, willingness to delegate control, perceived fairness, privacy concerns and trust in aggregators or community managers. These factors are difficult to capture through purely technical scoring criteria, but they can strongly influence real-world participation.

8.2 Future research agenda

Future research should move toward integrated techno-economic and regulatory models that combine distribution-network constraints with market participation. Recent work on electric-grid flexibility for variable renewable-energy integration confirms that future systems require coordinated flexibility from generation, storage, demand response, network operation and digital control, rather than isolated technology deployment (Eltohamy et al., 2026). Many current studies evaluate resource economics without representing feeder-level voltage, thermal and protection limits, while other studies assess hosting capacity without modelling market access, aggregation, settlement or revenue stacking. A more complete modelling approach should combine power-flow constraints, flexibility-product definitions, baseline uncertainty, customer availability, aggregator bidding, short-circuit and protection-coordination constraints, and TSO–DSO coordination (Saber et al., 2017). A related research need is the empirical validation of the participation-feasibility index. Future studies should apply the DSMG scoring structure to real DER portfolios, local flexibility tenders, energy-community projects, aggregator portfolios and balancing-market pilots, comparing predicted feasibility scores with observed participation outcomes, revenues, activation reliability and network impacts. This would allow the criteria, weights and bottleneck interpretation to be calibrated using operational evidence rather than only review-based judgement.

A second research direction concerns dynamic operating envelopes and grid-safe flexibility activation. Static export or import limits are increasingly inadequate for active distribution networks with high PV, storage, EV and heat-pump penetration. Dynamic operating envelopes can define time-varying import and export limits based on network conditions, forecasts and operational margins. Their integration with local flexibility markets, aggregators and balancing platforms should be further investigated, especially with respect to fairness, uncertainty, computational burden, communication failure and coordination between local and system-level services (Wickramasinghe et al., 2025).

A third research direction concerns digital twins and data-driven distribution-system operation. Digital twins can support scenario analysis, hosting-capacity estimation, flexibility validation, predictive maintenance, cyber-physical risk assessment and coordination between DER portfolios and network constraints. Future research should examine how digital twins can be connected to smart-meter data, inverter telemetry, market platforms, weather forecasts, electric-vehicle charging data and building energy-management systems while preserving privacy and cybersecurity (Værbak et al., 2024; Zomerdijk et al., 2024). In buildings and community-scale portfolios, this research direction should also consider machine-learning and reinforcement-learning control methods because these approaches are increasingly used to optimize renewable-energy utilization, HVAC flexibility and building energy-management decisions under uncertainty (Kaya et al., 2025; Vamvakas et al., 2023; Michailidis et al., 2025; 2024).

A fourth research direction concerns revenue stacking and service prioritization. Batteries, EV fleets, flexible loads and coordinated local portfolios may provide multiple services, including self-consumption optimization, wholesale arbitrage, local congestion management, voltage support, balancing and reserve. However, simultaneous participation creates conflicts in availability, baseline definition, settlement and dispatch priority. Future work should develop methods to allocate flexibility among competing services while ensuring network feasibility and fair remuneration.

A fifth research direction concerns cyber-resilient distributed flexibility. As distributed resources become more controllable and digitally connected, flexibility markets become more exposed to cyber-physical risks. Future work should integrate cybersecurity constraints into flexibility-product design, aggregator operation, telemetry requirements, fallback controls, data governance and system-restoration procedures (ENISA, 2024; Liu et al., 2024).

A sixth research direction concerns social acceptance, equity and governance. Energy communities and microgrids may support democratization and local resilience, but they may also exclude consumers without capital, digital access, flexible loads or suitable buildings. Future research should therefore evaluate distributed-resource participation through technical, economic and social indicators, including benefit distribution, energy justice, consumer protection, data rights and participation accessibility (Urban et al., 2025).

Table 16 summarizes the main future research priorities emerging from the DSMG synthesis.

TABLE 16. Future research agenda for distributed-resource participation in European electricity markets.

9 Conclusion

This review examined the participation pathways of distributed energy resources in electricity supply markets from a European perspective, with specific attention to renewable-based distributed-resource portfolios, distribution-network constraints, market and procurement pathways, governance arrangements, and enabling digital infrastructures. The analysis shows that distributed energy resources cannot be assessed only through installed capacity, annual energy production, or technology type. Their effective value depends on the alignment between physical capability, distribution-network feasibility, market-product requirements, measurement and verification rules, aggregation models, and the institutional responsibilities of transmission system operators, distribution system operators, aggregators, suppliers, market operators, and energy communities.

A central contribution of the study is the DER–Service–Market–Governance framework, which organizes distributed-resource participation as a multi-dimensional compatibility problem. At the resource level, portfolios must be characterized by controllability, response time, duration, measurability, aggregation requirement, and operational reliability. At the network level, activation must remain compatible with voltage limits, thermal loading, reverse power flow, hosting capacity, short-circuit levels, protection coordination, power quality, and local observability. At the market level, resources must satisfy prequalification, telemetry, baseline, settlement, minimum-size, and availability requirements. At the governance level, coordination is required to avoid conflicts between local distribution-network needs and system-level balancing or ancillary-service activation.

The review shows that no single market or procurement pathway is suitable for all distributed-resource classes. Wholesale and intraday markets are mainly suited to portfolios capable of forecasting, scheduling, aggregation, and imbalance management. Retail and community pathways provide accessible entry points for small consumers, prosumers, photovoltaic systems, batteries, heat pumps, electric-vehicle charging, and flexible building loads, but their flexibility value depends on tariff design, automation, data access, and consumer engagement. Local flexibility procurement is particularly relevant for congestion management, voltage support, transformer-loading reduction, and reinforcement deferral, because the value of flexibility in this layer is intrinsically locational. Balancing and ancillary-service markets require faster response, stronger telemetry, stricter prequalification, and more reliable verification, making them more suitable for batteries, vehicle-to-grid fleets, aggregated demand response, and coordinated portfolios.

The participation-feasibility index introduced in the DSMG framework provides an analytical screening method for comparing distributed-resource portfolios across market and procurement pathways. By combining controllability, response-time compatibility, duration adequacy, locational relevance, telemetry readiness, baseline feasibility, aggregation scalability, and regulatory eligibility, the index translates qualitative mapping into a reproducible decision-support structure. The illustrative European portfolio comparison shows that photovoltaic-only portfolios have strong renewable-energy value but limited flexibility value when they are not combined with storage, curtailment strategies, advanced inverter control, or aggregation. Photovoltaic systems coupled with battery storage show higher compatibility across local flexibility and ancillary-service pathways because storage improves dispatchability, response time, and duration. Electric-vehicle smart charging and vehicle-to-grid fleets provide relevant flexibility potential, but their feasibility depends on user availability, connection time, battery-degradation management, aggregation, and regulatory eligibility. Flexible loads and heat pumps are promising for retail response and local congestion support, although their performance is constrained by baseline uncertainty, comfort limits, process requirements, and telemetry. Coordinated local portfolios, including combinations of generation, storage, electric vehicles, flexible demand, and energy-management systems, show the strongest multi-layer potential because they combine complementary resource characteristics and can interface with markets through aggregators, energy communities, microgrid controllers, or virtual power plants.

The synthesis also shows that increasing distributed-resource penetration is not sufficient to guarantee system value. The relevant transition is from passive distributed-resource deployment toward coordinated distributed flexibility. This requires resources that are observable, controllable, verifiable, cyber-secure, and capable of participating in market or procurement mechanisms without compromising local network operation. Hosting-capacity assessment, active and reactive power control, adaptive protection, feeder-level observability, smart metering, interoperable data exchange, baseline definition, and grid-safe activation procedures are therefore essential conditions for scalable participation.

The benefits of distributed-resource portfolios are multidimensional. They can support renewable-energy integration, reduce dependence on fossil-based generation, improve local resilience, defer grid reinforcement, reduce network losses, create new revenue streams, enable consumer and community participation, and provide flexibility for local and system-level services. However, these benefits are conditional. They depend on the ability to connect resource capability with appropriate service definitions, market access, locational qualification, aggregation, measurement and verification, and clear governance arrangements. Without these enabling conditions, technically promising resources may remain limited to self-consumption or pilot applications and may fail to deliver wider market and system value.

The main barriers identified in the review arise across resource, network, market, digital, regulatory, financial, social, and cybersecurity dimensions. Resource-level barriers include limited controllability, uncertain availability, short duration, degradation, and user constraints. Network-level barriers include voltage rise, congestion, reverse power flow, thermal limits, short-circuit variation, and protection miscoordination. Market-level barriers include minimum bid sizes, prequalification requirements, baseline uncertainty, settlement complexity, and limited revenue stacking. Governance barriers include unclear aggregator roles, heterogeneous national implementation, incomplete TSO–DSO coordination, and uncertain access of energy communities and local portfolios to external markets. Digital and cybersecurity barriers become increasingly important as flexibility provision relies on smart meters, inverters, batteries, electric vehicles, building controllers, aggregators, platforms, and communication networks.

The roadmap derived from the DSMG synthesis indicates that short-term action should focus on transparent aggregation rules, baseline and verification methods, improved smart-meter data access, hosting-capacity screening, and identification of constrained areas suitable for local flexibility procurement. Medium-term action should strengthen TSO–DSO coordination, grid-safe bid validation, harmonized local flexibility products, interoperable data exchange, flexibility registers, secure communication interfaces, and energy-community access to aggregation and local services. Long-term action should move toward integrated flexibility ecosystems based on dynamic operating envelopes, distributed energy resource management systems, digital twins, adaptive protection, cybersecurity-by-design, and coordinated multi-layer market participation.

Overall, distributed energy resources should be understood not only as decentralized generation or demand assets, but as potential flexibility portfolios whose value depends on their technical characteristics, network location, digital readiness, market eligibility, and governance environment. The DSMG framework provides a structured basis for comparing these participation pathways and for identifying the conditions under which renewable-based distributed resources can contribute to a reliable, flexible, inclusive, and decarbonized European electricity system.

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Supplementary material

The Supplementary Material for this article can be found online at: https://www.frontiersin.org/articles/10.3389/fenrg.2026.1832115/full#supplementary-material

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Glossary

ADMS Advanced distribution management system aFRR Automatic frequency restoration reserve AI Artificial intelligence API Application programming interface BESS Battery energy storage system BM Balancing market BMS Battery management system BRP Balance responsible party BSP Balancing service provider CEC Citizen energy community CHP Combined heat and power DAM Day-ahead market DCS Distributed control system DER Distributed energy resource DERMS Distributed energy resource management system DG Distributed generator DOE Dynamic operating envelope DR Demand response DRES Distributed renewable energy source DSM Demand-side management DSMG DER–Service–Market–Governance DSO Distribution system operator EC Energy community EES Electrical energy storage EMS Energy management system ENISA European union Agency for cybersecurity ESS Energy storage system EU European union EV Electric vehicle EVSE Electric vehicle supply equipment FCR Frequency containment reserve FERC Federal energy regulatory Commission FRR Frequency restoration reserve GHG Greenhouse Gas HC Hosting capacity HVAC Heating, ventilation, and air conditioning ICT Information and communication technology IDM Intraday market IoT Internet of Things LTTR Long-term transmission right M&V Measurement and verification M2M Machine-to-Machine mFRR Manual frequency restoration reserve MG Microgrid ML Machine learning NEMO Nominated electricity market operator P2P Peer-to-Peer PFI Participation-feasibility index PLC Programmable logic controller PV Photovoltaic REC Renewable energy community RED II Renewable energy Directive II RES Renewable energy source RET Renewable energy technology RTM Real-time market SCADA Supervisory control and data acquisition SDG Sustainable development goal SoC State of charge ToU Time-of-Use TSO Transmission system operator TSO–DSO Transmission-system-operator–distribution-system-operator coordination V2G Vehicle-to-Grid VPP Virtual power plant

Footnotes

Edited by: Qikun Chen, University of Surrey, United Kingdom

Reviewed by: M. Saber Eltohamy, Electronics Research Institute, Egypt

Elad Shaviv, Ben-Gurion University of the Negev, Israel