This chapter examines the critical role of electricity grids in enabling electrification and the integration of renewable energy. It outlines the structure of Europe’s transmission and distribution systems and identifies barriers that constrain both grid expansion and optimisation. Key challenges include planning and siting delays, regulatory and financing disincentives, and limited digitalisation and flexibility procurement. The chapter highlights the importance of anticipatory investment, non-wires alternatives, transparent locational signals, and data-driven congestion management to ensure efficient and timely grid development. It provides a framework for assessing regulatory and operational measures that can enhance flexibility, optimise capacity, and align network planning with system needs. 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
Electricity grids serve as the backbone of energy transmission and distribution, playing a crucial role in integrating both growing electrification across sectors and increasing shares of renewable energy. As electrification expands across sectors, grid capacity must keep pace to avoid becoming a bottleneck.
This chapter explores the issue of grids, which is crucial as it across electricity generation technologies. It assesses the critical role for grids in the increased electrification, and the impact it has on renewable energy deployment (Section 11.1). It then provides an explanation of the grid architecture (Section 11.2). Finally, it focuses on regulatory barriers to grid capacity expansion (Section 11.3), to existing grid capacities optimisation (Section 11.4) and to efficient grid connections (Section 11.5).
11.1.1. The trend towards electrification and the role for renewables
While electricity demand had decreased in the EU in the last few years, an increasing trend is expected, with significant implications for grid infrastructure needs. This decrease was observed in 2022 and 2023 1, extending a declining trend that is more than a decade-long. At global level demand rose by 4.3% in 2024 (IEA, 2025[1]). This growth marked an increase in average annual electricity demand growth of 2.7% recorded between 2010 and 2023, a rate already twice as high as overall energy demand growth during the same timeframe. The coming years are expected to witness an increasing trend in Europe, the IEA expecting electricity demand to increase by 2.4% per year on average between 2024-26 (IEA, 2024[2]). An uptick in electricity demand of 1% has already been observed between 2023 and 2024 (EMBER, 2025[3]).
Current projections indicate that electricity's role in final energy consumption will experience a significant expansion by 2040. Estimates consider that electricity is expected to grow from current 25% and account for a 50% share of final energy demand by 2040 (European Commission, 2024[4]). Between 1990 and 2020, peak electricity2 demand increased by 25%, and this is projected to rise by a further 60% by 2050 (see Figure 11.1). This in line with growing electricity demand until 2050, combined with the emergence of a summer peak (especially in Southern Europe) due to significant increases in cooling demand. It may also reflect other changes in consumption patterns, an increase of distributed, behind-the-meter, solar electricity generation capacity and, possibly, some impacts from unmanaged forms of new electricity demand, such as from data centres and EV charging.
Note: This figure is taken from (Eurelectric, 2024[5]).
Source: European Network of Transmission System Operators for Electricity (ENTSO-E); Eurelectric Decarbonisation Speedways
According to the analysis developed for the EU 2040 climate target, EU's electricity needs are expected to be met from wind and solar generation. This will lead to an expected increase from 570 GW of installed capacity in 2024 (EMBER, 2025[3]) to 1,200 GW by 2030 and more than 2,500 by 2040 (European Commission, 2024[6]). This has also implication for grid layout, given the different needs and characteristics of these generation technologies – including lower capacity factors and locations not necessarily aligning with excess capacity in the existing network – as compared to conventional generation (fossil fuels, nuclear or hydro).
11.1.2. Renewable energy's distinct grid requirements
Solar and wind energy have distinct characteristics to traditional energy sources, with implications for grid requirements. They depend largely on natural conditions rather than market signals or dispatchable control, resulting in variable output. 3 This reliance on natural conditions means that grid management and market mechanisms need adjustments to effectively accommodate renewable energy production patterns, which are inherently weather-dependent and less controllable compared to conventional energy sources.
Renewable energy production predominantly occurs in locations where wind or sun are abundant, which may be far away from major consumption centres. Such production sites are also made up of many units, of different capacities (Davis, Hausman and Rose, 2023[7]). Additionally, the variable nature of solar and wind power, dependent on weather conditions and time of day, requires flexibility solutions, including grids that are capable of dynamically balancing energy supply and demand to maintain system stability and reliability. Further, while grids were designed for stable alternating current from conventional sources, solar PV generates direct current and wind turbines generate variable frequency alternative current, meaning that both require conversion.
The distributed type of generation from solar and wind capacity necessitates significant grid developments, unless generation occurs next to existing spare capacity and close to consumption centres. Smart grid optimisation, as well as batteries and other electricity storage options – such as pumped hydro – are also needed to manage decentralised, variable energy flows. Such power systems are quite different from the conventional power system with significant implications for the grid (see Figure 11.2).
Source: (IRENA, 2019[8])
Interconnecting diverse geographical regions can enhance grid flexibility and optimise energy availability. By linking different time zones and weather patterns, the grid can better match supply with demand – for example, using late afternoon solar power from one region to meet peak demand in another area (Joskow, 2023[9]). A robust transmission network connecting geographically dispersed renewable energy sources across Europe enhances reliability through diversification of supply (López Prol et al., 2024[10]). It can also optimise energy production, reduce curtailment, bring down negative wholesale prices as well as energy storage needs, and improve the overall resilience and efficiency of the electricity system (Davis, Hausman and Rose, 2023[7]). The extent to which this requires interconnection agreements across Member States is not the focus of this chapter or of this Report. At the same time, investments in distribution grids are also pre-requisites to enable the conditions that require transmission investments, as they enable the connection of renewable electricity generation to the grid.
11.1.3. Current status & ageing infrastructure
Electricity transmission networks in the EU in 2021 span nearly 500 000 km of transmission lines and approximately 10 million km of distribution lines. More than 25,000 km of new transmission lines were planned in 2024 by 2026, bringing the cumulative length of national transmission grids to approximately 523 000 km (Cremona and Rosslowe, 2024[11]). However, differences between Member States are significant, both in terms of current network length and planned extensions (see Figure 11.3). By 2050, transmission grid length is expected to double, reaching nearly 1 million km, while distribution grids will expand by 30% to around 13 million km (Joint Research Centre, 2024[12]). Moreover, 7 million km of existing grid lines, including 300,000 km of transmission infrastructure, will need to be replaced. Some industry estimates suggest that the increase in network extension could be faster, with 800 000 km of new transmission lines (rather than 500 000 km) and 17 million km of new distribution lines (rather than 3 million) needed by 2050 (CurrENT, 2024[13]).
Source: (Cremona and Rosslowe, 2024[11])
Many EU electricity grids are decades old. Electricity grids in Europe typically feature ageing infrastructure, largely from early electrification, with some components having been operational for over five decades. More than half of the electricity grid is already over 20 years old, approaching roughly half of its expected lifespan (IEA, 2023[14]). For distribution grids, some estimates note that 30% of today’s grid in the EU and Norway, combined, is more than 40 years old on average, with some assets significantly older (European Commission, 2023[15]; Eurelectric, 2024[5]). For transmission grids, advanced economies have a higher average age of grid infrastructure compared to emerging markets and developing economies (IEA, 2025[16]).
Further, grids need to be updated to current conditions. In addition to the need for conversion to stable AC-based infrastructure for solar and wind electricity, already discussed above at paragraph 0, grids also need to be adapted to climate change. This includes the usage of more durable materials and installing flood-resistant substations to safeguard infrastructure from extreme weather conditions and rising water levels. Without adaptation, available estimates for the EU point to a tripling of the cost of damages to critical infrastructure (including energy generation plants, transport systems, industry, water supply networks, and education and health infrastructure) due to climate change in the period 2011 to 2040 and a six-fold increase by 2040-71, and over ten-fold by century’s end, with respect to a 1980-2010 baseline (2071-2100) (Forzieri et al., 2018[17]).
The regulatory infrastructure in many countries needs to adapt to electrification. In many countries, regulatory frameworks have prioritised marginal expenditures for cost optimisation of existing assets over more profound investments allowing to fully leverage the benefits of large-scale electrification (IEA, 2024[18]). Moreover, permitting and regulatory processes lead to long lead times and are not adapted to distributed production and large scale expected increase in electrification demand.
11.1.4. Consequences of insufficient grid capacity
Electrification and renewable projects risk being stalled due to grid connection constraints. A lack of sufficient grid capacity to connect new projects swiftly, and, in some areas, grid congestion, can lead to bottlenecks preventing the acceptance of new capacity. At least 3 000 GW of renewable power projects globally – 1 500 GW of which in advanced development (i.e. with a connection agreement in place or under active review) – were identified as waiting in queues in 2023 (IEA, 2023[14]).4 In the EU, 500 GW are in construction or pre-construction, based on the data gathered in the OECD database, with almost 200 in Spain and Italy alone. In the Netherlands, which has been amongst the top EU countries for both solar and wind capacity installations per unit land area, most grids are considered congested, with long waiting lists for connections, suggesting that anticipatory grid investments to avoid capacity constraints can play an important role to remove upcoming risks of bottlenecks In 2024, the backlog amounted to approximately 10 000 large consumers or battery projects and 7 500 large-scale generation projects awaiting connection in the Netherlands, with a waiting list that continued to grow (IEA, 2024[19]).
Grid expansion risks lagging behind the rapid growth of renewable energy deployment and electrification across the EU. The mismatch between the significant increase of renewable electricity supply projects, related connection requests and the comparatively slow pace of grid reinforcements has already led to an increase in connection delays. This is estimated to continue to grow and has led to suggestions of non-firm connections as interim (and in some cases permanent) solutions (CEER, 2023[20]).
Congestion leads to curtailment on zero marginal cost generation. The financial and economic impact of congestion in the transmission grid is already significant. In 2023, transmission grid congestion management5 cost EUR 4 billion (ACER, 2024[21]) an amount equivalent to investing in 4.51 GW of new PV solar capacity (IEA, 2023[14]). More than 12 TWh of electricity from renewable electricity was curtailed in 2023, leading to the reliance on more expensive and carbon-intensive back-up generation (ACER, 2024[21]) (IEA, 2023[14]).67 Moreover, power outages from inadequate capacity cost the European economy €50 billion in 2021 (Eurelectric, 2024[5]). By 2030, grid constraints could prevent the deployment of 205 GW of solar and 31 GW of wind energy deployment. Some forecasts suggest that this could prevent the connection of 1 220 GW of distributed renewables and 240 TWh of industrial electrification not undertaken by 2050 in the EU, equivalent to 32‑37% of required CO2 emission reductions (Eurelectric, 2024[5]).
Failure to expand and modernise grids in line with increasing electrification and growing renewable generation risks exacerbating this bottleneck. A failure to anticipate transmission and distribution grid expansion needs and align infrastructure planning is already leading to persistent grid constraints in the EU. These constraints lead to increasing curtailment of renewable energy sources and limit opportunities to reduce electricity costs across the EU. Grid expansion, optimisation and enhanced management systems are essential to enable better and more equitable access to low-cost electricity in the EU, especially in a context that will see increased deployment of renewable electricity capacity and where electricity demand is projected to grow. Investments to strengthen the EU network can favour access to optimal renewable generation sites, manage intermittency, maintain system reliability in a decarbonised energy system, while also delivering cost-effectively additional energy security benefits.
11.1.5. Investment needs & infrastructure expansion
The significant shift toward renewables and increased electrification requires increased grid capacity. This can be underpinned not only through the construction of new grids, but also with energy storage (batteries), energy efficiency enhancements and with innovative grid technologies based on digitally-enabled network controls and management. Equally important is improving the efficiency of existing networks through greater demand and supply-side flexibility (IEA, 2024[19]). These can help avoid unnecessary infrastructure expansion, reduce overall system costs, and limit upward pressure on electricity prices. This means a mix of expanding grids, including establishing new interconnections, and upgrading to smarter and flexible grid solutions, especially for distribution networks. Therefore, before undertaking major investments in grid capacity, a careful assessment of the most cost-effective options available is important.
Increasing capacity of existing grids requires new infrastructure. Estimates by the European Commission and industry point to 500 000 to 800 000 km of new transmission lines and 13 to 17 million km of new distribution lines needed by 2050 (CurrENT, 2024[13]). Investment needs for European distribution grids are estimated at EUR 67 billion per year until 2050 (Eurelectric, 2024[5]).8 A recent analysis carried out in the framework of a study commissioned by the European Commission estimated investment needs for electricity infrastructure categories until 2040 amounting to over 76 billion per year (European Commission: Directorate-General for Energy, Artelys, LBST, Trinomics, Finesso, A. et al., 2025[22]).
Enhancing the capacity of existing grids can also be achieved through a range of innovative measures, offering faster and more cost-effective solutions than building new lines. Techniques such as reconductoring (retrofitting existing power lines with higher capacity conductors to allow greater power flows), voltage uprating (increasing the voltage level to raise the capacity in the existing grid), dynamic line rating (DLR, monitoring and optimising how much electricity can flow through power lines), and advanced network operation practices, such as the dynamic control power flows, can improve grid efficiency (Kvarnström et al., 2025[23]), complementing and also offering alternatives to the use of stationary storage (see also Section 11.4. below)9
Grid usage and capacity also need to be optimised. Alongside new or upgraded grids, equally crucial is optimising the efficiency of existing infrastructure. Advancements in technology enable the expansion of virtual grid capacity through smart grids and the seamless integration of many distributed energy, real-time dynamic line rating and battery storage resources. To make grids more responsive and smarter, for example for managing congestion in distribution grids, this requires location-specific solutions enabled by high levels of digitalisation (IEA, 2023[14]). These innovations can alleviate some of the pressure for new grid construction by enhancing system flexibility and efficiency and reduce reliance on stationary batteries.
A critical, often overlooked, consequence of current grid limitations is their impact on the development of new system services. To meet emerging needs such as greater balancing and congestion management, the system requires new tools – including platforms that aggregate flexibility from distributed resources. However, providers of these services must secure financing to develop and operate such tools. Financing becomes difficult if investors and lenders perceive high uncertainty over the viability of these services. In such cases, the lack of access or predictable operating conditions can render business models financially non-viable. Consequently, insufficient grid capacity does not only constrain renewable energy deployment but may also become a significant barrier to the emergence of innovative services critical for the future flexibility and resilience of the energy system.
Grid expansion into new areas and the reinforcement of existing networks require distinct strategic approaches. Expanding grids into new geographies, particularly offshore, requires long-term planning and proactive investment. In contrast, increasing the capacity of existing grids should be guided by system cost minimisation, leveraging an optimal mix of traditional grid reinforcement and innovative non-wire solutions.10
All these factors mean that grids will need to be better utilised, expanded, renewed and innovative solutions be deployed in the following years, requiring significant investments. The IEA estimates that the global grid investments should nearly double by 2030 to over USD 600 billion per year (IEA, 2023[14]). In the EU, an estimated EUR 584 billion in investments in grids is necessary by 2030 (European Commission, 2023[15]). A recent study (C. Heussaff and G. Zachmann, 2025[24]), estimates total annual investment needs across Europe up to 2030 between EUR 65 billion to EUR 100 billion. A very significant part of these investments will be at the distribution level (C. Heussaff and G. Zachmann, 2025[24]). A recent study commissioned by the Commission also estimates investment needs for electricity infrastructure to enable a decarbonised economy to almost EU 1220 billion between 2024 and 2040 – i.e. EUR 76.25 billion per year (European Commission: Directorate-General for Energy, Artelys, LBST, Trinomics, Finesso, A. et al., 2025[22]).
11.1.6. Strategic actions for grid modernisation
The expansion and modernisation of the grid require action across three key areas. First, new grid connections must be developed, including (i) transmission corridors to integrate wind and solar projects located in resource-rich but remote areas and (ii) new distribution infrastructure to accommodate new generation assets (including from prosumption profiles) and increasing loads from industrial electrification, including electrolysers for green hydrogen production for cases that cannot directly electrify cost-effectively, for electric transport (including long-haul) and for the electrification of heating (including district heating). Second, ageing grid assets must be replaced if degradation compromises safety, reliability, or efficiency or when maintenance costs outweigh the benefits of the prioritisation of more targeted interventions, such as refurbishments, upgrades, or component replacements. Third, system reinforcements are critical to enhance grid flexibility and resilience, including structural upgrades to enable bidirectional power flows in distribution networks and the deployment of digital tools such as sensors and advanced software to manage increasingly complex power flows (Energy Transitions Commission, 2024[25]).
As expanding grid infrastructure takes time, investment planning plays an important role. New grid infrastructure typically requires between five and fifteen years for planning, permitting, and construction (IEA, 2023[14]). Lead times for grid projects are longer than those for renewable energy developments – distribution grids can take up to 10 years, while transmission grid project can take up to 17 years (European Commission, 2025[26]) (see Figure 11.4 below). This mismatch in development timelines means that grid investment planning plays an important role.
Note: This is sourced from European Court of Auditors and based on data from the Commission as well as replies from 12 NRAs and the IEA.
How regulation can impact investment in the grid will be the focus of this chapter. This chapter is organised as follows:
Section 2 examines the evolving architecture of electricity grids and how it must adapt to decentralisation and the growing share of renewable energy.
Section 3 analyses regulatory barriers to grid expansion, with a focus on permitting procedures and the absence of clear anticipatory investment rules.
Section 4 discusses barriers to optimising existing grid capacities, including rules on grid mapping, flexible connection agreements, and grid digitalisation.
Section 5 addresses challenges in grid connection management and how improved coordination can facilitate faster, more predictable access for new projects.
Section 6 presents a self-diagnostic questionnaire with instructions for use, designed to help policymakers and regulators assess the main barriers within their national grid frameworks.
The electrical grid operates on distinct voltage levels managed by different entities. This architecture is divided into two primary systems: high-voltage networks managed by Transmission System Operators (TSOs) and medium- to low-voltage networks overseen by Distribution System Operators (DSOs). TSOs oversee the backbone of power transmission, handling grids that transport power over long distances, both national and cross-border. In contrast, DSOs manage medium and low-voltage systems that deliver electricity to end users.11 This division of responsibilities reflects the distinct infrastructural, technical and operational requirements and challenges associated with each voltage level, enabling a co‑ordinated approach to grid planning and management (see Figure 1.5). Whilst at national level electricity transmission infrastructure planning is typically undertaken by TSOs with National Regulatory Authorities (NRAs) and or ministries, at local level distribution infrastructure is built and maintained by DSOs, with some countries having one DSO and others having several hundred of various sizes (ACER, 2024[28]).
Source: (Cremona and Rosslowe, 2024[11])
Transmission System Operators (TSOs) face increasing complexity in managing high-voltage networks as renewable integration accelerates. Their role extends beyond traditional bulk power transmission to include cross-border power flows, integrating a diverse set of electricity generation sources, and system-wide balancing across geographic areas (Cremona and Rosslowe, 2024[11]). TSOs must co-ordinate large renewable energy flows across regions while ensuring grid stability, managing congestion, and facilitating efficient market operations through enhanced interconnection capacity and advanced control systems. This requires significant investment in both infrastructure and digital capabilities to maintain system reliability.
Distribution grids and DSOs are evolving from passive power delivery systems into active platforms that enable two-way power flows. These grids must now accommodate distributed energy resources like rooftop solar, electric vehicle charging, as well as energy storage and demand response while maintaining voltage stability and power quality. The move towards smaller-scale, distributed generation has increased the complexity and requires upgrades to both physical infrastructure and control systems, with smart meters, sensors, and automation and data management technology becoming essential components for effective network management (Eurelectric, 2024[5]; GEODE, 2023[29]).12 For example, in Wallonia (Belgium), the DSO Ores plans to deploy approximately 9 000 km of low- and medium-voltage cables, construct 3 500 electrical substations, and install 1.3 million smart meters over the next five years (Pató, Claeys and Morawiecka, 2024[30]). This modernisation is critical for enabling local energy markets, demand response programs, and efficient integration of renewable resources at the community level.
Furthermore, both TSOs and DSOs face expanding responsibilities in grid management which requires greater co-operation between them. They must act as neutral market facilitators ensuring fair grid access and data sharing. The increasing penetration of renewable energy adds complexity to these duties, requiring more sophisticated approaches to grid management and market coordination between transmission and distribution levels.13
11.3.1. Permitting
(To undertake a self-assessment on permitting, see questionnaire in section 11.6).
Permitting is a critical step in the development of grid infrastructure, requiring a wide range of authorisations from relevant authorities at local, regional and national levels. Grid infrastructure projects may be subject to several procedures which include environmental assessments, land-use authorisations and safety-related approvals, all of which can vary in complexity depending on jurisdiction and project scale. While the permitting phase is initiated by the project promoter, it requires them to develop an environmental impact assessment and it requires the process itself is largely driven by environmental and permitting authorities operating under national and local procedures to decide upon the assessments. Legal appeals may extend timelines further. The permitting phase is lengthy. It has been assessed to last more than five years for transmission lines (ACER, 2024[28])14 and, and, despite improvements in the recent past, bringing estimates down to 2 to 3 years, it still takes approximately a quarter of the time required for the grid investment (European Court of Auditors, 2025[27]). Specifically, for DSOs, permitting approvals for medium-voltage grid reinforcements can take two to three years, while high-voltage lines and substations face delays of up to eight to ten years, slowing the integration of new renewable capacity and exacerbating grid congestion (DSO Entity, 2025[31]).
Permitting is still considered one of the main obstacles to grid deployment. Grid permitting is widely recognised as one of the main barriers for grid expansion (European Commission, 2023[15]). Permitting procedures and land-use requirements are often complex and regulatory interpretations can be inconsistent (see for example (ACER and CEER, 2024[32]) (European Court of Auditors, 2025[27])). The complexity of permitting is evident in cases like Germany’s 340 km Ultranet DC line, which requires approximately 13 500 permits (IEA, 2023[14]).
They also often involve multiple authorities with differing and sometimes overlapping responsibilities at national, regional and local levels. National regulatory frameworks across Europe exhibit considerable diversity, characterised by the involvement of various authorities at different administrative levels, including national, regional, and local bodies. This often involves limited co-ordination between them (European Court of Auditors, 2025[27]) (DSO Entity, 2025[31]). Specific requirements linked to infrastructure such as public roads and railways may exist, for instance with distinct procedures and timelines and uncertainties in permitting processes (DSO Entity, 2024[33]). Simplifying these processes is essential to facilitate the timely connection of new renewable installations to the distribution grid (see Box 11.1).
The example of the Netherlands
In response to growing challenges in grid congestion, the Netherlands launched the National Action Programme on Grid Congestion in December 2022. Developed collaboratively with DSOs and TenneT (the national TSO) as well as with extensive stakeholder consultations, the programme outlines a comprehensive set of actions aimed at accelerating grid expansions and enhancing grid utilisation.
The Ministry of Economic Affairs and Climate Policy, along with provincial governments, oversees the implementation of this programme. Dedicated working groups, comprising network operators, network users, central government representatives, provincial authorities, and the regulator, have been established for each goal to ensure co-ordinated efforts and effective execution.
Every six months, TenneT, the national transmission system operator, publishes a progress report outlining acceleration measures for national grid projects. Additionally, a pilot project led by TenneT explores the proactive construction of new grid infrastructure before final permits are granted, aiming to reduce delays and improve network capacity.
Source: (IEA, 2024[19])
DSOs face significant administrative complexity due to fragmented responsibilities across national, regional, and local permitting authorities. The DSO Entity’s 2022 survey highlights overlapping procedures and unclear points of contact, which hinder timely permitting. DSOs are typically required to obtain multiple building permits across various jurisdictions for smaller-scale infrastructure, further exacerbating delays. This fragmented approach increases procedural burdens and slows the connection of renewable energy sources to the grid (DSO Entity, 2025[31]).
The positive effects of recent permitting reforms can be discerned in those EU Member States actively employing emergency rules. For instance, in Germany the implementation of accelerated permitting procedures during the energy crisis significantly increased the pace of approval of grids - about 3,300 kilometres of transmission grids received approval from Q2 2023 onwards, translating into a reduction in permitting durations by one to three years (European Commission, 2025[26]). Such progress underscores the critical role efficient permitting plays in accelerating renewable energy deployment and infrastructure roll-out. The German example also flags risks, as it includes projects that led to public opposition, resulting in, underscoring the importance of giving citizens opportunities for early engagement and the chance to improve projects by incorporating local knowledge (Horn and Meier, 2023[34]).
The EU has introduced broader infrastructure planning tools that can support or contribute to improving permitting conditions. ENTSO-E was mandated to develop Ten-Year Network Development Plans (TYNDPs) to provide a non-binding Union-wide outlook already in 2009 (European Union, 2009[35]). In 2019, the mandate evolved, adding, for example, greater alignment to long-term decarbonisation goals and closer coordination with ACER (European Union, 2019[36]). A further legislative update gives ACER specific responsibilities regarding the integration of flexibility needs in the TYNDP (European Union, 2024[37]). The 2024 TYNDP by ENTSO-E introduces system needs analysis for 2050, emphasizing the importance of investing in grid and storage infrastructure (ENTSO-E, 2025[38]). A similar planning obligation applies to DSOs. Since 2019, the European Commission has required DSOs to develop Distribution Network Development Plans (DNDPs). However, implementation across Member States has so far varied significantly, with different national requirements.
Streamlining authorisation procedures for cross-border infrastructure can accelerate project timelines and reduce administrative burdens. Whilst not the focus of this report, the Trans-European Networks for Energy (TEN-E) Regulation, revised in 2022, also supports the development of cross-border energy infrastructure through streamlined authorisation procedures for 11 identified priority corridors, including onshore and offshore grid interconnections (see Box 11.2). Modifying procedures to allow parallel processing of tasks traditionally handled in sequence can significantly reduce project timelines. A concrete example is the separate approval of permit granting and other preconstruction activities from the regulatory approval of the project construction (which would come later, when the need is confirmed), as suggested by ACER and CEER (ACER and CEER, 2024[32]). Additional efficiencies can be gained by clustering grid connections within the same geographical area, enabling better coordination of works and resource use. Standardising application formats and assessment criteria further streamlines approvals and reduces administrative burdens for both authorities and developers (Zsuzsanna Pató, 2024[39]).
The example of the PCI projects in the EU
The EU has established streamlined permitting and regulatory frameworks for Projects of Common Interest (PCIs) under the Trans-European Networks for Energy (TEN-E) Regulation. The PCI status signals strategic importance to investors, improving project attractiveness and lowering financing cost. These measures aim to reduce administrative and regulatory barriers for strategic energy infrastructure projects, facilitating their timely implementation.
Below are the key provisions and mechanisms that make PCIs subject to reduced barriers:
Priority Status: PCIs are granted the status of the highest national significance, ensuring expedited administrative and judicial treatment. This includes accelerated project implementation and shorter permitting procedures
One-Stop-Shop Mechanism: Member States must designate a National Competent Authority (NCA) responsible for coordinating all permitting procedures. This centralized approach simplifies the process by reducing bureaucratic complexity and providing a single point of contact for project developers
Binding Time Limits: The TEN-E Regulation imposes a binding three-and-a-half-year time limit for permit-granting procedures, ensuring projects progress without unnecessary delays
Requirements for Member States to assess how to streamline Environmental Assessments: Environmental impact assessments are simplified to reduce administrative costs while maintaining compliance with EU environmental standards
Furthermore, increased public participation is mandated through consultations, fostering transparency in decision-making processes.
Projects such as the Viking Link interconnector between Denmark and the UK have successfully utilised the streamlined permitting framework under TEN-E Regulation. This project coordinated permitting across multiple jurisdictions using the one-stop-shop approach, demonstrating its effectiveness in multi-national contexts. The Viking Link project coordinated a complex permitting schedule across four national competent authorities (NCAs) and multiple local authorities – four in the UK and two in Denmark. A key element of this process was aligning interpretations of the TEN-E Regulation, particularly how each NCA integrated its requirements into national permitting procedures. Regular meetings between NCAs helped build a shared understanding of environmental assessment approaches and permitting timelines across jurisdictions, facilitating more coordinated project delivery.
Source: (European Union, 2022[40]) and Renewables Grid Initiative
https://renewables-grid.eu/activities/best-practices/database.html?detail=181&cHash=df12d8cbbf2e8d8ac54d95f739f30dd1 last assessed in 25.03.2025
Environmental assessments currently constitute a significant portion of permitting timelines for grid infrastructure. To accelerate these processes, targeted amendments to environmental assessment regulation may be needed in order to simplify permitting without compromising environmental protections or human health. Additionally, implementing shorter deadlines at the national level would further streamline approvals for energy infrastructure projects. Measures such as tacit approval for specific administrative decisions, where applicable, and the implementation of one-stop shops for developers can help streamline this process. These approaches enhance procedural efficiency, reducing administrative delays and associated uncertainties that deter investment. Such measures would foster investment certainty while ensuring continued adherence to rigorous environmental standards. In the Netherlands and Estonia, environmental regulations feature clearly defined timelines, including maximum durations for completing the entire permitting process. This approach provides greater procedural certainty and helps to streamline project development (COWI, Eclareon and Prognos, 2025[41]).
Designating priority areas
Designating priority areas can be one tool for strategic spatial planning aimed at accelerating grid infrastructure deployment. By identifying land areas with particularly high technical potential and low environmental sensitivity Member States can pre-identify suitable zones for renewable energy project development where environmental constraints are minimal and permitting can be fast-tracked. The Renewable Acceleration Areas (RAAs) introduced by REDIII (European Union, 2023[42]) require these to be identified for at least one renewable technology. When strategically planned, Authorities can avoid project-by-project environmental impact assessments and focus on regions where renewable infrastructure is most viable and can help overcome local permitting bottlenecks and accelerate grid rollout. For grid infrastructure, this also allows for better alignment between generation assets and transmission needs, reducing connection delays and network constraints.
For grid infrastructure planning, RAAs can serve as one way for aligning spatial planning with network development. By overlaying zones of high renewable potential with areas of existing or planned grid capacity, Member States can better coordinate the expansion of both generation and transmission assets. The designation of RAAs therefore offers an opportunity not only to accelerate project timelines but also to optimise infrastructure roll-out and minimise grid congestion. Ensuring that RAAs are selected with reference to grid readiness is essential to unlocking timely connection and avoiding costly delays or curtailment risks for new renewable installations.
This can contribute to investment certainty by clarifying where project development is most viable. Early assessments of technical suitability, environmental constraints, and social acceptance reduce legal risk and administrative complexity for developers. This clarity enables grid operators and project promoters to plan with greater confidence, while maintaining flexibility for local authorities to assess specific applications. A governance framework that combines local accountability with national coordination is key to preventing administrative bottlenecks and promoting consistency. Ultimately, RAAs can help balance the twin objectives of accelerating renewable deployment and safeguarding environmental and social standards.
Overriding public interest
Legal challenges to the permitting process can also delay the construction of grid infrastructure. Opposition to new grid infrastructure projects such as electricity transmission lines can lead to appeal procedures in court, which can considerably lengthen the permitting process, see for example (ACER, 2024[28]) or (Wind Europe, 2024[43]).
The introduction of the principle of overriding public interest can be a tool to balance the public interest in grid roll-out with other public interest goals. This can strengthen the designation of projects of national significance that can be given by member states. In several countries, network development projects are either formally recognised as being of national significance or are clearly prioritised through legislative and policy measures (COWI, Eclareon and Prognos, 2025[41]) (see also Box 11.3). The overriding public interest principle establishes a presumption that the planning, construction, and operation of plants and installations for the production of energy from renewable sources, their connection to the grid, the related grid itself, and storage assets are in the overriding public interest (European Union, 2023[42]). While the national significance designation does not override EU environmental rules, the overriding public interest principle allows projects that negatively affect protected habitats/species to proceed if there are no alternatives and if compensatory measures are taken. The principle is also a way to introduce in law a prioritisation criterion for judges and balance grid infrastructure with other legal interests in a specific individual legal case.
The example of Germany
Germany has recently advanced a legal reform through the adoption of the “Solar Package I,” which includes amendments to the Renewable Energy Sources Act and the Energy Industry Act. Under this reform, transmission and distribution grid expansion projects are designated as being of overriding public interest and are granted special legal status. The package requires landowners and authorised users to permit the installation and operation of power lines for connecting renewable energy systems, as well as to grant rights of way for their construction and dismantling.
11.3.2. Anticipatory investments
(To undertake a self-assessment on anticipatory investments, see questionnaire in section 11.6).
Historically, grid planning has prioritised short-term cost efficiency and reliability based on stable demand projections. This backward-looking approach has resulted in conservative investment strategies designed to avoid stranded assets. However, today’s shifting energy landscape characterised by rapid growth in renewable generation and electrification mean that regulatory frameworks with short investment horizons are less fit (Energy Transitions Commission, 2024[25]).
Planning cycles have not necessarily kept pace with these changes to the energy landscape, and project timelines are misaligned with expected future system needs. As renewable energy projects often develop faster than the grid infrastructure needed to support them, particularly when located far from demand centres the long lead times associated with grid expansion pose risks to electricity security, making proactive planning essential. Further, given how interlinked the different parts of the electricity system are significant risk accrues if investment is not done in sync between the different part of the system. Investors in electricity supply, demand, or network infrastructure face substantial commercial risk if developments in one segment do not synchronise with progress in the others, leading to risk of investments made becoming sunk costs (C. Heussaff and G. Zachmann, 2025[24]).
Anticipatory investments – those made in expectation of future generation and demand – involve building grid capacity ahead of actual demand or supply in the medium-to-long term. They reduce the risk of bottlenecks and may allow time-sensitive projects to proceed. Despite short-term underutilisation, their long-term system value may prove significant (DSO Entity, 2025[44]), even if the costs and benefits need to be weighed to apply the most cost-effective solution.
This approach to investments can support infrastructure readiness for electrification in other key areas of the economy, such as transport, heating, and industrial sectors. Europe broader sectoral targets, including electrification in heating and transport and efficiency goals across industries should be taken account of in the planning process (Energy Transitions Commission, 2024[25]) (Solar Power Europe, 2023[45]). An example are the new requirements arising from EU regulations that mandate Member States to install charging stations, for light duty vehicles (cars and vans) and heavy duty (electric trucks) every 60 kilometers along highways by the end of 2025 and 2030, respectively.15 Early identification of these hub locations is crucial to manage anticipated increases in demand on the wider electricity distribution network. This underscores the growing importance of strategic grid planning to support infrastructure development and capacity expansion effectively.
Investments in electricity grids, encompassing both TSOs and DSOs, are currently subject to stringent regulatory oversight within the EU. TSOs and DSOs must obtain approval from their respective National Regulatory Authorities (NRAs) for investment plans and tariff methodologies (even if this may be done also ex-post). This process aims to ensure that investments are efficient, cost-effective, and aligned with the EU's energy objectives. At the distribution level, it requires Demand-side Network Development Plans (DNDPs) to be approved by NRAs. At the transmission level, the Ten-Year Network Development Plan (TYNDP) developed by ENTSO-E, with a focus on infrastructure needs with cross-border relevance and requiring regional consistency, is also subject to the oversight by ACER. ACER assesses factors such as expected benefits, costs, and progress timelines, and provides recommendations to TSOs and NRAs to address any inconsistencies or delays in project implementation.
While the regulatory framework for grid investments ensures oversight and alignment with current energy objectives, it risks not to support forward-looking, anticipatory investments aimed at addressing future needs and policy goals. TSOs have been found to effectively anticipate future electricity generation and demand, but ACER recognized that a focus on firm connection requests in infrastructure needs assessments is inadequate (ACER, 2024[21]). For DSOs, a focus on a traditional incremental approach also risks being too centred on short-term needs and not adequately integrating anticipatory grid developments (Eurelectric, 2024[46]). Further, conventional grid planning based on unmanaged peak demand should transition to dynamic models that consider net peak utilisation—accounting for both injections and withdrawals and factoring in expected flexibility from connected users, such as EVs, heat pumps, and data centres without immediately requiring major infrastructure expansion. It ensures that capital investment is only triggered once digital flexibility options are fully utilised. For this shift to succeed, DSOs and regulators need robust tools to simulate and verify dynamic, bidirectional flow scenarios (see also section 10.4.6 below).
Most jurisdictions lack a clear articulation of what constitutes anticipatory investment, leaving TSOs and DSOs without the confidence to propose them and NRAs without the tools to assess them. According to a recent 2024 report by ACER and CEER, the term “anticipatory investments” is not explicitly defined in any of the 22 national regulatory frameworks reviewed, although this may not necessarily lead to issues regarding anticipatory investments (ACER and CEER, 2024[32]). Existing planning rules often bind TSOs and DSOs to targets set in legally binding documents, discouraging forward-looking investment (Cremona and Rosslowe, 2024[11]). One extreme case is Spain’s annual investment limits set in 2013 on transmission and distribution grids based on GPD levels that have curtailed grid expansion despite clear energy transition needs. These constraints stem from regulatory frameworks that treat low near-term utilisation as inefficiency, penalising operators and disincentivising strategic upgrades.
Energy regulators need to have better visibility on network developments and network utilisation to assess infrastructure needs and facilitate decisions related to new network investments. Early communication from electricity network users regarding, for example, potential connection requests and improving coordination among stakeholders can help to expedite regulatory validation of grid investments (ACER and CEER, 2024[32]).
As most future investments are expected at the distribution grid level, fully integrating DSOs overall grid planning processes is essential. Future system needs include large-scale vehicle electrification and decentralised generation, most of which connects to the distribution grid. For DSO being empowered to plan ahead may be therefore particularly important. However, many Member States still do not provide sufficient regulatory space for DSOs to undertake anticipatory investments or to procure grid-friendly flexibility. As users connected to the distribution grids hold significant potential to provide system flexibility, this reinforces the need for a structured and forward-looking approach to distribution-level planning that accounts for interdependencies across grid levels as well as coordination with the national level (ACER, 2024[47]) (see Box 11.4). An example of where information provided by local authorities is important is when there is planning for new housing or industrial developments and where not informing DSOs sufficiently early can lead to delays and grid development inefficiencies – in misalignment of local plans with broader network needs – such as HV connections, substations, and MV/LV infrastructure.
France’s Schémas Régionaux de Raccordement au Réseau des Renouvelables (S3RENR) provides an example of how structured information and planning can support anticipatory grid investments. The S3RENR framework enables a global optimisation of grid connection planning across regions, rather than a series of isolated local optimisations based on individual connection requests. This approach offers project developers a level playing field and greater transparency regarding connection costs. It also allows grid reinforcements to commence as soon as future needs are identified.
Planning under the S3RENR is carried out in stages. First, the TSO maps all potential renewable projects in the region over a medium- to long-term horizon, ensuring alignment with the National Energy and Climate Plan (NECP). In the second stage, the TSO and DSOs jointly optimise the design of the high-voltage (HV) network and primary HV/MV substations, including flexibility options, to connect the full pool of identified projects. This process results in a comprehensive list of necessary reinforcements, a calculation of total costs, and the establishment of a regional standardised connection cost (expressed in k€/MW).
Source: (DSO Entity, 2025[44])
Regulatory frameworks must evolve to reflect new realities, and regulatory clarity should extend to scope, remuneration, and the treatment of underutilisation risks. This means revising regulatory frameworks to ensure clear definitions of what anticipatory investments means, define its scope, as well as return on investment methodologies (Trinomics, 2024[48]). Regulatory cost benchmarks should be forward-looking, ensuring efficiency assessments account for future investment needs rather than relying solely on past expenditure as these benchmarks may have been adequate for a market of relatively stable and predictable demand, this is no longer the case.
Given the shifting system needs the regulatory frameworks need to evolve to support longer investment horizons and become more agile. Regulation should increasingly be designed to accommodate anticipatory investments, recognising their value in facilitating the energy transition, achieving scale economies, and capturing externalities (wider system benefits) (DSO Entity, 2025[44]). This means revising regulatory frameworks to ensure clear definitions of what anticipatory investments means, define their scope, as well as return on investment methodologies (Trinomics, 2024[48]).16 One way may be to link or take into account the long-term Network Development Plans (NDPs) for the investment horizon projections of SOs. This may also include increasing the frequency of planning cycles, and enabling post-approval adjustments in response to new information as projects evolve (Eurelectric, 2024[5]). Further, the approval processes for strategic investments that may significantly impact electricity generation should be fast-tracked (Eurelectric, 2024[5]). Further NRAs may need to introduce risk mitigation instruments within the regulatory framework. A range of uncertainty management mechanisms exist and can be tailored to the characteristics of each investment case (DSO Entity, 2025[44]).
Importantly, all comparable grid investments – anticipatory or not – should receive equal treatment in asset base inclusion and remuneration. Anticipatory investment needs to have access to stable financing. NRAs can facilitate grid financing by allowing operators to invest in anticipation of future demand, rather than waiting for confirmed needs. To do so, they need to provide clear guidance to operators on how to integrate anticipatory investments in their asset base. Rate of returns linked to government bonds could also help financial risks for operators. While this approach carries the risk of underused or premature assets, it helps manage growing uncertainty (European Court of Auditors, 2025[27]). NRAs should be careful to avoid biases and ensure equal treatment for comparable investments. NRAs could review to avoid ex-post penalties for prudent but underutilised investment, thus providing additional certainty to grid operators investing in a forward-looking manner.17 Network cost recovery has also been found to rely heavily on withdrawal charges, both for TSOs and DSOs. Complementing withdrawal charges with cost-reflective injection charges has been suggested as a solution that may help balancing cost allocation between consumers and producers and consequently foster efficiency (ACER, 2024[21]). Finally, ACER and CEER suggest permitting pre-construction activities ahead of full project approval, which could accelerate delivery but requires robust planning to ensure investment relevance (ACER and CEER, 2024[32]).
In sum, a shift towards a more forward-looking, stable, and predictable regulatory environment is crucial to unlock the necessary investments in grid infrastructure in anticipation of future energy needs. This requires clear frameworks, appropriate risk-reward mechanisms, streamlined processes, and a recognition of the long-term benefits of anticipatory investments for the energy transition. It also requires coordination between distribution and transmission levels, and between system operators and regulators, anticipatory investment cannot materialise at scale.
Optimising the grid use can be an important part of the solution as it may minimise the need for additional capacity by maximising the efficiency of existing grid infrastructure. This need to be part of analysis of whether to invest in grid expansion and grid investment generally. This requires clear signals – through network tariffs and zonal market prices18 - indicating when and where congestion occurs, enabling users to adjust their consumption or generation accordingly. Regulators and policymakers can play a key role in embedding these signals into tariff structures, for example through decisions that they take on the boundaries of bidding zones. Non-price signals, such as TSO and DSO capacity maps showing grid constraints, can also support more efficient network use and connection decisions. The focus of this section, however, will be on innovative solutions that do not require adding to the grid, including Grid-Enhancing Technologies (GETs) and digitalisation solutions.
11.4.1. Increase capacity in existing grid via innovative grid solutions
Current regulatory frameworks may tilt investments towards traditional capital assets. Historically, cost-based methods such as rate-of-return (RoR) and cost-plus regulation were commonly applied in tariff regulation, aimed to prevent over-investment by network companies and avoid unnecessary costs being borne by consumers (CEER, 2024[49]). However, this approach can inadvertently bias incentives towards capital over operational expenditures if the rate of return is above the cost of capital (Averch H and Johnson, 1962[50]), (C. Heussaff and G. Zachmann, 2025[24]) and (Borrmann and Brunekreeft, 2020[51]).1920
The rules may be providing insufficient incentives to grid operators to invest in innovative and cost-efficient solutions. Incentives to invest in operational expenditures like smart grid solutions and digital technologies may fall short of what can stimulate investment decisions (C. Heussaff and G. Zachmann, 2025[24]) (ACER, 2023[52]). In the case of TSOs, the current approaches do not necessarily ensure the selection of the most technological advanced cost-effective investments (ACER, 2023[52]). A regulatory framework biased towards capital spending may therefore act as a regulatory barrier to the deployment of cost-effective, operational innovations for modernising electricity networks (Brunekreeft, 2023[53]) (ACER, 2024[47]).
Innovative solutions such as Grid Enhancing Technologies (GETs) offer a faster and more cost-effective means to increase capacity on existing electricity networks. These approaches can improve monitoring, control, and utilisation of grid infrastructure, reducing the need for traditional grid reinforcements. In many cases, GETs can be deployed within three to five years – significantly faster than standard wire-based expansions, which may take a decade due to permitting and construction delays. GETs are less capital-intensive to deploy than traditional grid expansions, but they tend to involve higher operational costs for network operators, such as increased staffing or system management. Moreover, as individual GETs yield more modest benefits, multiple deployments are typically needed to achieve the system-wide impact of a new transmission line (Trinomics, 2024[48]). Recent analysis suggests that deploying innovative grid technologies could boost overall network capacity by 20–40% and reduce the need for conventional grid expansion by around 35% by 2040 – equating to potential gross savings of EUR 700 billion across Europe (ACER, 2024[47]) (CurrENT, 2024[13]).21
GETs enable system operators to maximise the transmission or distribution of electricity across the existing grid by using a family of technologies, including sensors, power flow control devices, and analytical tools. Their core advantages are threefold: (i) more efficient use of existing infrastructure, (ii) faster deployment of capacity at both transmission and distribution levels, and (iii) reduced need for costly grid investments (CurrENT, 2024[13]). Key examples include Dynamic Line Rating (DLR) and Ambient Line Rating (ALR), which adjust thermal limits based on real-time or weather-based conditions, and Dynamic Transformer Rating, which enables increased utilisation while managing asset life. Additional GETs include Power Flow Controllers (PFCs), such as phase-shifting transformers or software-based topology control, which reroute electricity from congested lines; High-Temperature Superconductor (HTS) cables, capable of transmitting five times the current of conventional cables; and Digital Twin (DT) platforms, which digitally replicate grid assets to optimise performance and predictive maintenance (CurrENT, 2024[13]).
There is some evidence to suggest that GETs can unlock significant system benefits – boosting renewable energy utilisation by up to 20% and reducing emissions by as much as 70%, depending on market conditions (CurrENT, 2024[13]). Suppliers also estimate that GETs could enhance overall network capacity in Europe by 20–40% and reduce grid expansion costs by up to 35% by 2040.
Despite their potential, these solutions remain underutilised. One key barrier identified by stakeholders is the prevailing capital expenditure (CAPEX) bias in regulatory frameworks, which often incentivises traditional infrastructure investments over operational expenditure (OPEX)-based innovations, see for example (CurrENT, 2024[13]). A shift towards TOTEX-based remuneration, placing an overall requirement of economic efficiency for all expenditures, including OPEX and CAPEX, is therefore a possible tool for incentivising the use of innovative solutions.22 Unlike CAPEX-focused models, which favour asset-based investments included in the regulatory asset base (RAB), TOTEX frameworks can treat capital and operational expenditures more neutrally. However, even if the potential of TOTEX regulation to address the CAPEX bias exists, there is significant complexity to its implementation (ACER, 2023[52]).23 Nonetheless, properly designed TOTEX approaches can better align incentives with system efficiency and long-term cost reduction.
Further, another way to incentivise uptake is to ensure regulatory frameworks require the assessment of non-wire alternatives and authorise cost recovery for their deployment. However, analysis shows that many Member States do not yet provide sufficient regulatory space for DSOs to procure grid-friendly flexibility (Eurelectric, 2024[5]). Given the monopoly nature of network activities, clear regulation is essential to ensure that flexibility and other alternative solutions are properly considered alongside traditional grid expansion.
11.4.2. Grid mapping and transparency in grid connections
(To undertake a self-assessment on grid mapping and transparency, see questionnaire in section 11.6).
In economic terms, a coordination problem arises when multiple actors must make interdependent decisions without access to shared information or reliable signals. In the context of renewable energy deployment, developers, investors, and system operators must align project siting, grid upgrades, and storage investments. Without transparency on available and future grid capacity, these actors face uncertainty, leading to inefficiencies such as speculative applications, misaligned infrastructure, and underutilised flexibility solutions. By providing clear, accessible, and location-specific data this enables better planning and synchronisation between generation, storage, and grid infrastructure, see for example (ACER and CEER, 2024[32]).
A lack of transparency regarding grid capacity and constraints hinders the efficient use of existing infrastructure. When information on available hosting capacity, grid congestion, and planned reinforcements is limited or fragmented, renewable energy project developers are unable to make well-informed siting decisions. This uncertainty can deter investors and limit financing options. This may also lead to multiple speculative connection requests, increasing administrative burden for system operators and delaying viable projects. In turn, this raises transaction costs and hinders the deployment of flexibility solutions that could otherwise ease local constraints.
In many EU countries, public access to grid saturation data – such as reserved capacity and congestion levels – is either unavailable or not updated regularly. Developers often lack access to reliable and frequently updated grid maps with geospatial data detailing available capacity at each substation (Wind Europe, 2024[43]). Information asymmetries across technologies and markets also impede optimal planning and choices and thus may not lead to the most efficient projects advancing.
To improve utilisation of existing grid capacity and overcome the coordination problem, TSOs and DSOs should publish detailed grid hosting capacity maps. These tools promote cost-effective approaches to renewable energy capacity integration and grid development. They do so as they reduce speculative connection requests by guiding developers toward viable connection points. They also highlight areas of limited capacity, where flexibility solutions – like storage and demand-side response – are most needed. Regularly updated, granular maps with location-specific data, indicative connection costs, and timelines improve investment certainty by integrating grid factors into early-stage project planning. For good examples of grid mapping, see Box 11.5.
Improved grid transparency can help ease the administrative burden on TSOs and DSOs by reducing speculative grid connection applications. Many grid operators still rely on a ‘first-come, first-served’ approach that evaluates each application on a location-specific basis (see sub-section 11.5). By reducing the volume of speculative grid connection requests, as project promoters would reduce application for multiple locations, this will contribute to reducing the administrative workload of TSOs and DSOs. In most jurisdictions, grid operators still follow a ‘first-come, first-served’ approach, assessing applications on a location-specific basis, which can lead to inefficient use of both time and capacity.
Since grid availability evolves rapidly, updating grid data and making this accessible regularly would enable deployment of renewable and electricity storage capacity. Regular and comprehensive updates on key variables to allow developers and investors to better assess grid availability would allow for better strategic planning, plan projects more efficiently and reduce uncertainty.24
Important information points include both current capacity as well as future grid developments for both distribution and transmission grid data (Ember and Regulatory Assistance Project, 2024[54]). To enable developers to optimise project siting based on resource availability and on grid access feasibility (Wind Europe, 2024[43]) maps should display available capacity at substations, identify connection options in congested areas, as well as explain the criteria used to assess new connection requests. Information on future grid investments is also important for project developers (Solar Power Europe, 2023[45]), including on capacity reinforcement plans by the SOs (including timeframes) for substations. In areas with high grid saturation, access to up-to-date grid capacity maps become even more important.25
Belgium - In Flanders, the DSO Fluvius has developed an interactive map of the medium-voltage grid, providing detailed information on available capacity for new load (up to 5 MW) and generation (up to 4 MW) at each substation. The map displays remaining capacity without reinforcement needs, transformer capacity, current peak loads, injection capacity (current and projected), connected users by technology, and reserved capacity. For any given location, users can view the nearest viable connection point, indicative connection lead times, and estimated connection costs. The map’s features and layout were developed in consultation with the grid user group of the flexibility forum, validated by the TSO Elia and the national regulatory authority. Fluvius also closely coordinated with Elia to integrate transmission grid constraints into the distribution-level map.
Denmark - Both the TSO and DSO maps are available on a single integrated platform. This tool provides substation-level details, including current capacity, planned upgrades, and designated zones for high-capacity generation (wind, solar, thermal). A colour-coded interface enhances usability and supports better investment and siting decisions.
Estonia - The TSO publishes a detailed capacity map that includes not only available grid capacity but also specifies the required network upgrades, along with estimated timelines and costs.
Some standardisation or harmonisation of data made available and data formats would also allow for better investment decisions across the EU. This would facilitate across the EU comparisons of connection options thus also facilitate decisions by developers and investors.26
11.4.3. Flexible connection agreements
Flexibility connection agreements – also known as alternative connection agreements or non-firm connections – serve as instruments to manage grid congestion effectively via supply flexibility.27 Unlike traditional firm connections, which guarantee developers such as wind or solar producers continuous and uninterrupted grid access, flexible agreements allow for adjustments in the timing and volume of electricity injections or withdrawals. Such arrangements can mitigate congestion in grid-constrained areas, providing temporary relief while awaiting necessary infrastructure upgrades or the development of local flexibility markets. Additionally, these agreements may offer a cost-effective alternative to expensive grid reinforcement measures (CEER, 2023[20]).
Regulatory frameworks can hinder the adoption of flexible grid connection agreements. The uptake of flexibility contracts depends on several factors, including grid constraints, the availability of local flexibility markets, and the regulatory framework governing such agreements. Current regulatory frameworks vary considerably, often lacking clarity or explicitly restricting flexible connections - according to a recent report there are countries or regions where alternative connection agreements are either not allowed or there is uncertainty regarding their implementation (CEER, 2023[20]) (Trinomics, 2024[56]). Nonetheless, they are used in 15 countries, often with tariff discounts or reduced connection charges (ACER, 2025[57]).
Key considerations for regulatory authorities might include how these contracts interact with market-based flexibility mechanisms, the typical use cases that justify their deployment, and the data needed to support effective oversight and fit-for-purpose regulation. This framework should provide clear criteria for transitioning from flexible to firm connections once the network is upgraded to ensure it does not lead to indefinite delays in grid build-out. Flexible connection agreements might specify key parameters, including firm and flexible injection and withdrawal capacities, applicable network charges, and the duration of the agreement, including the expected timeline for securing full firm capacity (see Box 11.6).
Capacity Limitation and Non-Firm Connection Contracts in the Netherlands
The Netherlands has introduced innovative contractual models to better manage grid congestion and accelerate connections. One such model is the Capacity Limitation Contract (CBC), which allows grid users to voluntarily limit their existing firm connection capacity in exchange for financial compensation. The CBC is separate from the standard 24/7 connection agreement and must specify key terms, including:
the maximum transport capacity to be used;
whether the limitation is permanent or time-bound;
the compensation rate per MW;
the connection location; and
the contract period.
DSOs can activate the CBC by notifying the grid user the day before congestion is expected, allowing for responsive grid management even outside predefined congestion zones. Several Dutch DSOs already offer these contracts to both producers and consumers, with early examples successfully concluded.
In parallel, non-firm connection contracts are also being developed, allowing projects to connect under more flexible terms in return for reduced tariffs. These models offer variable firm capacity by hour, capacity guarantees tailored to energy transport needs, and minimum availability guarantees. Unlike CBCs – which assume congestion will eventually be resolved – non-firm contracts are built around enduring flexibility. Together, these approaches offer scalable, market-aligned tools to unlock capacity and integrate more renewable energy.
Source: (Zsuzsanna Pató, 2024[39])
11.4.4. Congestion management platforms
Organised flexibility platforms can serve as tools for TSOs and DSOs to effectively procure grid services and manage congestion. By enabling market-based procurement of flexibility from distributed energy resources, these platforms help balance supply-demand and defer expensive infrastructure upgrades. Successful operation of these platforms requires harmonised data standards, effective TSO-DSO coordination, and equitable market access rules to scale efficiently. Regulated redispatch frameworks may limit its applicability in some jurisdictions. Establishing robust regulatory frameworks and clear operational guidelines will be critical for their broader usage (see Box 11.7).
In the Netherlands, TenneT together with the DSOs operates market-neutral congestion management platform called GOPACS since 2019. This platform aims to provide parties with flexibility potential easy access to a growing market for congestion services. GOPACS is not a trading platform but allows market players to monetise their available flexibility on energy-trading platforms ETPA and EPEX SPOT to help resolve congestion situations. As of April 2024, there were 752 connections for redispatch registered on the GOPACS platform. Though focused on high- and medium-voltage grids, GOPACS plans to expand to low-voltage networks as congestion issues grow at that level, likely via aggregators.
The initiative, rooted in a market-based approach, led to updates in the Electricity Network Code, introducing provisions for TSO-DSO coordination, real-time communication during congestion events, and the creation of Congestion Management Service Providers (CSPs) to support smaller-scale flexibility.
Source: (IEA, 2024[19])
11.4.5. Network tariffs
Regulatory frameworks determine the maximum revenue that grid operators can earn – known as allowed revenue – which is recovered through network tariffs paid by users or the maximum price that they can charge per unit of electricity delivered. Revenues generated cover operational expenses, asset depreciation, and provides a return on grid investments. In the case of price caps, risks associated with possible declines in electricity demand volumes are borne by the operators. With revenue caps, risks are passed through to electricity end-users While the underlying principle is common across the EU, NRAs apply different tariff-setting methodologies to allocate costs among user groups, including households, businesses, industry, storage, and generators. As a result, tariff levels vary significantly across Member States. In 2023, EU households paid an average of EUR 0.072/kWh for network tariffs, while non-households paid EUR 0.035/kWh (European Court of Auditors, 2025[27]).
Distribution network tariffs may also present a barrier to the economic viability of electrification, distributed energy resources (DER), and technologies such as storage and electric vehicles.28 Higher capacity needs for electricity grids may lead to rising network charges. These would risk discouraging new installations – particularly when charges are linked to supply capacity. Consumers who have already invested in electrification may resist additional costs, particularly if they perceive them as paying twice for contributing to system efficiency.
Risks of multiple network charges are higher for storage assets and prosumers, i.e. network users that are both injecting electricity to the grid and withdrawing it. Double charges can hinder investment in clean energy technologies: tariff design should reflect the value that DER, storage, and EVs bring to the network, such as reducing peak demand and supporting local balancing services (Trinomics, 2024[56]). Net billing distinguishing between types of flows can also help eliminate double charges. However, these approaches – especially if based on energy rather than capacity, and if not integrating time-of-use pricing mechanisms – it can also lead to risks of comparatively high charges for other network users.
Connection charges linked to supply capacity can be beneficial if they help managing risks posed by speculative network connection requests. Capacity-based charges are tied directly to the maximum amount of electricity a customer can draw from the network, rather than their actual consumption (energy-charges). Speculative connection requests, risking being paired with a monopolisation of connections to sell then at higher prices, were flagged in the case of Spain already in 2019 (EU Parliament, 2019[58]). Challenges from speculative projects have also been arising recently in Sardinia, in Italy, leading to social backlash (Pinna, 2024[59]; AFP, 2024[60]). Charges, deposits or guarantees applied together also with milestones can help avoid speculation, in comparison with energy charges, as they dissuade developers or businesses from requests of large capacity connections that they may not immediately use. In doing so, they reduce the risk of clogging interconnection queues and therefore accelerating genuine projects, lowering costs once delay risks are factored in. This highlights the importance of striking a balance between ensuring effective project implementation on one hand and facilitating universal access to the network, on the other. Complementary or alternative solutions include prioritization criteria, financial commitment requirements and achievement principles. They are further discussed in the section on grid connections.
Dynamic and flexible network tariffs may play a supportive role in congestion management by aligning network charges with real-time system conditions, encouraging more efficient use of grid capacity. Spatial and temporal differentiation in tariffs is particularly relevant for flexible assets such as electric vehicles, heat pumps, and storage, which can respond to signals and help alleviate local congestion. Dynamic network tariffs and connection charges can improve grid efficiency and guide investment by providing temporal and locational signals. Further, flexible grid tariffs may enable consumers to purchase firm grid capacity at full price for inflexible demand, while accessing discounted capacity for flexible uses—such as EV charging, heat pumps, or adaptable industrial processes. In exchange, the grid operator can adjust this flexible load during periods of local congestion or system stress. By reflecting system conditions over time and across locations, these pricing mechanisms help optimise grid usage and influence where and when new connections are made. However, the complexity of dynamic pricing – due to automation needs, data processing, and billing – may challenge principles of simplicity, predictability, and transparency and will need to be carefully considered by NRAs (ACER, 2025[57]).
11.4.6. Regulatory barriers to grid digitalisation
A key challenge to accelerating end-use electrification and integrating distributed energy resources (DER) is the digitalisation of the distribution grid. Moving from analogue grids to digital ones enables network operators to optimise grid operations, better manage variable energy sources, and respond more swiftly to emerging consumer needs. DSOs typically lack detailed visibility, particularly at the low-voltage level, precisely where the majority of EVs, rooftop solar installations, heat pumps, and storage batteries are located. Constrained by stringent reliability standards and lacking digital management tools, DSOs build infrastructure designed for infrequent peak demand scenarios ensuring reliability but in a very inefficient way, meaning that low-voltage grid utilisation is low. Finally, digitalisation also empowers end-users to participate actively respond to price signals, engage with flexible tariffs, and thus also participate in the grid use optimisation.
This highlights the crucial role of digitalisation investments in enhancing grid efficiency, facilitating the integration of renewable energy, and adapting to changing consumer requirements. However, realising these benefits requires supportive regulatory frameworks that incentivise investment in digital solutions. Without appropriate regulatory conditions, digitalisation projects might face barriers or underinvestment, potentially hindering the transition to smarter and more resilient electricity networks.
Investments in the digitalisation of distribution grids and the effective use of flexibility could be faster. Despite the growing importance of digital tools for managing distributed resources, some DSOs still make limited use of such solutions. Barriers identified by a number of DSOs include regulatory constraints on data access and handling, unclear responsibilities for digitalisation and inadequate incentives, for investing in digital infrastructure, related with the CAPEX-bias in regulatory frameworks (Eurelectric, 2024[61]).29
Clear regulatory supports the effective use of smart meter data by DSOs. In the EU, the main principles and requirements for the management of energy data are set in the Electricity Directive (EU) 2019/944, including specific requirements for cases where DSOs are actively involved in data management.30 Specific interoperability requirements and non-discriminatory and transparent procedures for access to metering and consumption data were further detailed in an implementing regulation.31 Nevertheless, many DSOs still reported in 2024 on the absence of specific rules on how smart meter data – such as voltage levels, tariff structures, and consumption patterns – should be shared or utilised (Eurelectric, 2024[61]). Bridging remaining knowledge and regulatory gaps can help fully exploit the potential of smart metering for grid optimisation, flexibility services, and more efficient network operation.
Regulatory treatment of digital investments can also limit incentives for grid digitalisation. Most frameworks categorise digital tools – such as digital monitoring and automation, software licences, cloud services, and data platforms – as operational expenditure (OPEX), while only physical infrastructure is recognised as capital expenditure (CAPEX). This narrow classification may discourage investment in the digital assets essential for smart grid development. As also mentioned above, However, current regulatory frameworks favour CAPEX-heavy investments, limiting the uptake of more efficient, flexible solutions. While TOTEX approaches help by balancing CAPEX and OPEX, they remain insufficient. A more targeted approach would reward DSOs for higher grid utilisation. Updating regulatory rules to include key digital components within the scope of CAPEX would better reflect modern infrastructure needs, support more efficient grid operation, and ultimately benefit both DSOs and consumers.
Dedicated codes and framework legislation are expected to help overcome risks that outdated or incomplete regulatory frameworks can slow the adoption of digital technologies across the electricity system. Key barriers include the absence of clear and consistent standards on interoperability, cybersecurity, and data protection, as well as unclear definitions of roles and responsibilities (Monaco et al., 2024[62]). These issues can hinder the effective deployment of digital solutions by creating uncertainty for market participants and limiting coordination across actors. The European Commission has introduced key measures to address these barriers including via the Cybersecurity Network Code (2024) to standardize risk assessments and incident reporting (European Union, 2024[63]), the Data Governance Act for fair data sharing and access, and guidance for a repository on metering data interoperability (European Union, 2022[64]).32
Finally, unclear roles and responsibilities among stakeholders may also act as barriers to effective digitalisation and flexibility deployment. Ambiguities persist around operational coordination – particularly between DSOs and TSOs – as well as around accountability for fulfilling flexibility contracts (Monaco et al., 2024[62]). Without clear rules on who is responsible for compliance and decision-making, collaboration between system operators, flexibility providers, and other actors can be undermined. Establishing transparent roles and responsibilities is essential to foster coordination, build trust, and support the successful rollout of innovative digital solutions.
(To undertake a self-assessment on grid connection regulatory barriers, see questionnaire in section 11.6).
System operators across Europe are facing a surge in grid connection requests, creating growing challenges for network planning and timely connection. Requests from diverse market actors – including renewable generators, industrial users, and data centres – often overlap geographically, adding complexity to connection assessments. Wind energy illustrates the scale of the issue: over 500 GW of wind capacity is currently awaiting grid connection assessment across nine countries, including Germany, France, Spain, and Poland (Wind Europe, 2024[65]). In Germany, connection delays have worsened significantly. According to the German Agency for Onshore Wind Energy (Fachagentur Windenergie an Land, 2023[66]), the average time from project approval to grid connection doubled from one year (2011–2017) to two years (2018–2022). This highlights the growing mismatch between project pipelines and available grid capacity.
Grid connection delays remain a bottleneck for PV solar deployment across the EU, particularly for utility-scale projects. While most Member States report small-scale PV connection times below six months, delays of up to a year persist in some regions due to insufficient digitalisation, staffing shortages, and unclear procedures. In contrast, utility-scale projects face significantly longer timelines – averaging around four years and reaching up to eight in congested areas – due to limited grid capacity, non-transparent connection processes, and inadequate infrastructure planning (Solar Power Europe, 2022[67]).33
Grid connection procedures in many countries follow a first-come, first-served approach that treats all technologies equally. Formal connection requests – whether for generation, storage, or demand – are typically placed in the same queue and processed in order of submission. While this method is administratively straightforward, it is increasingly ill-suited to the current pace and complexity of renewable energy deployment. It can lead to grid congestion, unbalanced technological integration, and inefficient use of capacity, as speculative or inactive projects may block grid access for more advanced or flexible ones (Wind Europe, 2024[65]). Moreover, projects in the queue often vary widely in their likelihood of completion and stage of development. When a project fails to proceed, the associated grid capacity may remain locked for extended periods, slowing the rollout of more viable alternatives. As a result, the traditional first-come, first-served model is under growing pressure and may need to be replaced with more strategic, readiness-based connection procedures.
There is growing recognition of the need to move beyond the traditional first-come, first-served approach to grid connections. In some cases, speculative or inactive projects can block capacity and delay more advanced or beneficial investments. Prioritising projects on a first-ready, first-served basis – or based on their social and system value – can help ensure that limited grid capacity is used more efficiently to support timely and impactful deployment (see Box 11.9).34
Transmission and distribution system operators are generally required to connect all new users, with limited scope to refuse connections based on grid constraints or cost implications. This obligation can result in suboptimal grid development, where projects are connected despite imposing high reinforcement costs or negatively impacting system stability. Granting operators greater discretion to assess the technical and economic feasibility of connections could enhance grid efficiency and support more cost-effective expansion. To ensure transparency and consistency, this discretion should be guided by clear regulatory criteria and published guidelines, while still allowing flexibility to account for local system conditions.
Introducing measures to discourage non-viable projects and reduce queue congestion can improve the efficiency of grid connection processes. This may include offering amnesty for projects to exit the queue without penalty or implementing safeguards to prevent capacity hoarding – often driven by speculative interests rather than genuine development intent.35 Smart and dynamic queue management can improve grid access by prioritising mature, system-relevant projects while maintaining procedural fairness.
Rather than relying solely on a first-come, first-served model, grid connection queues might apply high entry criteria and incorporate milestone-based filtering to ensure that only credible projects with demonstrated financial commitments advance. Priority might be given, for example, to projects that support system integration – such as hybrid installations, co-location with storage (see Shared connections sub-section below), or those offering advanced grid-support capabilities – as well as repowering projects that optimise existing grid use. Within these prioritised categories, a first-come, first-served approach can still be applied to maintain transparency and avoid the complexity of subjective project comparisons (Wind Europe, 2024[43]). Countries like Greece, Romania, and France have introduced application fees to be paid by the project developer to ensure that only sufficiently mature and viable projects enter the queue (Wind Europe, 2024[43]). Those states have implemented criteria such as bank guarantees or project advancement in the permitting process which can help distinguish mature projects from speculative ones.
Establishing harmonised national rulebooks for grid connection may help to reduce delays and improve transparency. Many countries still lack a unified framework that clearly defines connection procedures, timelines, and stakeholder responsibilities – posing particular challenges in Member States with numerous DSOs, such as Germany. Greater consistency is also needed in grid connection rules and certification processes for small PV installations, which vary widely at the low-voltage level and create barriers for rooftop PV deployment and equipment manufacturers.36 In addition, DSOs should define clear criteria for when simplified notification procedures can apply. For good example of simplified grid connection procedures, see Box 11.8.
Additionally, rules should allow or require SOs to provide system users with timely and transparent updates on the status of their connection requests. Within a few months of a request submission, users should receive clear information on its processing. If a connection is neither approved nor permanently rejected, DSOs should continue to update applicants at least quarterly to ensure transparency and predictability in the connection process, therefore also incentivising investment.
Example of France and Spain
France – In October 2023, France enacted the "Green Industry" Law to expedite industrial development and decarbonization efforts. This legislation simplifies administrative procedures for industrial projects and their grid connections. Notably, it streamlines the environmental authorisation process by allowing public consultations and application reviews to occur concurrently, potentially reducing processing times by approximately three months. Additionally, the law permits project developers to undertake environmental compensation measures proactively through the production or acquisition of biodiversity restoration units. For projects designated as "industrial projects of major national interest," the law introduces a specialized, expedited procedure. Under this framework, grid connection processes are accelerated, and the authority to issue building permits shifts from local entities to the French government, centralising and hastening decision-making. These measures collectively aim to facilitate the swift establishment of green industries and support France's transition toward a low-carbon economy.
Spain – Spain introduced simplified administrative procedures under Royal Decree-Law 29/2021 to expedite the grid connection of electric vehicle (EV) charging infrastructure. The previous requirement to obtain licences or prior authorisations from administrative authorities has been replaced by a "responsible declaration" ("declaración responsable"). This declaration must explicitly confirm compliance with current regulations, including possession of all necessary documentation including, for example proof of payment of any required taxes. Developers may begin installing charging points and providing energy recharging services immediately upon submitting this declaration. However, the streamlined procedure does not apply to buildings recognised as historical-artistic heritage or cultural-interest assets.
Source: (DSO Entity, 2024[33]))
Country Examples: – The Netherlands and Sweden
In the Netherlands, given the significant congestion (especially during peak hours of electricity consumption) the energy regulator, Authority for Consumers and Markets (ACM), has introduced a new framework to replace the traditional "first-come, first-served" approach to grid connections. From 1 October 2024, system operators prioritise and rank projects that facilitate efficient grid management, promoting timely project implementation and effective congestion mitigation and alleviate grid congestion. For example, for battery storage systems This is followed by other priorities such as critical infrastructure projects related to national security, including defence and police services, and by socially valuable projects like schools and hospitals. For congested areas other priority factors may include user's willingness to contribute flexible capacity during periods of peak grid usage, the scale of requested connection capacity, or the project's potential to alleviate congestion. Additionally, queue positioning could be influenced by the project's stage of advancement, applying a 'first-permit, first-served' approach.
In Sweden, the approach focuses on project maturity to ensure grid connections are allocated efficiently. A new industry standard, developed in coordination with the national TSO, establishes guidelines for assessing project readiness. This ensures that priority is given to projects with a higher likelihood of being completed, reducing delays and optimising grid expansion efforts.
Spain has introduced a structured permitting framework to reduce speculative grid access and ensure project viability. Royal Decree-Law 23/2020 sets clear deadlines for renewable energy developers to secure permits, requiring the Administrative Authorisation for Construction (AAC) – including environmental approvals like the Autorización Ambiental Unificada (AAU) – within 31 months of receiving grid access. An additional six months is allowed to obtain the final Administrative Authorisation for Operation (AAO), totalling 37 months. Failure to meet these deadlines results in automatic revocation of grid rights and forfeiture of financial guarantees (EUR 40/kV), discouraging capacity hoarding.
11.5.1. Shared connections
Shared grid connection (or cable pooling) is a practical and low-cost measure to maximise the use of limited grid capacity and accelerate renewable energy deployment. It allows two or more generators – or a generator and a storage facility – with complementary production profiles (e.g. wind and solar) to share a single connection point and allocated capacity. A common example is adding a solar installation to an existing wind farm. These installations may be owned by different investors, who enter into cooperation agreements to manage cost-sharing and define their responsibilities to the grid operator. Shared grid connection improves the utilisation of connection points, flattens generation profiles, and optimises land-use. Shared connections help enhance system flexibility and gained traction in cases where the limitations of the one-user-per-connection model became clear, particularly in regions with high shares of variable renewables. As a purely regulatory measure requiring no additional infrastructure investment, Shared grid connection is widely seen as a no-regret option to ease grid bottlenecks and bring more renewables online faster (Pató, Claeys and Morawiecka, 2024[30]), see Box 11.10.
Clearer guidance on grid connection criteria for hybrid projects is needed to streamline permitting and unlock flexible capacity. In Spain, hybrid systems – such as those combining renewables and storage – are currently assessed based on their combined capacity, with storage treated as additional generation (Andries De Brouwer et al., 2022[68]). This subjects projects to stricter grid connection requirements, creating unnecessary barriers. Clear and accessible guidelines to clarify how hybrid systems are assessed might therefore create also additional legal service.
Good Practice Example: Poland’s Introduction of Cable Pooling
Poland introduced a legal framework for cable pooling in October 2023, following a legislative process that began in 2022 and involved broad stakeholder consultation. The new rules allow multiple renewable generators to share a single grid connection point. While still in its early stages, the implementation has revealed several challenges. The regulator (ERO) issued clarifying guidance in March 2024 to address inconsistent interpretations by distribution system operators (DSOs), particularly regarding whether cable pooling applies only to new joint projects or also to new installations added to existing ones.
Key limitations remain: storage is excluded from shared connections, and only one installation per pooled connection can access the RES support scheme. Additionally, DSOs still conduct full grid impact assessments and require advance payments from all parties, even when no additional costs are incurred. To address these issues, working groups involving DSOs, industry associations, the ERO, and the Ministry of Climate are being formed.
11.6.1. 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.
The 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
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← 1. This decrease was a result of a slowdown in manufacturing and industrial activity (IEA, 2024[2]).
← 2. Peak demand or production refers to the highest level of electricity consumption or generation occurring within a specific timeframe. It represents the maximum capacity that the grid must handle during periods of intense energy usage or high renewable energy output.
← 3. Hydroelectricity is also subject to variability, but on longer time scales than solar and wind.
← 4. These refer to the United States, Spain, Brazil, Italy, Japan, the United Kingdom, Germany, Australia, Mexico, Chile, India and Colombia.
← 5. Congestion management costs are expenses incurred by electricity system operators to deal with grid congestion, more specifically for remedial actions such as redispatching, countertrading and curtailment.
← 6. This is equal to approximately the entire electricity demand in Lithuania in 2024. Moreover, ACER calculates that if the 12 TWh of curtailed renewable energy were instead generated by gas-fired power plants, the resulting greenhouse gas emissions would amount be roughly equivalent to Slovenia’s total emissions from power generation.
← 7. System operators may curtail renewable electricity both preemptively and in real-time to address demand-supply imbalances, grid congestion, or system stability concerns. While some curtailment is a normal grid management practice, persistent high levels signal the need for expanded infrastructure and improved grid flexibility to optimise renewable integration (IEA, 2023[14]).
← 8. This compares to DSOs to invest EUR 33 billion annually between 2019 and 2023 (EU27 + Norway) (Eurelectric, 2024[5]).
← 9. Reconductoring involves replacing existing power lines with higher-capacity conductors, while voltage uprating increases transmission capacity by raising voltage levels, requiring modifications to insulators and upgrades to grid towers.
← 10. The Regulatory Assistance Project has identified and summarised the main tools that can be used to decrease grid congestion, offering a number of short term, medium and long term options. https://www.raponline.org/toolkit/rip-first-come-first-served/ (last assessed on 19.03.2025).
← 11. Transmission grids operate at extra high voltage (EHV) levels, typically above 150 kV, facilitating long-distance electricity transport. In contrast, distribution grids usually function at lower voltage levels, including high voltage (above 36 kV and up to 150 kV), medium voltage (1 kV to 36 kV), and low voltage (below 1 kV), serving local end-users. (Eurelectric, 2024[5]). Low-voltage electricity distribution is typically managed through municipal-level concessions.
← 12. Whilst historically, DSOs relied on top-down forecasting and simulation models focused primarily on higher voltage levels due to the predictable and stable nature of demand, DSOs now need to also use bottom-up forecasting methods, with detailed smart meter data alongside sophisticated, granular simulation tools.
← 13. ENTSO-E – General guidelines for reinforcing the cooperation between TSOs and DSOs,
← 14. This is the estimate of ACER relating to PCIs, whilst it notes that this is for PCI and these are “likely to take longer compared to projects without cross-border relevance”. Nonetheless, they are indicative of long permitting times.
← 15. Regulation (EU) 2023/1804 of the European Parliament and of the Council of 13 September 2023 on the deployment of alternative fuels infrastructure, and repealing Directive 2014/94/EU.
← 16. The (Trinomics, 2024[48]) reports suggests that anticipatory investments should be reflected in tariff methodologies and allow for appropriate cost recovery.
← 17. This needs to be accompanied with clear ex-ante specification of ex-post assessment criteria to provide regulatory certainty and maintain investment incentives.
← 18. This can be quite complex and would require careful consideration.
← 19. This has since lead to the development of some incentive regulation approaches such as price or revenue caps, see (CEER, 2024[49]).
← 20. See (European Court of Auditors, 2025[27]), p 40 for a concise comprehensive treatment of the different frameworks for remunerating grid operators.
← 21. These estimates do not account for the operational expenditure associated with deploying such technologies, which are typically OPEX-intensive.
← 22. This is now required under Article 18 of Regulation (EU) 2019/943 as revised (the Electricity Regulation).
← 23. The report recommends that NRAs establish and request TSOs to use a CBA methodology for assessing high CAPEX projects. This methodology would include the monetization of relevant project benefits such as market integration, variation of losses, security of supply, and sustainability/climate benefits and help prioritize between proposed projects and alternatives that address the same need
← 24. These obligations are set out in the Electricity Directive, which refers to such information being made available by TSOs and DSOs at least quarterly. See Articles 50 and Article 31 (3) of the Electricity Directive.
← 25. Under the Electricity Market Regulation (Articles 50 and 57) and the Electricity Directive (Article 31), TSOs and DSOs must publish high-resolution data on available grid capacity, including capacity under connection requests and options for flexible connections in congested areas. They must update this at least monthly (TSOs) or quarterly (DSOs), and disclose the criteria used to assess capacity availability.
← 26. Under Action 6 of the EU Grid Action Plan, ENTSO-E and the EU DSO Entity are tasked with establishment of harmonised definitions for available grid hosting capacity among system operators.
← 27. This differs from demand-response flexibility that can also enhance grid efficiency, but by encouraging consumers to adjust or reduce electricity consumption during peak demand or grid congestion periods, helping to flatten demand spikes and optimise the use of existing grid infrastructure.
← 28. While distribution network tariffs represent an implicit incentive for distributed energy integration, a detailed analysis of tariff design falls outside the scope of this report.
← 29. This report is based on survey to 31 DSOs serving more than 80M customers in 21 countries.
← 30. Directive (EU) 2019/944 of the European Parliament and of the Council of 5 June 2019 on common rules for the internal market for electricity and amending Directive 2012/27/EU (recast).
← 31. Commission Implementing Regulation (EU) 2023/1162 of 6 June 2023 on interoperability requirements and non-discriminatory and transparent procedures for access to metering and consumption data.
← 32. While these challenges are important, a detailed discussion of digital standard-setting and broader regulatory governance falls outside the scope of this report and will thus not be discussed further.
← 33. This is significantly beyond the maximum deadlines set out in RED (recast).
← 34. See for example: https://www.raponline.org/toolkit/rip-first-come-first-served/
← 36. This is acknowledged in the revised RED.