Demand response and demand-side flexibility are critical components of a cost-efficient and resilient electricity system. While demand response focuses on shifting or curtailing consumption at specific times, flexibility encompasses the broader capacity of the system to balance both generation and demand dynamically. The participation of prosumers, renewable energy communities, and aggregators enables decentralised resources to provide flexibility and system services traditionally delivered by centralised actors. Yet, regulatory and market frameworks have not always evolved at the same pace as these innovations. This chapter examines the regulatory barriers that hinder the effective deployment of demand-side flexibility and the integration of prosumers, communities, and aggregators. It identifies key obstacles to market access, data exchange, and fair remuneration, while showcasing emerging good practices that promote consumer participation, innovation, and competition in support of a flexible, decarbonised energy system. A self-diagnostic questionnaire helps policymakers assess the legal framework through the main barriers identified.
Diagnostic Toolkit for Reducing Regulatory Barriers to Solar, Wind and Pumped Hydro Storage in the European Union
Abstract
Prosumers and renewable energy communities are playing an increasingly important role in the energy transition. They can leverage private investments to scale up renewable energy (in particular PV solar, often decentralised) and enhance system flexibility (through batteries and other energy storage). By generating renewable electricity – also combined with storage – these actors can contribute to the reduction of electricity costs, grid resilience, more equitable access to low-cost, low-carbon electricity and enable new business models at different levels of the value chain. The full potential of prosumers and communities can be realised if their investments can be effectively aligned with the characteristics of the grid. This is a feature that may require specific network investments, especially when renewable shares increase. Further benefits can also arise from the coordination of generation and storage capacity by aggregators. While opportunities for net benefits are clear, their realisation can be constrained by regulatory uncertainty and limited access to enabling market mechanisms. Without targeted integration measures, decentralised production can also create local grid constraints, underscoring the need for forward-looking planning and regulatory reform at that level.
Demand response and demand-side flexibility are critical components of a cost-efficient and resilient electricity system. Whilst demand response (or DR) focuses on adjusting electricity use at different points in time, flexibility relates to the ability of the electricity system to adjust both generation and consumption. For the purposes of the following sections flexibility will often be used as shorthand for both concepts. Flexibility measures encourage producers and energy storage facilities to increase supplies, and consumers or energy storage facilities to adjust their consumption in response to real-time conditions – such as levels of low-cost, low-carbon electricity supply, levels of demand, system congestion, or price volatility – thereby supporting grid stability, reducing peak loads, and deferring costly infrastructure upgrades (see for example (ACER and CEER, 2024[1])(see Figure 6.1)
Note: Under EU law, individual consumers who adjust demand or generate electricity are defined as active customers
Source: OECD
This chapter addresses the evolving role of distributed energy resources and consumer participation in the European energy landscape as well as the regulatory barriers to their deployment. It begins by examining the potential of individual consumers – also known as active consumers – to directly manage their energy consumption and generation, contributing to grid flexibility and efficiency (Section 1). It then explores collective models of consumer participation, particularly energy communities, highlighting how they pool local resources and foster decentralised investments in renewable energy, storage, and enabling broader access to the benefits they can deliver (Section 2). Finally, the analysis considers the role of aggregators as intermediaries, enabling smaller individual and collective entities to participate effectively in wholesale markets by consolidating their capacity into commercially viable loads (Section 3). Together, these provide a structured overview of the barriers and opportunities for scaling distributed, consumer-driven flexibility in a competitive manner.
Rooftop solar has the potential to meet a substantial share of the EU’s electricity demand. A recent assessment by the JRC estimates that rooftop PV could generate up to 25% of current EU electricity consumption (Bódis et al., 2019[1]). Yet despite this technical potential, uptake remains uneven across Member States. Rooftop installations can be expected to form a primary entry point for many active customers.
Flexibility needs in Europe are expected to grow rapidly. By 2030, the EU electricity system will require more than double today’s flexibility resources to cope with variable renewable energy and changing consumption patterns. Compared to 2021, daily flexibility needs are projected to rise 2.4-fold, weekly needs by 1.8, and annual needs by 1.3. Looking ahead to 2050, flexibility demand is expected to triple, driven increasingly by the electrification of end uses (EEA/ACER, 2023[2]).
Net of impacts on net reductions of industrial production and final service demand reductions, which are clearly not desirable, the 2022 energy crisis highlighted latent demand-side potential. In response to extreme price signals, households and businesses across Europe reduced gas consumption by around 20% compared to previous years, helping stabilise electricity prices and avoid severe disruptions (EEA/ACER, 2023[2]). At the same time, negative electricity prices1 became increasingly common in early 2023, doubling in frequency compared to the previous year (IEA, 2024[3]).These may be exacerbated in the absence of effective price signals and consumer incentives contribute to increased flexibility through decentralised initiatives, as these can complement cost-effectively large-scale investments in grid capacity adjustments, including interconnections and energy storage.
Enabling consumer flexibility delivers tangible benefits. Demand-side flexibility allows consumers to adjust electricity use in response to market signals, reducing costs and sometimes generating new income streams. As electric vehicles, heat pumps, and rooftop solar installations become more widespread, they can offer growing contributions to the flexibility, helping to manage distribution grid constraints and avoid infrastructure bottlenecks.
Flexibility delivers system-wide benefits and enhances market efficiency. DR helps integrate variable renewables, balance supply and demand in real time, and reduce the need for costly grid upgrades by allowing DR to compete directly with generation in wholesale markets, systems can prioritise the lowest-cost option – reducing peak demand instead of activating expensive peaking plants (see for example (FLEXCoop, 2017[4])). Consumers contribute through both implicit responses – such as reacting to time-of-use or dynamic tariffs – and explicit responses by participating in demand response programmes via aggregators or directly in markets (ACER, 2023[5]). While offering savings to participants, DR also strengthens grid efficiency and resilience. Policy frameworks should reflect this dual role by aligning individual incentives with system needs.
Evidence shows demand response delivers high net benefits. Modelling for 2030 suggests that deploying 30 GW of demand response across Europe could yield savings nearly three times greater than the associated costs.2 These system savings would ultimately benefit all consumers, not just those directly participating in DR schemes.
Consumers and communities play a vital role in delivering flexibility. Prosumers and energy communities help localise production, raise awareness, and contribute new sources of investment and flexibility. When coordinated through aggregators, their distributed resources can also participate in electricity and balancing markets, transforming them from passive consumers into active market participants.
The transition to a flexible and decarbonised electricity system depends to a significant extent on the active participation of consumers. Under EU law, individual consumers who adjust demand or generate electricity are defined as active customers (also referred outside of the EU legal framework as “Prosumers”). These are consumers that not only use the generation they produce (self-generation) but also export surplus to the grid (see Figure 6.1)While large consumers that could shed load from the grid by being disconnected have been part of the electricity system for a long time, new opportunities from electric vehicles, heat pumps and decentralised electricity storage capacities (e.g. through batteries) indicate that their role is evolving, becoming more relevant as electricity use shifts toward heating, cooling, and transport, involving a larger number of small-scale electricity end users, and making demand flexibility both technically and economically viable.
Despite the growing need for demand-side flexibility, most consumers across the EU are not exposed to meaningful price signals. Over 70% of households remain on fixed-price contracts, and fewer than 10% have access to dynamic retail or network tariffs (ACER, 2025[6]). This limits the ability of active customers to shift demand in response to system conditions. Time-differentiated contracts – such as time-of-use, dynamic pricing, or hybrid models – can incentivise off-peak consumption and enhance system efficiency, especially when paired with cost-reflective network tariffs, as electricity costs for consumers may vary in real time reflecting fluctuations in market prices. However, many Member States have yet to implement these offerings at scale due to gaps in legal frameworks and delays in smart meter deployment (ACER, 2023[5]).
Active customers may generate, consume, store, or share renewable electricity individually or collectively, typically within clearly defined premises. Collective self-consumption is permitted in shared buildings, such as apartment complexes, while some Member States also recognise remote prosumers using off-site generation (CEER, 2025[7]). To expand participation, the revised Electricity Directive (2024) establishes a right to energy sharing within the same bidding zone or defined area. These arrangements – whether bilateral, community-based, or via peer-to-peer platforms – can enhance access to self-consumption and support demand-side flexibility.
6.2.1. Regulatory Barriers
(To undertake a self-assessment on Prosumers, see questionnaire in section 6.5)
Despite their potential, active customers face numerous regulatory barriers. These include disproportionate technical requirements, non-cost-reflective network charges (Yule-Bennett and Sunderland, 2022[8]), and lack of legal clarity about market participation (Florea et al., 2024[9]), especially for newer actors such as storage operators or EV owners (ACER, 2023[5]). In many cases, customers are also hindered by delays in grid connection and connection or metering costs, unclear rules on dual service provision (e.g. self-consumption plus flexibility), or the risk of double charging for storage (ACER, 2025[6]).
Regulatory uncertainty remains a key barrier to active customer participation. Active customers continue to face regulatory uncertainty and inconsistent treatment in electricity markets across many Member States. This lack of clarity regarding roles and rights impedes the ability of households (including in apartment buildings) and small businesses to fully leverage new technologies and business models, ultimately limiting their contribution to system flexibility and decarbonisation. National legal frameworks frequently lack provisions that secure the right of active customers to self-consume, to provide flexibility services, or to operate via aggregators (ACER, 2023[5]). This uncertainty limits participation, discourages innovation, and hampers investment in consumer-centric business models.
Energy storage is a key enabler of active customer flexibility but remains underused due to regulatory obstacles. Active customers with storage facilities may face double charges (for injection and withdrawal), unnecessary licensing requirements, or be prevented from providing multiple services simultaneously, even when technically feasible. The inability to connect to the grid within a reasonable timeframe, coupled with ambiguous rules on the financial responsibility for imbalances, further discourages active customer investment in storage solutions (ACER, 2025[6]). Addressing these issues is crucial to for customer uptake and unlock the full value of distributed energy resources.
Tariff design must evolve alongside legal rights to enable meaningful consumer participation. Dynamic and time-differentiated tariffs – for both energy and network use – are critical to support load shifting, integrate variable renewables, and enhance system efficiency. Yet, current regulatory frameworks and market structures in many Member States still favour fixed-price contracts and static tariffs over dynamic pricing models, limiting incentives for consumers to engage with demand-side flexibility (ACER and CEER, 2024[10]). To address this, regulators should expand the range of retail contract options, including dynamic pricing, time-of-use rates, and hybrid or incentive-based models, ensuring consumers are empowered to respond to system signals and benefit from greater flexibility.
The limited availability of real-time data and dynamic pricing signals. Without access to accurate consumption data or the ability to respond to fluctuating prices, consumers are unable to participate meaningfully in demand response programmes (ACER, 2025[6]).
Retail price interventions – such as price caps or subsidies – can also mute market signals and reduce incentives for flexibility. While these interventions may be motivated by social or affordability goals, they often mute the price signals that would otherwise encourage consumers to shift demand, invest in flexible technologies, or optimise their consumption patterns (ACER, 2023[5]). Policymakers should carefully assess the impact of such measures on participation in demand-side response and consider designs that target the public policy goals they wish to achieve carefully without creating new distortions or disincentives to flexible behaviour.
Rules that enable the voluntary adjustment of electricity consumption can also play a role. By allowing final customers to reduce or shift their consumption in exchange for compensation, these mechanisms can reduce grid congestion, especially at local level. To be effective, legal frameworks must clearly define participation rights, ensure non-discriminatory access, and establish adequate compensation provisions (see Box 6.1).
In 2022, the main Portuguese DSO E-REDES piloted a local flexibility market across eight zones. The initiative aimed to test the readiness of grid users to voluntarily adjust their electricity consumption or production in exchange for financial compensation. Participation was open to both large consumers and aggregators representing smaller users.
The first auction attracted 623 bids from 21 participants, mainly industrial users. Flexibility options that allowed for activation with one week’s notice were the most popular, suggesting that users prefer advance scheduling over short-notice adjustments. This pilot offers valuable insights into user behaviour and the practical design of local flexibility markets.
Renewable Energy Communities (RECs) are emerging part of the decentralised energy transition. RECs can be built around various technologies, including solar and wind, with wind generation – due to its broader temporal profile – offering potential for higher rates of self-consumption. They also encompass electricity storage (e.g, through batteries). By allowing citizens, SMEs, and public entities, including local municipalities to jointly generate, consume, store, and share renewable electricity, RECs enhance local resilience and contribute to system flexibility.3 They also contribute to the social acceptance of renewable deployment as they can lead to tangible benefits to members. Their distributed structure supports demand response and reduces grid congestion – key benefits as renewable penetration rises. Through local generation and active participation, RECs also foster energy security, grid stability, and public acceptance of clean energy infrastructure.
Yet despite their growing relevance, RECs remain underdeveloped in many Member States. Legal and regulatory barriers – such as unclear legal frameworks and restrictive definitions, and limited market participation – continue to hinder their expansion. Overcoming these challenges is essential to unlock the full system value of RECs. The following section identifies the key legal constraints.
6.3.1. Regulatory barriers
(To undertake a self-assessment on Renewable Energy Communities, see questionnaire in section 6.5)
Fragmented regulatory frameworks and unclear definitions hinder REC uptake. RECs face a distinct set of legal and procedural barriers that hinder their effective participation in electricity and flexibility markets (Rescoop, 2024[11]). In many jurisdictions, the absence of a comprehensive enabling framework – coupled with inconsistent definitions and restrictive eligibility criteria – creates uncertainty for investors, local actors, and system operators. According to a recent CEER survey of National Regulatory Authorities, the lack of clear legal frameworks and regulatory guidance was ranked among the top three barriers to energy community uptake (CEER, 2025[7]).
Legal uncertainty undermines inclusive participation and governance. Although EU legislation sets out minimum criteria for RECs, national-level definitions are often either overly narrow or inconsistently applied (Tatti et al., 2023[12]; Jacques Delors Institute, 2024[13]). In some cases, RECs are restricted to specific legal forms – such as cooperatives – or exclude actors like SMEs or local authorities (Rescoop, 2024[11]). Strict legal definitions may also exclude innovative or hybrid approaches, preventing more dynamic models from entering the market. Inconsistencies between Renewable and Citizen Energy Community definitions further exacerbate uncertainty. Even where enabling legislation exists, the absence of implementing rules – such as model statutes or procedural guidance – may create operational uncertainty, especially in jurisdictions with no tradition of this type of organisation.
Governance rules in many Member States remain overly prescriptive, limiting both the inclusiveness and flexibility of RECs. Participation may be constrained by voting restrictions based on shareholding, rigid board composition requirements, or rules that exclude certain actors – such as local authorities or SMEs – from membership (Rescoop, 2024[11]). These constraints can reduce the organisational diversity needed to tailor RECs to local contexts. Although RECs are not-for-profit by nature, overly strict limitations on surplus distribution may also discourage investment. National legal frameworks should clearly define the rights and responsibilities of members while supporting democratic oversight and enabling a range of governance models suited to different community sizes and structures.
Restrictions on activities and geographical scope limit scale and innovation. In several Member States, RECs are limited to a narrow set of activities – such as electricity generation only – excluding key functions like supply, storage, aggregation, or energy sharing (Rescoop, 2024[11]). These restrictions prevent RECs from evolving into fully integrated energy service providers. Legal caps on generation capacity may further constrain their ability to reach economies of scale, while narrowly interpreted proximity requirements restrict the geographical area in which they can operate. Such limitations reduce the cost-effectiveness and strategic potential of RECs. To fully unlock their contribution to local flexibility, Member States should enable RECs to operate across the energy value chain and not unduly limit its range of activities. Smart metering and virtual platforms are also helpful solutions for urban environments and apartment blocks, as they can allow participation to RECs without physical proximity of generation or storage. They can also facilitate the use of storage capacity available from electric vehicles, freeing up both individual and collective benefits.
Unequal market access and burdensome entry requirements persist. In many jurisdictions, RECs face difficulties accessing wholesale, balancing, or ancillary service markets. Community-generated electricity and/or storage capacity in batteries may be excluded from participation or subject to disproportionate prequalification and licensing requirements. National rules may fail to recognise the decentralised or aggregated nature of RECs, and its specific features and characteristics. To level the playing field, regulatory frameworks should provide for tailored, non-discriminatory market access, and accommodate shared and aggregated participation models.
Internal energy sharing remains poorly defined. In numerous Member States, RECs lack a clear right to share electricity internally among members (Rescoop, 2024[11]). Legal and regulatory frameworks often fail to specify how self-generated energy should be accounted for within the community, how network charges apply to shared energy, or how members’ entitlements as final customers are preserved. This limits the ability of RECs to optimise local generation and demand. Clarifying internal sharing rules – particularly in relation to grid use, taxation, and settlement procedures – is important to increase legal certainty for those wishing to start or join RECs.
Network charges can be discriminatory or economically disincentivising. RECs may be subject to charges that do not reflect their actual grid use. Internal energy transfers may be priced the same as long-distance transactions, ignoring the locational value and reduced system impact of local generation and consumption (Rescoop, 2024[11]). In some cases, communities face cumulative or double charges, undermining economic viability. Therefore, tariff methodologies should be transparent and ensure cost-reflectiveness and consistency with system needs. In countries such as Portugal and Belgium, targeted tariff exemptions or reductions for collective self-consumption and RECs have been introduced to reflect these benefits (Trinomics, 2024[14]).
Grid access and energy sharing remain procedurally complex. REC projects frequently face lengthy and opaque grid connection processes, often not tailored to its characteristics. These hurdles reduce project viability and inhibit broader flexibility contributions.
The rise of distributed renewable energy and digitalisation has enabled new business models, with energy aggregators emerging as an actor across both wholesale and retail electricity markets. Aggregators bundle distributed energy resources (DERs) – such as rooftop solar, batteries, electric vehicles, and flexible demand – into a single portfolio capable of participating in energy markets. This model bridges the gap between small-scale participants and formal market structures, enabling access that would otherwise be restricted by scale or complexity. Aggregators can optimise and dispatch these assets in real time, offering services traditionally reserved for large, centralised power plants and that may struggle to become available from distributed market players, due to price signals that risk being too small, without aggregation, to mobilise demand responses. Aggregators therefore play an important role in helping to unlock consumer flexibility, supporting energy communities, and integrating small-scale generation into formal electricity markets.
Beyond market access, aggregators can coordinate and optimise DER flexibility across a range of system participants. These include Transmission System Operators (TSOs), Distribution System Operators (DSOs), Balancing Responsible Parties (BRPs), and active customers. By aggregating small-scale resources, notwithstanding the need to guarantee compensation to the owners of the assets that they pool together, they can seize value from a range of services, such as congestion management, as well as balancing, and other ancillary services to system operators (see for example example (M. Otte, J. Kamsamrong and S. Lehnhof, 2024[15])). Aggregators can take several forms, such as supplier affiliated models and BRP hybrids to independent third-party providers. At the retail level, aggregators may also support peer-to-peer energy trading platforms, facilitate community-based supply models, and help customers optimise self-consumption and manage behind-the-meter resources. In doing so, and while sharing benefits, they can offer innovative business models that drive consumer participation and support more decentralised, resilient and flexible electricity systems.
6.4.1. Regulatory Barriers
(To undertake a self-assessment on Energy Aggregators, see questionnaire in section 6.5)
A key barrier to the expansion of energy aggregation services is the continued absence of clear, consistent, and non-discriminatory legal frameworks. Although EU legislation such as the Electricity Directive recognise the role of aggregators, national legislation frequently lacks sufficient detail on their rights to market participation, data access, and interactions with customers (ACER and CEER, 2024[10]). This legal uncertainty deters investment and hampers the emergence of new market players (ACER, 2025[6]).
Aggregators often operate under restrictive conditions. Some Member States require supplier consent or limit aggregator access to final customers, particularly in cases involving independent aggregators. These constraints restrict market entry and competition. Further, in order to operate effectively aggregators, require timely access to relevant data (e.g. metering and consumption data). While data access transparency, informed consent, and privacy protections are important, lack of access to data limits the ability of aggregators to provide services or interact with system operators or customers is hindered (ACER, 2025[6]). The establishment of rules for aggregator transparency, codes of conduct and standardised contracts could help bridge barriers while ensuring consumer protection.
Additional regulatory barriers include the absence of cost-reflective compensation mechanisms (for both aggregators and consumers), unclear technical participation requirements, and lack of dedicated and clear dispute resolution procedures. In several Member States, TSOs continue to rely on non-market-based methods or fail to remunerate flexibility providers adequately. These practices deter aggregator participation. In parallel, dedicated dispute resolution mechanisms – overseen by independent regulatory authorities – can help resolve any conflicts efficiently and affordably.
The lack of well-defined aggregation models and standardised settlement procedures adds to the uncertainty faced by aggregators. Without clear methodologies for baseline calculation, performance assessment, or compensation, aggregators are potentially exposed to inconsistent treatment and financial risk – particularly in balancing markets or participating in wholesale markets (ACER, 2025[6]). This regulatory ambiguity prevents aggregators from forecasting revenues and managing risk as well as heightening the possibility of inconsistent treatment and unresolved disputes with suppliers or BRPs. To address this, Member States should adopt clear baseline methodologies, cost-reflective settlement principles, and adequate financial transfer mechanisms.4
Access to balancing and ancillary service markets may be constrained by procurement practices that exclude distributed resources from competitive tenders. These restrictions distort price signals, inhibit renewable integration, and limit cost efficiency. A shift toward fully market-based procurement for system services – open to all eligible providers5 – can help ensure competition, stimulating innovation, and reducing grid management costs.
Finally, excessive and disproportionate prequalification and administrative procedures can hinder the participation of smaller aggregators and distributed assets. Licensing processes can be lengthy, capacity thresholds and financial guarantees unnecessarily high and with burdensome testing requirements (ACER, 2025[6]). In some Member States, prequalification must be repeated at the unit level – even after minor adjustments – leading to duplication and inefficiency. To improve accessibility and scalability, Member States should adopt risk-based and proportionate administrative requirements, which can help reduce transaction costs while safeguarding grid reliability.
Unlocking the full potential of energy aggregators requires clear, proportionate, and technology-neutral regulation. As the energy system decentralises and flexibility becomes more valuable, aggregators can serve as vital enablers of system efficiency and consumer participation. Removing entry barriers – through standardised rules, market-based procurement, streamlined administrative processes, and cost-reflective compensation – will be essential to support innovation, attract new actors, and ensure that distributed resources contribute meaningfully to energy transition goals.
6.5.1. Instructions for use
The self-diagnostic questionnaire is designed as a practical tool for policymakers to assess the regulatory and administrative conditions affecting renewable energy deployment. Each question or set of questions targets a specific barrier identified – such as permitting delays, grid connection, and asks whether a legal or regulatory obligation exists to address it. Responses are scored on a simple 0–1 scale, with 0 representing best practice (clear legal obligation enabling efficient deployment) and 1 representing the most burdensome conditions (no enabling framework). This structure allows policymakers to systematically identify gaps, benchmark performance, and prioritise reforms based on areas where national, regional or local rules fall short of good practice.
The questionnaire is divided between questions relevant to national and sub-national authorities. In jurisdictions where energy, environmental, or planning powers are decentralised, certain national-level questions should be completed by the relevant regional or devolved authority. Sub-national questions are further distinguished between regional and local levels, depending on how permitting and infrastructure responsibilities are distributed within the Member State. Policymakers at all levels should consult internal legal frameworks to determine which authority is competent to answer each question and ensure coordination where competencies overlap.
Scoring
The questions in this section are meant to enable two types of scores:
A. A score specific to a barrier within a market segment (technology): a market segment/barrier-specific score. An example is a score for permitting for PHS; and
B. A score specific to a market segment, hence including all barriers for that specific market segment: a market segment‑specific score. An example is utility-scale solar PV. A market segment/barrier-specific score forms part of the technology-specific score.
A. Market segment/barrier-specific score
This score determines the importance of a barrier for this technology. The score can be determined through the following steps:
i. Select a barrier within a market segment for analysis
ii. Score each relevant question for that aspect of the analysis (at the relevant level of government). For this scoring, one designates a score between 0 and 1.
Please note, for a scoring of the barrier Spatial planning and permitting, one needs to score the questions in this section (excluding for this market segment the questions for “permitting for small installations”), and for grid connection and flexibility, one needs to score the questions in this section.
iii. Add up the scores for each question to obtain the Market segment/barrier total score: Market segment/barrier total score = Sum(all individual questions for that barrier)
iv. Scale the Market segment/barrier total score to arrive at a (weighted) Market segment/barrier score, namely a score between 0 and 6 (see Annex C):
Market segment/barrier score =
(Market segment/barrier total score) x
B. Market segment-specific score
The next step is to combine the (Weighted) Market segment/barrier scores to arrive at a Market segment-specific score. The score can be determined by adding up the Market segment/barrier scores and divide them by the number of barriers:
Market segment-specific score =
Questions
References
[6] ACER (2025), Unlocking flexibility: No-regret actions to remove barriers to demand response 2025 Monitoring Report.
[5] ACER (2023), Demand response and other distributed energy resources: what barriers are holding them back? 2023 Market Monitoring Report.
[1] ACER and CEER (2024), Position on anticipatory investments.
[10] ACER and CEER (2024), Energy retail - Active consumer participation is key to driving the energy transition: how can it happen? 2024 Market Monitoring Report.
[7] CEER (2025), Regulatory and Consumer Considerations for Decentralised Energy Opportunities.
[2] EEA/ACER (2023), Flexibility solutions to support a decarbonised and secure EU electricity system.
[4] FLEXCoop (2017), Democratizing energy markets through the introduction of innovative flexibility-based demand response tools and novel business and market models for energy cooperatives, https://doi.org/10.3030/773909.
[9] Florea, A. et al. (2024), “Prosumer networks – A key enabler of control over renewable energy resources”, Renewable Energy Focus, Vol. 51, p. 100648, https://doi.org/10.1016/j.ref.2024.100648.
[3] IEA (2024), “Renewable Energy Market Update Outlook for 2023 and 2024”.
[13] Jacques Delors Institute (2024), “Fleshing out energy community legislation in EU Member states for a fair energy transition”.
[15] M. Otte, J. Kamsamrong and S. Lehnhof (2024), “Aggregators in Digitalised Power Systems How can Aggregators Improve the TSO-DSO-Customer Coordination in Digitalised Power Systems?”.
[11] Rescoop (2024), Energy communities repository barriers and action drivers for the development of different activities by renewable and citizen energy communities.
[12] Tatti, A. et al. (2023), “The Emerging Trends of Renewable Energy Communities’ Development in Italy”, Sustainability, Vol. 15/8, p. 6792, https://doi.org/10.3390/su15086792.
[14] Trinomics (2024), Analysis of barriers for innovative forms of solar PV deployment and associated recommendations Final Report.
[8] Yule-Bennett, S. and L. Sunderland (2022), “The joy of flex: Embracing household demand-side flexibility as a power system resource for Europe”.
← 1. These events typically occur when renewable generation – such as solar and wind – exceeds demand, often during summer afternoons with high solar output and strong wind conditions.
← 2. See Compass Lexecon study Quantifying the Benefits of Demand Response – DR4EU .
← 3. RECs, as defined under EU law, are distinct from Citizen Energy Communities (CECs) in that they must focus primarily on renewable sources and are often more geographically constrained. This report focuses exclusively on RECs.
← 4. The forthcoming Network Code on Demand Response and ACER’s recommendations provide guidance on these issues.
← 5. This is required by the Electricity Balancing Regulation 2017/2195 of 23 November 2017.