Diagnostic Toolkit for Reducing Regulatory Barriers to Solar, Wind and Pumped Hydro Storage in the European Union

1. Scene Setting and Main Findings

1.1. The Diagnostic Toolkit

See Chapter Instructions for use, on practical instructions on how to use the tool

This report presents a self-diagnostic toolkit developed by the OECD to support regulatory reform for renewable energy deployment across the European Union. Designed for use at all levels of government, the tool enables policymakers to systematically self-assess the readiness of their regulatory frameworks, identify key barriers, and prioritise areas for reform. It also introduces a structured scoring system that allows authorities not only to pinpoint regulatory challenges but also to monitor progress over time. While based in a consistent assessment methodology, the tool is adaptable to diverse legal and administrative contexts, eventually also facilitating meaningful comparisons across countries and regions.

The diagnostic toolkit is explicitly tailored to address the diversity of technologies and market segments relevant to the energy transition. This Report focuses on three core renewable technologies – PV solar, wind, and pumped hydro storage – and disaggregates each into ten relevant market segments. For example, in the case of solar, it addresses utility-scale PV, innovative solutions such as agrivoltaics, and smaller-scale residential systems, including energy communities. It also provides a comprehensive review of two cross-cutting issues: spatial planning and permitting, as well as grids. For each segment, the tool identifies the most common regulatory barriers, highlights good practices from EU Member States that have worked to address these obstacles, and provides and provides targeted self-assessment questionnaires. These can be completed by national, regional, or local authorities, depending on their competences, and generate a readiness score that helps users gauge the strength of their current regulatory framework, identify reform priorities, and track improvements over time.

This chapter provides a summary of the main findings of the Report. This Chapter begins by contextualising the application of the Diagnostic Tool (Section 1.1), then examines the challenge that represents adapting regulatory and legal frameworks to fully benefit from renewable energy sources (Section 1.2) It then explains how this report aims at supporting policymakers to assess the readiness of their regulatory framework for renewable energies (Section 1.4). Finaly, it sets out the structure of the Report to help navigate more easily (Section 1.5)

1.2. Context for the application of the Diagnostic Toolkit

Electricity is projected to account for a significantly larger share of final energy consumption by 2040. It is estimated that the share of electricity in the final energy consumption will double from 25% today to approximately 50% by 2040 (European Commission, 2024[1]). Moreover, between 1990 and 2020, peak electricity1 demand increased by 25%, and this is projected to rise by a further 60% by 2050 (see Figure 1.1. ).

Figure 1.1. Estimates of increase in peak demand

Significant change as compared to historical increases is estimated

Note: This figure is taken from (Eurelectric, 2024[2]).

Source: European Network of Transmission System Operators for Electricity (ENTSO-E); Eurelectric Decarbonisation Speedways

EU's electricity needs are expected to be increasingly met by wind and solar generation. This will lead to an expected increase from 570 GW of installed capacity in 2024 (EMBER, 2025[3]) of solar and wind power in Europe to an expected 1 200 GW by 2030 and more than 2 500 GW by 2040 (European Commission, 2024[4]).

1.2.1. The role of renewable energy in the EU

Renewable energy deployment is increasingly relevant for the EU’s economic security and competitiveness. Solar, wind and other zero marginal cost renewable energy technologies can reduce reliance on imported fossil fuels, thereby lowering input costs, strengthening energy security and insulating the EU from global price volatility – thereby addressing a key strategic vulnerability (Draghi, 2024[5]).

Renewables can attenuate the EU’s heavy reliance on fuel imports and reduce exposure to global energy price volatility. With limited fossil fuel resources, the EU is heavily reliant on energy imports. According to Eurostat, fossil fuel import costs ranged from €232 billion in 2020 to a peak of €478 billion in 2022. The 2021‑2022 energy price shock evidenced this strategic vulnerability, with wholesale electricity prices rising over 400% - from an average of €35/MWh in 2020 to €500/MWh in March 2022 (Serhan Cevik and Keitaro Ninomiya, 2022[6]). During this period, renewable energy acted as a buffer: IEA data indicates that without the solar and wind capacity added between 2021 and 2023, wholesale electricity prices would even have been 8% higher (IEA, 2024[7]), and EU consumers would have paid an estimated EUR 100 billion more for electricity (IEA, 2024[7]).

Renewables can contribute to structurally lower electricity prices across the EU. This can support it to overcome competitiveness challenges that arise from high energy costs. Due to a large reliance on fossil energy imports and geopolitical pressures, for example, the EU currently faces higher energy prices compared to the United States and China, affecting both consumers and industry (Draghi, 2024[5]). Research shows that higher shares of renewables in European countries are associated with lower average prices (Serhan Cevik and Keitaro Ninomiya, 2022[6]).2 Moreover, data on wholesale electricity prices suggest that, among EU Member States with similar generation mix characteristics, prices tend to be lower when the share of electricity generated from solar and wind is higher (see Figure 1.2).

Figure 1.2. Relationship between the average wholesale electricity prices and the share of electricity generation from fossil energy and from wind and solar in EU Member States, 2024

Source: Shares of electricity production: EMBER (EMBER, 2025[8]) and wholesale electricity prices are from (EMBER, 2025[9]).

However, realising the competitiveness gains from renewables will require significant investment across the entire energy system. This includes not only scaling up solar and wind generation, but also reinforcing grids, including cross-border grid connections (OECD, 2025 (Forthcoming)[10]), expanding storage capacity, enabling flexibility services, and deploying digital infrastructure.3 These components must be developed in tandem to ensure system reliability, efficiency, and integration of variable renewables. As the investment environment for renewables is largely influenced by the regulatory framework, the latter should be adapted to the economic characteristics and needs of these technologies.

1.2.2. Wind and solar resources have increased rapidly and are expected to continue to scale

Wind and solar capacity have scaled up rapidly in recent years, with their combined share of electricity generation in the EU more than quadrupling since 2010 to reach nearly one-third by 2024 (see Figure 1.3). While total electricity demand has slightly declined, wind and solar generation have grown consistently, exceeding fossil fuels in 2024 for the first time. Wind contributes a larger share (60% in 2024), but the share of solar has increased faster in recent years. This expansion reflects the EU’s shift towards renewables, gradually replacing other sources.

Figure 1.3. Electricity production in the EU27, total annual production (l) and shares (r), 1990 to 2024

Note: PV solar and wind generation estimates developed by the OECD differ slightly from those reported in Eurostat.

Sources: For annual generation of all technologies except PV solar and wind: 1990-2023 - Eurostat, 2024 - EMBER; For solar and wind: EMBER, Eurostat, IRENA, GEM, TZ-SAM - OECD calculations (see Annex C for details on the methodology).

Changes in the electricity generation mix were significantly influenced by increases in installed capacity of solar and wind (see Figure 1.3). For solar energy, both utility-scale and distributed PV4 systems expanded, with a marked acceleration after 2020. While distributed PV accounted for the largest share of new solar capacity from 2020 onwards, utility-scale PV also continued to grow, indicating parallel investment trends across both large- and small-scale installations. Between 2010 and 2024, PV solar capacity expanded at an average annual rate of 14.9%, with growth accelerating to over 20% per year since 2019. This acceleration was primarily driven by a surge in distributed PV, which grew by more than 28% per year. Wind capacity, by contrast, has grown steadily in a largely linear pattern between 2010 and 2024 at an average annual rate of 7.5%. As shown in Figure 1.4, onshore wind remains dominant; however, offshore wind’s share is increasing – accounting for 9% of total wind capacity in 2024, up from 5% in 2015 and just 2% in 2010. Notably, despite lower total installed capacity compared to PV solar, wind power generation exceeds that of solar. This reflects wind’s higher capacity factors, given the dependence of PV solar output on solar irradiance.5

Figure 1.4. Solar (utility-scale and distributed) and wind (onshore and offshore) capacities in the EU, 2010-2024

Sources : EMBER, Eurostat, IRENA, GEM, TZ-SAM. OECD calculations (see Annex C for details on the methodology).

An important driver of this expansion is that in recent years, solar and wind technologies have become, and will increasingly be, cost-competitive when compared to fossil fuels. Levelized costs of electricity (LCOE) – a measure of the average net present cost of electricity generation for a fuel type over its lifetime – for PV solar and wind have come down drastically in the past decade and this trend is expected to continue (see Figure 1.5).

Figure 1.5. LCOE (USD/MWh) per fuel type in the European Union

Note: The costs in the figure are taken from the “Stated Policies Scenario”, i.e. the scenario that follows from the prevailing policy settings around the word. Other scenarios, including the “Announced Pledges Scenario” (if all national energy and climate targets made by governments were to be met in full and on time) and the “Net Zero Emissions by 2050 Scenario” (net zero emissions by mid-century) lead to even lower LCOE for renewables and higher LCOE for non-renewables, resulting, for instance, from learning by doing effects or economies of scale.

Source: (IEA, 2024[11])

Solar and wind deployment differs greatly between Member States

While wind and PV solar have expanded significantly, capacity additions have varied widely across EU Member States. Figure 1.6 shows that PV solar deployed capacity to date, in absolute terms, has been seen primarily in Germany, Spain, Italy, the Netherlands, Poland and France. Most wind capacity has been deployed in Germany, France, Spain, Sweden, Italy and Poland. Significant offshore capacity additions have also taken place in the Netherlands, Belgium and Denmark.

Structural cost drivers play a role in shaping the deployment of solar and wind energy across Member States. Member States that succeeded in deploying large capacities per unit area of PV solar and wind electricity are also those with lower weighted average costs of capital (WACC) (see Figure 1.6). For instance, Germany, the Netherlands, France, Belgium and Denmark have already deployed substantial PV solar capacity – despite having lower capacity factors than Member States located further South, such as Italy and Spain, as reflected in the ratio of capacity to production. Similarly, all Member States leading in the deployment of onshore wind have benefitted from a WACC on these projects averaging less than 6%. Germany, France, Finland, the Netherlands, and Denmark all stand out as leading in onshore wind deployment; onshore wind projects had an average WACC of less than 4% across all these countries in 2023.

Figure 1.6. Installed capacity normalised per unit land area versus the weighted average cost of capital for utility-scale solar (l) and onshore wind (r) across EU Member States

Sources : EMBER, Eurostat, IRENA, GEM, TZ-SAM. OECD calculations (see Annex C for details on the methodology).

Moreover, differences within countries are significant

While differences in installed renewable energy capacity between EU Member States exist, disparities within countries can also be significant, particularly at the NUTS 2 regional level.6 These intra-national variations (see Figure 1.7 for installed capacity per unit land area for utility-scale PV solar and onshore wind) reflect a range of factors, including regional differences in natural resource availability, administrative capacity and regulatory frameworks (including spatial planning frameworks and local permitting procedures).

Figure 1.7. Installed capacity (W per m²) at NUTS 2 level for utility-scale PV solar (l) and onshore wind (r)

Sources: ENSPRESO2 – 2023 (PV solar) and 2025 (onshore wind). OECD calculations (see Annex C for details on the methodology).

1.2.3. Significant potential remains to further deploy PV solar and wind in the EU

EU Member States have a significant number of renewable projects in the pipeline

Current project pipelines suggest significant growth in renewable capacity by 2030, though deployment remains concentrated in a few Member States. Projects in the pipeline7 to 2030 (including those that are in pre-construction or in construction), assuming they all materialise, will increase utility-scale PV solar capacity by 9%, and wind capacity by more than 50%. Around two-thirds of the projects in the pipeline are being undertaken by the same countries that account for 90% of current capacity (Figure 1.8).

Figure 1.8. Installed capacity in 2024 and in the project pipeline (in pre-construction and construction) to 2030

Note: The pipeline for PV solar only includes utility-scale projects, while installed capacity includes both utility-scale and distributed PV. Wind includes both onshore and offshore. The left-hand side figures show installed capacity and capacity in pre-construction and construction in absolute terms (GW), while the right-side figures show the shares of installed, pre-construction and construction, ranked from low to high in terms of share of installed capacity.

Sources: Installed capacity: GEM, TZ-SAM. Pipeline-data: GEM. OECD calculations (see Annex C for details on the methodology).

The projected increase in PV capacity is likely underestimated, as it excludes a large share of distributed solar – installations under 1 MW – which have driven recent growth (see Figure 1.4). These smaller rooftop systems (“distributed-scale PV solar) are not tracked in pipeline data (to our knowledge), partly because they can be deployed and operational within months.

While solar deployment is beginning to diversify across more Member States, wind project pipelines remain heavily concentrated in countries with larger existing capacity. Some countries that may have seen slower growth in the past have plans to ramp-up their solar and wind capacity. For instance, Finland, Portugal, Romania, and Greece are among the EU countries with significant ambitions for utility solar in the coming five years, even though Germany and Spain still account for the largest utility-scale additions in absolute terms (Figure 1.8). For wind, the diversification of projects in the pipeline across Member States is less pronounced than for PV solar: 83% of the future capacity through 2030 is set to be installed in countries that currently account for more than 90% of current capacity (Figure 1.8).

If realised, currently announced projects for solar and wind could raise 2030 capacity significantly beyond current pipelines. In fact, announced projects (which have not yet advanced to pre-construction and are therefore more uncertain in nature) through 2030, if brought to fruition, would increase capacity additions by 70% for utility-scale PV and by 50% for onshore and offshore wind, beyond projects already in pre-construction or construction (see Figure 1.9).

Figure 1.9. Capacity of announced projects to 2030 and percentage of the announced capacity beyond projects under construction and in pre-construction, by Member State

Note: Announced PV solar capacity, and PV capacity in the pipeline is exclusively focused on utility-scale.

Source : EMBER, Eurostat, IRENA, GEM, TZ-SAM. OECD calculations (see Annex C for details on the methodology).

However, many publicly announced projects do not make it to fruition

A large share of planned renewable projects has been cancelled or postponed. Adding up the size (in MWs) of such abandoned projects shows that they represent more than 60% of the capacity in the pipeline to 2030, for PV, and are on par with the total capacity of projects in the pipeline to 2030, for wind (Figure 1.10). In the case of PV solar, Spain, Greece, Poland, Denmark, and Croatia all stand out as countries where the capacity of abandoned projects exceeds 1 GW. The capacity of abandoned projects as compared to the project pipeline is particularly high in Denmark, Poland, Croatia, Greece, and Bulgaria. In the case of wind, the capacity of projects in the pipeline is lower than the capacity of abandoned projects across most Member States, and the ratio of abandoned projects is particularly high in Denmark, Spain, Greece, and Estonia.

High rates of project abandonment can indicate structural barriers to renewable energy deployment, including regulatory, financial, and grid-related challenges. A high rate of project abandonment in a given country, whether measured in total gigawatts or as a percentage of the project pipeline, can signal the presence of significant barriers to renewable energy deployment. These barriers may include regulatory hurdles, such as lengthy, complex, or uncertain permitting processes, which can delay or discourage project development. Rising costs of capital – reflected in higher weighted average costs of capital (WACC) – can also undermine project viability, particularly in the presence of tighter financial conditions. Inadequate grid infrastructure and growing grid congestion may further limit the ability to connect new projects to the electricity system in a timely and cost-effective manner. In addition, shifts in political priorities or reductions in policy support can create uncertainty for investors and developers, weakening investment signals and delaying or cancelling planned projects. Monitoring rates of project abandonment can thus provide important insights into the challenges affecting the pace and scale of renewable energy deployment (see Figure 1.10).

Figure 1.10. Capacity of abandoned projects by Member State (l), including as a percentage of the total capacity in the project pipeline (r)

Note: Announced PV solar capacity, and PV capacity in the pipeline is exclusively focused on utility-scale. Countries are ordered in the left based on the scale of abandoned capacity. They are ordered on the right based on the share of abandoned capacity in the total of installed, in construction, in pre-construction and abandoned capacity. Countries shown as gaps on the right-side figures have no projects announced, nor in the pipeline. Projects are classified as abandoned if information on their development is no longer available two years since the time when the first historical record has been tracked.

Sources: GEM. OECD calculations (see Annex C for details on the methodology).

Current and planned installed capacity fail to meet National Energy and Climate Plans (NECPs)

Current and planned capacity in most EU Member States remains insufficient to meet country-level targets. Such targets for PV solar and wind deployment for 2030, formulated in National Energy and Climate Plans (NECPs), well exceed current installed capacity plus capacity additions in the pipeline.8 For instance, Germany, Spain, Italy, and France, which collectively account for 61.5% of the EU’s PV solar and wind installed capacity and 45% of capacity additions in the project pipeline, have NECP targets that significantly surpass current and planned installed capacities. In the case of PV, continuing scale-up of distributed installations, in line with recent historical trends (as mentioned earlier), may reasonably be expected to bridge some of the shortfall.

This does not take into account the fact that NECP targets in and of themselves may not be sufficient to meet EU-wide targets. In fact, an assessment by the European Commission in December 2023 has found that even if the NECP targets for PV and wind were to be met, a gap of more than 2 percentage points with the EU-wide 2030 collective endeavour binding target of 42.5% renewable energy under the updated RED III (EU Directive 2023/2413)9 would remain (European Commission, 2024[12]).

Figure 1.11. PV and Wind Capacity (Installed, Pipeline, Announced) vs 2030 NECP Targets and NECP share in the available potential estimated

Note: Announced PV solar capacity, and PV capacity in the pipeline is exclusively focused on utility-scale. Member States whose combined installed capacity and total capacity from announced and pipeline projects through 2030 exceed the targets set in their National Energy and Climate Plans (NECPs) are represented in the figures on the right as surpassing their NECP goals. These cases result in a negative share of the difference between the total additional capacity installed, in the pipeline and announced and the NECP capacity targeted (normalised to the NECP capacity), indicating overachievement (e.g. –39% for PV solar in Finland or wind in Estonia). These negative shares are not explicitly shown in the figures but highlight where current and planned developments (already) go beyond the original national targets.

Sources : EMBER, Eurostat, IRENA, GEM, TZ-SAM. OECD calculations (see Annex C for details on the methodology).

Enormous potential for solar and wind remains untapped

Significant additional renewable resource capacity exists, beyond what has been installed to date and is in the project pipeline through 2030. This is the case for both PV solar and wind: even under the conservative assumptions retained for the development of Figure 1.12, more than 95% of both PV solar and wind resource potential remains untapped at the EU level.

Despite recent growth, EU Member States have tapped only a small fraction of their total solar potential, even under conservative land and technology assumptions. The combined share of rooftop and ground-mounted PV solar potential that has been installed and is in the project pipeline through 2030 is below one-quarter across all EU Member States when applying conservative land availability and technology assumptions (Figure 1.12).10 Under less conservative technology assumptions, such total potential capacity could be significantly higher, from 75% higher11 to as much as 50 times higher if all available land were to be exploited.12 However, even under conservative assumptions, regions where the most PV solar capacity is set to be exploited by 2030, such as the Benelux and Germany, have yet to exploit 80%-90% of their potential. Other regions that have led in PV solar deployment, such as the Iberian Peninsula, the Nordics, Mediterranean island countries, and Italy and Greece, still have more than 90% of the potential solar resource available.

Figure 1.12. Solar capacity in 2024 and in the project pipeline to 2030 and their share in potential

Notes: The pipeline for PV solar only includes utility-scale projects, while installed capacity and potential include both utility-scale and distributed PV. Estimates for PV solar potential are taken from the 3% land-use and 170 W/m² scenario of Nijs (2019[13]), as modified in 2023.

Source: ENSPRESO, GEM, TZ-SAM. OECD calculations (see Annex C for details on the methodology).

Similarly, the combined share of onshore and offshore wind potential that has been installed and is in the project pipeline through 2030 is below half of the potential across all EU Member States (Figure 1.13). Under less conservative assumptions13, total potential capacity would be more than 40% higher. However, even under conservative assumptions, more than 95% of wind resource potential remains untapped across almost all EU Member States.

Figure 1.13. Wind capacity in 2024 and in the project pipeline to 2030 and their share in potential

Notes: Estimates for Wind potential are taken from the reference case setback scenario for onshore wind (Uihlein, Collaer and Paul Elsner, 2024[14]) and from the E2 reference fixed capacity scenario for onshore wind (ENSPRESO, preliminary analysis by JRC shared with OECD 2025b).

Source: ENSPRESO, EMBER, Eurostat, IRENA, GEM. OECD calculations (see Annex C for details on the methodology).

This highlights that a large share of Europe’s solar and wind potential remains untapped -though other important considerations may limit how much of this potential is ultimately viable or desirable to develop.

Renewable energy auctions require careful design

Renewable energy auctions have played, and will continue to play, an important role in wind and PV solar projects in the EU. Capacity allocations via Auctions account for over 70% of Europe’s renewable capacity growth between 2023 and 2028 (IEA, 2024[15]). Such auctions are market mechanisms designed for two different (but sometimes related) reasons: to allocate public support for the construction of renewable energy installations – whilst minimising distortions to competition and taking into account, for example, possible system integration costs and grid stability – or to grant developers the rights to develop a project through a competitive process (European Commission, 2024, p. 3[16]).

Although market-based deployment of renewable energy is increasing, it remains largely dependent on public support schemes in Europe. This is due to the significant targets of the EU (45% renewables by 2030) requiring rapid scaling and uptake and may also include factors that reduce incentives for existing market players to invest in renewables such as existing fossil fuel subsidies, legacy investments and existing thermal power infrastructure that risk being stranded and thermal electricity generators with long-term input contracts. Other challenges arise from the fact that renewables require complementary investments to accelerate system integration, including grid modernisation, storage and flexibility and spatial planning and permitting issues.14

Even as subsidies decline auctions will continue to be important for the allocation of scarce resources – such as land and grid access. Well-designed competitive auctions are an effective way to minimise competition distortions as well as reduce the cost of subsides, when and if subsides are still needed. They are increasingly utilised to allocate rights to develop renewable energy projects on public lands or seabed, as well as grid connection. For example, auctions can serve as a tool to secure scarce grid access, with developers bidding to gain connection rights, such as in Portugal. Further, once Member States identify suitable areas (in terms of potential but also existing infrastructure) for renewable energy deployment – such as through Renewable Acceleration Areas (RAAs)15 with simpler procedures for permitting and grid access - well-designed auctions can help ensure that land is allocated to the most efficient and least-cost projects. This can help optimise land-use and accelerate renewable energy rollout.

1.2.4.  Energy storage (including pumped hydro storage) is critical to manage variability and ensure system stability

An electricity system with a high rate of solar and wind power requires energy storage solutions, alongside demand response mechanisms, to ensure reliability of supply. The variable nature of solar and wind can negatively affect the resilience of the electricity market, especially in cases of supply and demand mismatches. Flexibility mechanisms (such as demand response and long-distance transmission linkages, including cross-border interconnections16) together with energy storage systems like batteries or pumped hydro (PHS) can help ensure supply security and balance generation and consumption. They help avoid risks of curtailment (requiring renewable electricity producers to halt their production at peak times) and/or supply shortages.

While many different energy storage technologies exist, pumped hydro storage is the most widely deployed type. The current installed capacity in the EU stands at approximately 42 GW in 2024 (generating annually approximately 29 TWh), with facilities concentrated in mountainous regions, particularly the Alps and the Pyrenees.17 This represents more than 90% of grid-scale electricity storage across the EU (European Commission, 2024, p. 8[17]).

Moreover, there is significant potential for further development and expansion of PHS. Two scenarios developed by the OECD provide a potential additional installed capacity that is between over twice (conservative scenario) and over 18 times (moderate scenario) the current installed capacity. This shows that there is significant potential, even in a conservative scenario, for PHS to increase flexibility and support, and facilitate the integration of solar and wind into the grids.

However, regardless of this significant potential, a relatively limited number of projects has been developed in the last 30 years. Most of the more than 400 projects in operation were built between the 1960s and 1980s (International Hydropower Association, 2024, p. 5[18]). There are significant barriers that hinder the development of PHS projects, which are most often large-scale, complex and high-risk.

An approach that fully integrates PHS into the energy strategy is required to address the risks and uncertainties that come with the large and long lifespan PHS projects. This includes addressing regulatory barriers related to, for instance, the heterogeneity of regulatory frameworks that apply to PHS, the lack of inclusion of PHS in national or subnational spatial plans and revenue uncertainty for project developers.

1.2.5. Grids fulfil an increasingly critical role and require optimisation and expansion

Electricity grids are central to EU’s energy transition, enabling both increased electrification across sectors and the integration of growing shares of renewable energy. While electricity demand in the EU has declined in recent years, projections show a steady rise through 2040, with electricity expected to represent half of final energy consumption (see paragraph 0 above). This, combined with a planned expansion of solar and wind capacity – set to more than quadruple by 2040 – will place unprecedented pressure on Europe’s ageing grid infrastructure, much of which was designed for thermal power plants.

Renovating transmission and distribution networks is essential to accommodate variable, decentralised renewable generation, manage growing congestion, and enable critical system services. Unlike traditional sources, wind and solar power depend on natural conditions and are often located far from major demand centres (Davis, Hausman and Rose, 2023[19]). Without timely upgrades, grid bottlenecks not only delay project connections and increase renewable curtailment but also create uncertainty that can stall investment in essential innovations, such as flexibility aggregation platforms. Persistent grid constraints risk slowing both the energy transition and the development of a more flexible, resilient power system. Signs of strain are already evident, with rising connection delays, congestion costs, and curtailments across Member States.

The financial and economic impacts of grid constraints are already substantial and are expected to worsen if no action is taken. In 2023, transmission congestion management costs reached levels equivalent to the investment required for 4.51 GW of new PV solar capacity (IEA, 2023[20]). Over 12 TWh of renewable electricity was curtailed, leading to increased reliance on more expensive and carbon-intensive back-up generation (ACER, 2024[21]) (IEA, 2023[20]).1819 Inadequate grid capacity also contributed to power outages that cost the European economy an estimated EUR 50 billion in 2021 (Eurelectric, 2024[2]). Looking ahead, a recent report shows that solar in particular is consistently underestimated in grid expansion plans by transmission system operators compared to market outlooks, and 205 GW of solar and 17 GW of wind capacity could get held up as a result of underinvestment in grids by 2030 (see Figure 1.14) (Cremona and Rosslowe, 2024[22]). Longer-term projections suggest that up to 1,220 GW of distributed renewables, 120 million EV chargers not connected and 240 TWh of industrial electrification might not occur by 2050 (Eurelectric, 2024[2]).

Achieving the necessary expansion and modernisation of Europe's grids will require an estimated EUR 584 billion in investments between 2024 and 2030 across both transmission and distribution networks (European Commission, 2023[23]). A very significant share of these investments will be needed at the distribution level, with annual requirements estimated at EUR 67 billion until 2050 (C. Heussaff and G. Zachmann, 2025[24]) (Eurelectric, 2024[2]).

Figure 1.14. Difference (GW) between grid investment plans and market outlook (negative = under investment) - solar

Source: (Cremona and Rosslowe, 2024, p. 15[22])

Meeting these challenges requires, in addition to new infrastructure and grid digitalisation, also smarter regulatory approaches. Alongside physical expansion, anticipatory investment approaches – i.e. those made in expectation of future generation and demand – by System Operators and regulators, improved planning coordination, and innovative solutions – such as reconductoring, dynamic line rating, and flexibility aggregation, as well as digitalisation – can enhance capacity and reduce delays, but often require regulatory adaptation. Critical issues include the absence of clear frameworks for anticipatory investments, lengthy and complex permitting procedures, insufficient coordination in grid connection management, and slow adoption of tools that could optimise existing grid capacity, such as flexible connection agreements and digitalised network management.

1.3. The challenge: adapting regulatory and legal frameworks is required to fully realise the benefits of renewable energy sources

Electricity markets are regulated due to both structural and policy considerations. While parts of the sector – such as transmission and distribution – may be natural monopolies requiring economic regulation to ensure fair access and cost efficiency, broader market design is also shaped by public interest goals. These include guaranteeing reliability of supply, system resilience, and long-term security of energy provision. As such, regulation plays a central role not only in safeguarding the system and consumers but also in steering investment and operational decisions to meet evolving policy objectives in the EU, including decarbonisation and affordability.

1.3.1. The role of regulation in shaping market entry, innovation, and competition in electricity markets

Market competition plays an important role in driving innovation and accelerating adoption of new technologies. A pro-competitive environment can help foster a virtuous cycle in which innovative firms with business models or technologies, enter the market and prompt rivals to respond with competing innovations, raising overall market dynamism, rapid technological diffusion, and enhanced welfare (OECD, 2023[25]; CMA, 2020[26]) (OECD, 2015[27]).

In electricity generation entry barriers are high due to a combination of structural, regulatory, and risk-related factors (Benatia and Koźluk, 2016[28]). Structural barriers include high upfront sunk costs, large capital requirements, which expose investors to significant risk, in particular if market conditions shift unfavourably (Competition Economists Group (CEG), 2012[29]). Regulatory obstacles- such as lengthy and complex permitting approvals and burdensome grid connection procedures, further raise the cost and delay entry (Benatia and Koźluk, 2016[28]). These are compounded by long project lead times and price uncertainty, fluctuating input costs, evolving policy frameworks (including regulation), all of which can increase risk premiums and deter investment in renewable projects (see for a more comprehensive discussion (Benatia and Koźluk, 2016[28])).These uncertainties may be compounded by the fact that different components (generation, storage, flexibility and grids) of the electricity system need to evolve at the same time.

At the same time, the ongoing transformation of electricity markets is reshaping who participate in generation and related services. Beyond traditional utility-scale projects, digitalisation and distributed energy systems are enabling the possibility of new business models and services that broaden the base of potential market participants, such as energy aggregators.20 This shift increases the relevance of regulation in either enabling or impeding the introduction of new technologies and actions, not only for generation, but for flexibility, balancing, and storage services as well.

Entry and exit are key mechanisms through which markets reallocate resources to more efficient firms (Adalet McGowan, Andrews and Millot, 2017[30]). Competitive pressures encourage inefficient firms to exit and allow innovative or productive entrants to grow. However, regulatory barriers – especially those that shield incumbents or impose disproportionate compliance burdens – can distort this process (Arnold, Nicoletti and Scarpetta, 2011[31]) (Andrews and Cingano, 2014[32]). Such barriers reduce market contestability, protect entrenched positions, and ultimately weaken dynamic efficiency and innovation (see for example (Benatia and Koźluk, 2016[28]) for a fuller treatment).

A range of firm-, industry-, and country-level factors influence entry and exit dynamics, but regulatory conditions are important. Key firm-level drivers include size, age, growth prospects and financial structure (Calvino, Criscuolo and Menon, 2016[33]), while industry-level influences relate to scale economies, capital intensity, market concentration, and innovation. At the Country-level, macroeconomic stability and capital access matter. Importantly, regulatory conditions also play a decisive role: (Cincera and Galgau, 2005[34]; Benatia and Koźluk, 2016[28]) find that pro-competitive regulation significantly increases both entry and exit rates, so that regulatory reform can significantly alter competitive dynamics and reshape market structure (Saia, Andrews and Albrizio, 2015[35]).

Regulation thus directly influences electricity market structures, market entry and competitive dynamics. Rules that are outdated and poorly aligned with technological advances can distort incentives, limit market entry, and suppress innovation, and reduce the uptake speed of new technologies, and ultimately reducing economic welfare (CMA, 2020[26]; OECD, 2017[36]) (OECD, 2015[27]). Regulations that impose high administrative costs, restrict market access, or favour incumbents can block innovative solutions from reaching the market, even when they are more resource-efficient (OECD, 2017[36]; CMA, 2020[26]).

The economic effects of regulatory quality extend beyond energy markets, with broader implications for innovation, productivity, and competitiveness. Empirical studies show that pro-competitive and well-governed regulation supports technology adoption and productivity growth across sectors. (Nicoletti, von Rueden and Andrews, 2020[37]) find that restrictive product market regulation significantly reduces digital technology uptake, with a one-point deterioration in the OECD’s PMR index associated with a 3% decline in adoption rates. (Gal et al., 2019[38])) in turn find the effects of adoption on productivity at the firm level. (Barone and Cingano, 2011[39]) show that anti-competitive regulation in key service sectors, including energy and finance, lowers productivity growth in downstream manufacturing – particularly in industries highly reliant on those services (Bourlès et al., 2013[40]). Similarly, (Demmou and Franco, 2020[41]) find that pro-competitive regulation and strong governance in network sectors are associated with higher long-term productivity. These findings reinforce the conclusion that modernising regulatory frameworks is essential not only to enable market entry and innovation in electricity markets, but also to generate broader economic benefits.

Regulatory reform can have significant impact on renewable deployment

Changes in regulations can significantly influence the pace and scale of renewable energy deployment. One clear illustration is the variation in permitting lead times for onshore wind projects across the EU. According to WindEurope, permitting times for onshore wind projects exceed five years in more than half of EU Member States. Germany offers an example of recent reform: in 2022, it designated renewable energy projects as being of "overriding public interest," a legal status that reduces risks of legal challenges to permitting decisions. This reform led to a 70% increase in wind installations granted permits in the year following its adoption (WindEurope, 2024[42]). Also in Germany, the reform of grid permitting with the simplification of rules led to four-fold increase in approved grid kilometres by the Federal Network Agency (BNetzA) in 2024-25.21

Figure 1.15. Total permitting lead time for onshore wind (2021) (l) and overall range in months per permitting step (r)

Source: WindEurope (WindEurope Intelligence Platform)

Another example relates to restrictive siting rules that if changed can lead to significant increases in renewable energy development. In 2016, Poland introduced the “10H rule,” requiring wind turbines to be located at least ten times their height from residential buildings – a constraint that rendered most of the country effectively inaccessible for onshore wind development. This significantly constrained project deployment for several years. In March 2023, Poland amended this rule, replacing it with a 700-metre fixed setback requirement. While some discussions continue on a potential reduction to 500 metres, the legal change has opened up previously restricted areas to development. Early estimates suggest that, as a result of the amendment, onshore wind capacity in Poland could increase fourfold by the 2040s compared to the previous regulatory regime. This illustrates how reforming rigid siting requirements can unlock significant deployment potential.

These examples highlight the importance of well-aligned regulatory frameworks at both national and subnational levels. Streamlined permitting procedures, spatial planning that reflects renewable energy priorities, and clear legal designations – such as the recognition of renewables as being in the public interest – can materially accelerate project deployment. Ensuring regulatory clarity and consistency across governance levels is essential to unlocking investment and supporting the scale-up of renewable energy.

1.3.2. Current regulatory frameworks were designed for a fundamentally different technological and economic paradigm and require adaptation

Regulatory frameworks remain shaped by a legacy energy paradigm centred on large-scale, centralised thermal generation. Existing rules were developed for an electricity system characterised by large power plants with one-directional power flows. In contrast, renewable energy technologies introduce a more decentralised model, featuring multiple small-scale generation points (including rooftop solar in urban areas) which result also in distinct economic characteristics – namely, as regards cost structures (high upfront investment with low marginal costs), and enable the entry of a diverse set of business models, market players and market price formation (dispatchable fuel prices vs technology costs).

The shift toward decentralised, variable, and digital energy systems is enabling new operational and market models. Decentralised and variable generation has enabled the possibility of new business models such as virtual power plants (VPPs), peer-to-peer energy trading, and prosumer-led systems. These models diverge from conventional structures by requiring new forms of coordination, dynamic interaction with the grid, and alternative revenue streams, and can enhance grid flexibility, unlock distributed energy revenue streams, and support real-time system balancing. At the same time, emerging applications such as Floating Solar and Agrivoltaics offer dual land-use benefits but often remain constrained the absence of tailored regulatory provisions.

Realising the benefits of emerging energy models will require targeted reform of regulatory frameworks. As electricity systems evolve and become increasingly decentralised and digitalised, policymakers must not only anticipate evolving business needs but also design rules that enable diverse forms of market participation while safeguarding system stability. Regulatory adaptation to accommodate both decentralised renewable generation and new business models can reduce system costs, reduce the need for infrastructure investment, and improve system optimisation.

In light of these shifts, reforms are needed across three core regulatory dimensions:

1. Planning and permitting: Frameworks need to evolve from rules made for large, centralised projects to accommodate dispersed, small-to medium-scale renewable installations across varied locations (See Section II and technology/market segment specific chapters 3 to 9)

2. Market design: Rules should enable value capture from distributed assets and new services, define new roles and responsibilities, facilitate innovative business models, as well as wider participation by a larger group of players (including residential customers) (See technology/ market segment specific chapters 3 to 9).

3. Grid regulation: Regulatory frameworks must adapt to enable grid expansion and modernisation, including use of new more efficient smart grid technologies, facilitate grid connection and interconnection across markets to increase balancing of variability from renewables.

4. Sub-national rules are also critical

Regulatory barriers frequently arise at the subnational level and require greater attention. While the distribution of legal competences across government levels varies among Member States, our analysis shows that many barriers are rooted in subnational regulations – even in relatively centralised systems. These rules can significantly affect the speed and certainty of renewable energy deployment.

The division of legal powers across national, regional, and local authorities differs widely across the EU. While in a “centralised regime”, the majority of legal powers and competences are held at the national level, a “decentralised regime” has transferred such powers and responsibilities from the central government to authorities at subnational level, giving them some degree of autonomy (OECD, 2019[43]). The precise allocation of competences – ranging from legislative authority to planning and permitting functions – has material implications for the regulation of renewable energy projects.

Even in centralised systems, local and regional authorities frequently control key aspects of implementation. Competences related to spatial planning and permitting are often exercised at subnational level. For instance, in Portugal – one of this report’s case studies – municipalities in the Algarve play a decisive role in approving renewable energy projects. As a result, the regulatory landscape governing renewable energy projects is shaped not only by national frameworks but also by subnational decision-making, with important implications for the pace and certainty of project deployment.

Subnational procedures often involve overlapping competences and fragmented processes. Project developers – whether renewable energy producers or system operators – may encounter multiple authorisation layers, involving national ministries, regional planning bodies, and municipal authorities. These actors often operate under different procedural rules, documentation requirements, and timelines, especially in spatial planning, permitting, and grid connection processes. This multiplicity can create uncertainty and administrative burden.

Regulatory reform must therefore extend beyond national legislation to encompass subnational frameworks. Adapting regulation to the technological and economic realities of renewable energy requires coherent and enabling rules at all governance levels. Reforms should aim to clarify roles, harmonise procedures where possible, and respect local priorities – such as land-use, environmental protection, and grid development needs. This report highlights the need to systematically address subnational governance as a key factor in accelerating renewable deployment – an aspect that may be overlooked and one of the novelties introduced by this Report and Diagnostic Tool.

1.4. A Diagnostic Tool to support policymakers to assess the readiness of their regulatory frameworks for renewable energy

Regulatory barriers to renewable energy vary by jurisdiction and technology, underscoring the value of a structured diagnostic tool to assess “renewable readiness”. Such a tool can identify obstacles, highlight good practices, and prioritise reforms in a transparent, evidence-based manner. It also supports regulatory simplification, cross-country comparisons, and alignment with evolving energy system needs – offering a practical resource for all levels of government.

The Diagnostic Tool contained in this Report combines quantitative and qualitative analysis to assess regulatory readiness. Its quantitative component draws on over 25 data sources and aggregates indicators into a scoreboard, enabling national or subnational policy makers to identify regulatory reform priorities, benchmark their performance against comparable regions and track progress. One key analysis compares the renewable energy capacities currently installed in a Member State or region22 with the capacity targeted or theoretical potential (under certain assumptions).

The qualitative analysis identifies key common regulatory barriers with accompanying technology-specific questionnaires and scoring. It supports policymakers in systematically identifying and assessing regulatory barriers to the deployment of PV solar, wind, and PHS in their jurisdiction. It sets out questionnaires per technology allowing a policymaker to self-assess whether the rules and regulations in place in the relevant region may have the effect of limiting the supply, the ability or incentives for renewable energy to be deployed, and the ability and incentives for consumers to exercise choice amongst market players. By answering the questions for a selected technology market, the policymaker will obtain a score indicating the level of “renewable‑readiness” of its geographic area. When combined with quantitative benchmarking, the tool offers a comprehensive view of the level of adaptation or restrictiveness of the current rulebook.

This qualitative analysis integrates different key OECD approaches23 – notably the OECD Competition Assessment Toolkit (integrated in the European Commission’s Better regulation’ toolbox 2023), the OECD Product Market Regulation (PMR) indicators, the Indicators of Economic Burdens of Environmental Policy (BEEP) and Design and Evaluation of Environmental Policies (DEEP) – ensuring a robust, tried and tested evidence-based framework.

What further distinguishes this tool is its granular market-specific approach. Rather than treating renewable energy as a monolithic sector, it segments the analysis into ten distinct markets across PV solar, wind, and PHS technologies (see Figure 1.16). This segmentation ensures that regulatory assessment reflects the unique characteristics and challenges of each market.

1.4.1. Preliminary findings: key barriers in the EU for increased deployment of renewable energy

Our analysis has identified six key common barriers to renewable energy deployment across the EU. These barriers represent systematic challenges that, if left unaddressed, risk hindering the renewable energy development. Each barrier has distinct characteristics but collectively they form an interconnected web of challenges that must be addressed together. The identification of these barriers resulted from our analysis based on desk research and consultation with numerous public and private stakeholders, including via two workshops.

Figure 1.16. Overview of key regulatory barriers in the EU

Legal frameworks barriers continue to impede the deployment of many renewable technologies and business models. Solutions such as Agrivoltaics (combining agricultural land-use with solar energy generation), energy communities (enabling local collective self-consumption), and energy aggregators (managing distributed energy resources) often face regulatory ambiguity. Unclear definitions, rights and obligations create legal uncertainty, raise compliance risks, and discourage market entry. In some cases, regulatory requirements – such as excessive setback distances for onshore wind – function as restrictions on deployment. Moreover, inconsistent classification and regulatory treatment across Member States further complicate cross-border investment, reduces possibilities for scaling of innovative solutions and hinders the EU market integration.

Uncertain remuneration and cost treatment weaken incentives for market entry and deployment. Renewable energy technologies that do not fit conventional categories – such as agrivoltaics or long-duration pumped hydro storage – often face unclear legal treatment. For example, agrivoltaic installations may trigger reclassification of farmland resulting in tax implications or loss of Common Agricultural Policy (CAP) subsidies; PHS projects may be subject to double taxation and grid fees due to unclear status as generators or consumers. Additionally, many Member States lack clear rules for compensating storage or ancillary services to balance the system, for example, leaving revenue mechanisms undefined.24. Without clear and stable rules on remuneration and cost recovery, these technologies face heightened legal and financial risks that deter investment.

Outdated and uncoordinated spatial planning hinders renewable energy deployment. In many countries spatial plans are not regularly updated to reflect evolving technologies, such as renewables. This makes it difficult to identify and then secure suitable sites for onshore wind, PV solar, Agrivoltaics, and PHS projects, for example. Further, the absence of integrated spatial planning aligned with energy and grid strategies delays project siting and increases risks regarding grid connection later in the development phases. Moreover, land-use planning spans multiple governance levels – local, regional, and national – often leading to inconsistent or conflicting siting rules. The absence of designated zones for renewables and limited coordination across levels of government increases siting conflicts and reduces predictability for developers.

Permitting processes remain a critical bottleneck to renewable deployment. Across Europe renewable energy developers must navigate complex and lengthy administrative procedures involving multiple authorities and unclear sequencing of approvals. These authorisation procedures, serving legitimate purposes of ensuring safety and environmental protection, were originally designed for large thermal plants, not for today’s distributed renewable projects. For onshore wind and solar projects, permitting durations can exceed 5 years, while agrivoltaics and PHS projects often face additional hurdles due to overlapping competences in local authorities as well as agriculture, environment, and energy ministries and authorities, operating under different timelines and requirements. These inefficiencies are especially problematic for smaller or innovative projects, which face higher relative compliance costs.

Grid-connection rules are misaligned with distributed and hybrid resources. Grid connection rules typically follow a first-come, first-served model which was well adapted to a system of a few large thermal stations but not to processing multiple requests for access to the grid by distributed systems. This leads to long queues and lead times; merely speculative projects can block the queue and delay (or even discourage) viable efficient requests. Transparency is limited, granular hosting- capacity maps and queue data are seldom published. Additionally, often current rules often treat agrivoltaics, rooftop PV, storage, and hybrid projects as standard generation assets, ignoring their distinct generation profiles, spatial dispersion, or dual-use benefits. This creates procedural rigidity, fails to prioritise grid-efficient or low-impact projects, and overlooks their contribution to local balancing or reduced peak loads.

Separately, grid expansion and optimisation face structural disincentives. Regulatory incentives remain biased toward traditional CAPEX, discouraging anticipatory investment approaches and innovative grid-enhancing technologies and digitisation of the grid. Moreover, enabling frameworks for non-firm access, shared connections, and hybrid systems are often absent, restricting efficient grid use and slowing renewable integration.

A schematic view of the market-specific approach as well as a selection of the regulatory barriers per technology is shown in Figure 1.17.

1.4.2. Case studies: application of the tool in Apuglia (Italy) and Algarve (Portugal)

To test the practical application of the Diagnostic Tool at regional and local levels and to allow its refinement, a detailed analysis was conducted in two European regions: Apuglia (Italy) and Algarve (Portugal). These regions were selected for their contrasting regulatory frameworks, different renewable energy potentials, and varying stages of deployment maturity. While Apuglia has (regional) legislative powers over energy matters – e.g. in 2019 it was one of the first Italian regions to adopt a law on renewable energy communities – the Algarve is more (although not fully) dependent on national rules. In Apuglia the analysis was undertaken on onshore wind generation, whilst the Algarve the analysis was on PV solar (utility scale).

Figure 1.17. Technologies included in the Diagnostic Tool and their primary regulatory barriers

The Apulia and Algarve case studies highlight key factors for accelerating renewable energy deployment. Spatial planning alignment and modernisation are essential, requiring harmonised "suitable areas" and regularly updated regional plans integrating renewable energy and grid priorities. Standardised guidance and capacity support are needed at local levels, with regional authorities providing expertise and templates to streamline permitting and project assessment, including innovative solutions like agrivoltaics and floating PV. Transparency and procedural clarity reduce delays and disputes by publishing guidelines, timelines, and establishing central registries. Integrated and streamlined permitting regimes are critical, consolidating multiple tracks into single frameworks with clear criteria, including environmental assessments. Finally, stable regulatory frameworks and strategic coordination with grid planning are foundational, ensuring consistent legislation and aligning permitting with proactive grid capacity mapping and investment. These measures enhance investor confidence and facilitate efficient renewable energy project development.

1.5. Structure of the report

The report is structured as follows: Chapter 2 provides an analysis of the cross-cutting issue of spatial planning and permitting regulatory barrier. Chapters 3 to 9 analyse the Renewable Technologies, subdivided into technology markets / market segments (for instance, PV solar has been subdivided into utility-scale PV solar and innovative solutions (including agrivoltaics PV solar and floating PV solar)) as well as the issue of grids and permitting specific to the technologies, in addition to the cross-cutting chapters. This analysis analyses the potential of each of these markets and then focuses on identifying and analysing the main common regulatory barriers found. Chapter 10 is a cross-cutting chapter on Grids, with a host of specific issues related to rules to incentivise the right sort and right amount of investment in the grid, on which all other markets depend. All chapters include a questionnaire that allow policy makers at national or sub-national levels to score (from 0-6 like the PMR, with 0 being the most renewable-friendly regulatory framework) their own regulatory framework and understand the level of restrictiveness of their rules. Chapter 11 and 12 discuss the two case studies (Portugal and Italy) that have been undertaken and that have informed the analysis, especially at the regional and local levels.

The annexes (i) provide an overview of the consulted stakeholders during the project (Annex A), (ii) include a database with regulatory good practices that policy makers can use for inspiration to improve their regulatory framework where needed (Annex B), and (iii) provide more detail about the applied methodology, both on the scoring for the qualitative component (Annex C) and on the data collected for the quantitative component (Annex C ).

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Notes

← 1.  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.

← 2.  These authors estimated a one-percentage-point increase in renewable generation corresponded to an estimated 0.6% reduction in wholesale prices on average, with a stronger impact at higher levels of share of renewables.

← 3.  For example grids need an estimated total investment of 584 million by 2030 to accommodate renewables and electrification (European Commission, 2023[23]), a significant part of which will in distribution (local) grids.

← 4.  Utility-scale PV systems use large arrays to convert sunlight into electricity and operate as centralised, typically commercial, generation facilities – similar to thermal power plants, though subject to intermittency. Distributed PV, by contrast, consists of smaller, grid-connected systems installed on rooftops of homes and businesses, designed to maximise available space. Following established conventions (e.g., IEA, NREL, TZ-SAM, and Global Energy Monitor), we classify PV installations above 1 MW as utility-scale.

← 5.  The capacity factor is a measure of how efficiently an energy generation facility, such as a solar or wind plant, operates over time. It is calculated as the ratio of the actual electricity output of the plant over a given period (typically a year) to the maximum possible output if the plant were operated at full capacity continuously during that same period.

← 6.  NUTS 2 regions are part of the Nomenclature of Territorial Units for Statistics (NUTS), a Eurostat classification for regions within EU Member States for statistical and policy purposes. NUTS 2 refers to intermediate-level regions – often corresponding to provinces, autonomous regions, or large administrative districts, depending on the country. As of the 2021 revision of the NUTS classification, there are 242 NUTS 2 regions in the EU.

← 7.  Data available distinguished between three types of projects in the pipeline, with increasing likelihood of realisation: projects (publicly) announced, projects in pre-construction and projects in construction. In this chapter, a distinction is being made between “announced projects” and projects in pre-construction and construction (which are considered to be “in the pipeline”).

← 8.  The National Energy and Climate Plans (NECPs) are submitted by EU Member States to the European Commission as part of their obligations under the Regulation on the Governance of the Energy Union and Climate Action (EU Regulation 2018/1999). This regulation requires each Member State to prepare integrated plans outlining how they will achieve the EU’s energy and climate targets for 2030, including on renewables, energy efficiency, and greenhouse gas reductions.

← 9.  RED III refers to the third revision of the Renewable Energy Directive.

← 10.  The resource potential scenario assessed assumes that 3% of available land is used, and low-intermediate level of PV technology performance – 170 W/m² panel efficiency, or 17% under standard test conditions – at the lower end of the efficiency range (of around 16%-24%) of commercially available monocrystalline or thin-film PV technologies.

← 11.  For instance by assuming 300 W/m² solar panel efficiency.

← 12.  The discrepancy between the low and high land-use estimates is not due to differences in the categories of land considered available, but in the share of the available ‘non-artificial’ land-used for PV. Both scenarios include the same categories – arable land, permanent crops, pastures, and abandoned land – as available. The low estimate assumes 3% utilisation of these ‘non-artificial’ areas, whereas the high estimate assumes full (100%) utilisation of these areas.

← 13.  For instance, assumptions regarding setbacks (i.e. minimum distance requirements e.g. from coasts, pipelines and cables, and military and Natura 2000 areas).

← 14.  As the role of state support is not the focus of this report, this will not be examined further.

← 15.  Directive (EU) 2023/2413 (RED III).

← 16.  Solar and wind resources vary significantly across regions and timeframes. For instance, wind tends to peak at night and during winter, while solar peaks during the day and summer. By connecting geographically distant areas through long-distance transmission, regions with surplus renewable generation can supply electricity to those experiencing deficits, effectively smoothing variability and reducing the need for localised flexibility resources.

← 17.  Estimations on the installed capacity of PHS differ depending on the used source. Annex C describes the methodology used to derive to the current installed capacity in the EU.

← 18.  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.

← 19.  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.

← 20.  Energy aggregators are entities that bundle the capacity and flexibility of multiple distributed energy resources – such as rooftop solar, batteries, electric vehicles, or demand response – from households, businesses, or energy communities. They act on behalf of these smaller actors to participate in energy markets or provide services to the grid, improving system flexibility and enabling more efficient use of decentralised resources.

← 21.  See: https://www.netzausbau.de/Vorhaben/uebersicht/prognose/de.html

← 22.  The quantitative scoreboard includes numerous indicators per renewable energy technology at Member State level, as well as NUTS 1 and 2 level. NUTS (Nomenclature of Territorial Units for Statistics) is a hierarchical system used for dividing up the economic territory of the European Union and is used for statistical purposes and to apply regional policies. See also Annex C for a detailed description of the data analysis.

← 23.  The OECD Competition Assessment Toolkit (OECD, 2021[46]) provides a structured framework based on competition principles widely used to qualitatively identify regulatory restrictions that limit market entry, distort ability and incentives to compete and limit consumer choice. The PMR Indicators (OECD, 2020[44]) enable a quantitative assessment to measure regulatory and administrative barriers to competition in product markets. The BEEP and DEEP methodology contributes a granular scoring system related to environmental policies that captures administrative burdens and economic inefficiencies, helping to quantify the severity of different regulatory barriers in that context (Koźluk, 2014[45]) (Berestycki and Dechezleprêtre, 2020[47]).

← 24.  An example is providing inertia to stabilise the system. Traditional inertia from rotating turbines in coal, gas, and nuclear plants has historically stabilised grid frequency. However, solar and wind generation-connected lack inherent inertia. This increases vulnerability to frequency deviations, risking blackouts. By integrating synthetic inertia into ancillary service frameworks updating Transmission System Operators remuneration models and setting out competitive procurement processes for such services, these services can be provided to ensure grid stability.