Martin Borowiecki
OECD Economic Surveys: European Union and Euro Area 2025
Abstract
The EU aims to enhance energy security, lower energy costs and decarbonise the economy through electrification, and the decarbonisation of electricity generation. Electricity costs are high, reflecting high taxation and weak competition. Generous fossil fuel subsidies and relatively high electricity taxes reduce incentives for electrification. Lower electricity costs could also be achieved through a more integrated Single Market for electricity. This would require structural reforms to reduce internal market barriers and strengthen competition to better align supply with demand. A more integrated Single Market for electricity would also help reducing the costs of decarbonisation.
Well-functioning and integrated electricity markets will be important to lower the costs of electricity and support the competitiveness of the EU industry. However, entry barriers, including regulatory ones, hamper competition in electricity markets, which could help lower electricity costs. Taxation of electricity is relatively high compared to fossil fuels, reducing incentives for electrification. Higher demand and supply flexibility is also needed for a decarbonised energy system with a high share of variable renewable energy. Moreover, a lack of European planning and funding creates additional disincentives for investment in cross-border electricity connections. This Chapter discusses policies to further integrate the Single Market for electricity with a view to lowering electricity costs, enhancing energy security and accelerating the energy transition.
The EU has no rich fossil fuel resources and relies heavily on energy imports. This became evident following Russia’s war of aggression against Ukraine when the EU introduced a coal and oil embargo on Russia, and Russia significantly reduced pipeline gas flows to the EU (Figure 3.1, Panel A). Global energy markets were instrumental to help replace Russian fossil fuel imports with imports from other countries. However, this adjustment came at a high cost as cheaper Russian gas was replaced by more expensive liquefied natural gas (LNG) from Norway and the United States (Panel B).
Note: Panel B, “Others” include Algeria, Azerbaijan, Libya and the United Kingdom.
Source: Eurostat; and Bruegel based on ENTSOG, GIE and Bloomberg.
During the energy crisis that followed, the EU internal energy market proved successful in shifting scarce energy volumes across EU countries. Since then, energy prices have fallen from their historic heights although they remain above pre-pandemic levels (Draghi, 2024[1]). A lingering concern is the reduced competitiveness of EU industry due to relatively high energy prices. EU wholesale gas prices were almost five times those in the United States in 2024 (Figure 3.2).
Higher gas prices directly translate into higher electricity prices because gas fired electricity-generating plants are often the plants that ensure that total electricity supply meets total electricity demand and they have the highest marginal cost (Box 3.1). As a result, EU industrial retail electricity prices were roughly twice as high as before the energy crisis in 2024 (Figure 3.3). High electricity prices will eventually encourage investment in cheaper energy sources. In the meantime, gas remains an important price setter and is projected to remain so at peak hours over the next decade (Gasparella, Koolen and Zucker, 2023[2]).
Gas prices, USD per Metric Million British Thermal Unit (MMBtu)
Source: IMF.
Note: Panel A, prices refer to day-ahead wholesale electricity prices. Panel B, consumption from 2 500 kWh to 4 999 kWh (band DC). Panel C, consumption from 500 MWh to 1 999 MWh (band IC).
Source: ACER calculations based on ENTSO-E transparency platform; Eurostat Electricity prices components for household consumers database; and Electricity prices for non-household consumers database.
In wholesale electricity markets, prices are set according to the electricity production cost of the last unit needed to meet demand (i.e., merit order model and marginal cost pricing). The cheapest electricity is bought first, next offers in line follow. Once demand is met, producers receive the price asked for by the last unit of electricity that was bought. In 2023, gas-produced electricity set the electricity price 37% of the time (ACER, 2024[3]). This means that wholesale electricity prices are sensitive to price swings of gas as seen during the energy crisis.
2023 reform of the electricity market
In response to the energy crisis, in 2023 the EU introduced reforms to the wholesale electricity market as discussed in more detail in the last Survey (OECD, 2023[4]). Emphasis was put on stronger uptake of long-term contracts to reduce dependence on more volatile short-term markets. These include commercial power purchase agreements (PPAs) between energy producers and industry, and government production-based subsidy schemes, notably Contracts for Difference (CfDs).
To encourage the uptake of PPAs:
To raise demand, EU countries can provide state guarantees to reduce the financial risks associated with PPAs for medium-sized companies that want to buy PPAs, as well as intermediaries who bundle demand from multiple small consumers, such as small and medium-sized enterprises. These companies often lack a strong investment grade credit rating that banks require for credit lines. In addition, the EU will provide EUR 0.5 billion (0.002% of EU GDP) in guarantees for the European Investment Bank until 2027 to counter-guarantee PPAs undertaken by companies under the Action Plan for Affordable Energy.
Electricity providers, which are often large dominant incumbents, are subject to more stringent requirements to hedge against price risks, which is expected to increase the supply of PPAs.
Renewable energy providers participating in a public tender also need to reserve a share of the generation for sale through a PPA to hedge against price risks. This should also raise the supply of PPAs.
The EU also encourages the use of CfDs:
Governments guarantee electricity providers a minimum price or strike price for electricity produced, which effectively moves some of the financial risk to the public sector. In return, a price caps limits providers’ revenues as any revenue above the price cap needs to be paid back to the government.
Providing long-term income stability through production-based CfDs reduces incentives to enter market‑based long-term PPAs. Trade-offs between these markets need to be carefully examined (see below).
EU countries can apply CfDs only to mature, low-carbon technologies with low operational costs and high capital expenses, such as solar, wind, geothermal, hydro, and nuclear energy, including historic nuclear power. Support is not allowed for emerging low-carbon technologies that are at early stages of their market development (European Parliament and European Council, 2024[5]).
Liberalisation of national electricity markets in the 1990s led to the establishment of the Single Market for electricity (Box 3.2). The aim was to lower energy prices for consumers through increased competition and consumer choice. Reforms included the liberalisation of supply by reducing barriers to entry, regulated third party access and the unbundling of transmission networks and generation. Separation of generation from networks led to the establishment of wholesale electricity markets. Independent Transmission System Operators (TSOs) now own the transmission grid in EU most countries. In some, but not all markets, there is a distinction between the TSOs and the market operators, i.e., they provide generation firms access to the transmission grid so that they can participate in wholesale electricity markets. The joint ownership and operation of grids under the umbrella of TSOs is a major difference to other electricity markets such as the United States.
Interconnected grids and European electricity exchanges allow countries to export their surplus electricity, helping to lower costs elsewhere, although countries which produce cheap electricity could see domestic prices rise (Figure 3.4, Panel A). The integrated EU electricity grid also helps to balance out production surpluses and deficits across countries by taking advantage of economies of scale. Interconnected electricity markets also allow for smoother integration of renewable intermittent sources of electricity (such as solar and wind) (Panel B). However, interconnection capacity among EU countries is still limited (see below). Further market integration would require extending interconnections between countries.
Source: Fraunhofer Institute for Solar Energy Systems (ISE); Eurostat; and OECD calculations.
The EU’s climate targets influence the EU’s Single Market for electricity. The main objective of the EU’s climate policy is to achieve net zero greenhouse gas (GHG) emissions by 2050. In addition, there are several intermediate targets for 2030: A 55% reduction in EU GHG emissions (compared to 1990), 42.5% of EU energy consumption produced from renewable resources, and a 11.7% reduction in the EU's energy consumption through higher energy efficiency (compared with the energy consumption forecasts for 2030 made in 2020). Greenhouse gas emission targets are climate targets while objectives related to renewable energy sources and energy efficiency are energy targets. Although they all contribute to climate mitigation, they also serve other energy policy goals such as energy security, fuel diversification, reduction of import dependency and competitiveness.
The EU has the Emission Trading System (ETS) at its disposal to reduce overall GHG emissions. The ETS carbon price of currently around EUR 80 per tonne of CO2 is set to rise, which will eventually support decarbonisation by making fossil fuels even more expensive than low-carbon electricity. In contrast, the EU does not have economic instruments to meet its renewable target. Here, EU countries are responsible. To achieve national renewables targets, EU countries provide generous state aid for renewables. However, such unilateral state aid may have consequences for the Single Market.
Under the Temporary Crisis and Transition Framework, the EU has temporarily relaxed its state aid regime to accelerate the rollout of renewable energy and energy storage during the energy crisis. In 2025, the EU announced a simplification of state aid rules for clean technology and energy-intensive manufacturing until 2030 to incentivise national investment in these areas aligned with EU priorities. The new state aid framework would build on the experience of the Temporary Crisis and Transition Framework (European Commission, 2024[6]; European Commission, 2025[7]). However, this stance, together with stronger use of national industrial policy, could lead to a relaxation of state aid rules and have implications for the level playing field in the Single Market as countries may give preference to their own sectors and firms. Unilateral industrial policies also endanger EU productivity by slowing down the relocation of energy-intensive industry to locations in the EU where such production is more competitive. Hence, the EU should refrain from relaxing state aid rules except in emergency situations. Instead, a more European approach for industrial policy is needed (Chapter 4).
The EU’s wholesale electricity market is divided into several zones, with a uniform price in each zone (so-called zonal pricing). Zones are usually defined by transmission constraints, or where transmission links are most likely to be congested, although also for political reasons. Germany, for instance, is a unique zone despite its relatively large size, often leading to north-south congestion.
Transmission System Operators allocate electricity capacity across zones, while cross-zonal volumes are traded at European electricity exchanges (so-called market coupling). The day-ahead market is most important for spot price setting, with national balancing markets providing ancillary services for the stabilization of the electricity grid.
The coupling of day-ahead wholesale electricity markets allows prices in every market and cross-border trades to be simultaneously determined. Market coupling also ensures that existing cross-border transit capacity is used more efficiently to send electricity from low- to high-price zones, reducing cross-country differentials in wholesale electricity prices.
Integrated and liquid day-ahead markets have supported cross-border electricity trade, which accounted for 10% of EU final electricity consumption in 2023. In contrast, balancing and future markets remain underdeveloped. On days when enough cross-zonal transit capacity is available, electricity prices across zones tend to converge. However, this is not often the case (ACER, 2024[3]). Hence, the EU aims to increase inter-zonal transit capacity to achieve a more integrated energy market.
Two European bodies were established in the 2010s to develop a rulebook for cross-border electricity trade and supervise it. The EU Agency for the Cooperation of Energy Regulators (ACER) supervises cross-border trade and surveils national wholesale and retail markets, including third-party access, cross-border capacity allocation, congestion management, and system balancing. The European Network of Transmission System Operators for Electricity (ENTSO-E) – itself not an EU agency, is tasked to develop legally binding electricity market and network codes, in accordance with the framework guidelines defined by ACER:
Market rules for short-term wholesale electricity markets: Day-ahead and intraday capacity allocation, congestion management, electricity balancing, and forward capacity allocation.
Operational codes to monitor and operate the EU-wide interconnected electricity grid.
Grid connection codes for the integration of renewables, distributed generation, and demand response.
National renewable targets also make it difficult to find market-based solutions that minimise abatement costs. For instance, if countries are not on track to meet the renewable energy target for 2030, additional investment in renewables will be needed. Such investment will not be driven by abatement cost considerations, but by the impetus to expand renewables to reach the target. Importantly, national renewable targets hamper EU-wide optimisation of the renewable fleet as they ignore cost advantage in energy rich regions (Figure 3.5). As a result, countries are encouraged to expand relatively inefficient solar production in Northern Europe, or wind production in non-coastal regions with less wind (ENTSO-E, 2024[10]).
A more cost-efficient approach would entail pricing all emissions and letting market forces determine the appropriate location with lowest abatement costs to reduce emissions, as discussed in the last Survey (OECD, 2023[4]). Carbon pricing leaves the decision on when and where to cut emissions to those who know best about their abatement costs. Support for new technologies and decarbonisation may still be necessary due to market failures. Nonetheless, a more European approach is needed for an EU-wide optimization of low-carbon energy. For instance, EU-wide competitive auctions for renewables could achieve an optimisation of the renewable fleet that reflects cost advantages of energy-rich regions (see below).
Note: Capacity factor refers to electricity produced at realistic wind or solar conditions, relative to the amount produced if the plants would in each hour have operated at their peak capacity. The figures are based on the assumptions for installed renewable capacities in 2030 reported to ENTSO-E.
Source: Bruegel (Zachmann et al., 2024[11]) based on ENTSO-E’s European Resource Adequacy Assessment 2023.
Well-functioning electricity markets, including for renewables, are important. The energy transition will have positive impacts, and more integrated markets will help lower electricity costs (IEA, 2024[12]). In the short run, however, there will be transition costs. This reflects the cost of transitioning to a low-carbon energy system with high investment in production assets, networks and flexibility mechanisms. Therefore, in addition to more integrated markets, it is important to develop more efficient renewable technologies to decarbonise in a more cost‑efficient way.
However, government support, notably through CfDs, benefits mostly mature technologies, notably solar, wind, geothermal, hydro, and nuclear energy (Box 3.1). The technology bias in subsidies hinders more efficient renewable technologies from entering the market, such as innovative wind energy solutions, or energy storage technologies, to name a few. This calls for more competitive markets and innovation, less state aid for mature technologies, and stronger support for new technologies. A way forward would be to ensure that the EU state-aid framework targets government subsidies to low-carbon technologies that are not yet competitive, as recommended in the last Survey (OECD, 2023[4]).
There is also a trade-off between industrial policy and productivity. On the one hand, some forms of national industrial policy can have positive cross-border spillovers if they are motivated by well-defined market failures such as decarbonisation and support for new technologies. However, design and implementation of such policies should be considered carefully through a cost-benefit analysis, including Single Market implications (Millot and Rawdanowicz, 2024[13]; OECD, 2024[14]). On the other hand, some EU countries with high energy prices want to maintain energy-intensive industries, whereas they could only be competitive in regions with low energy prices such as southern Spain or northern Sweden (Zachmann et al., 2024[11]). Unilateral industrial policy may bind resources in uncompetitive firms, harming competition and hindering industry’s adjustment to structural change. Some energy‑intensive production may be kept in the EU due to security of supply concerns. However, production may have to happen in locations in the EU with lower energy costs. Instead, better integrated energy markets will be key to lower energy prices and support EU productivity, which the Commission is working on (see below).
3.4.1. Enhancing competition to lower electricity costs
Competition in retail markets remains low in many EU countries (Figure 3.6). Low competitive pressures mean that developments of the wholesale market, notably price decreases due to cheaper renewable energy, are not passed through to lower retail prices for consumers (ACER, 2022[15]; European Court of Auditors, 2023[16]). This is a sign that markets are not properly functioning. National electricity regulation in some countries still inhibits entry of foreign energy producers and retailers, and smaller distributed producers, such as rooftop solar cells. For example, only seven EU countries provide smaller distributed producers access to electricity markets, balancing and congestion management services, as mandated by European legislation (ACER, 2023[17]). The EU’s Directive on Common Rules for the Internal Market for Electricity requires EU countries to develop a regulatory framework that enables market participation of such actors.
The EU should fully enforce competition in electricity markets to avoid that national electricity regulation is used by EU countries to distort the playing field in favour of national incumbents. The EU, together with the EU Agency for the Cooperation of Energy Regulators (ACER), could provide technical guidance to EU countries on the correct implementation of the EU Directive on Common Rules for the Internal Market for Electricity that guarantees all energy producers and retailers access to electricity markets. The EU could also consider infringement action when progress is insufficient.
Market share of the largest company-generator in the electricity market, %, 2022
Source: Eurostat Energy market indicator database.
Retail electricity markets remain fragmented along national lines. This reflects to some extent regulated retail electricity prices, but also other barriers such as access to grids for retailers (Figure 3.7 and Figure 3.8) (IEA, 2020[18]). Regulated retail prices, often below market prices, poorly reflect market demand, making cost recovery difficult and discouraging investment in new low-carbon electricity generation. The EU requires countries to phase out retail price regulation except if it is time-limited and for energy-poor or vulnerable households. Further market integration requires stronger price signals. This entails phasing out regulated retail prices. Instead, energy poverty can be better addressed by targeted income support such as social transfers and tax credits to vulnerable households as discussed in the last Survey (OECD, 2023[4]).
To support the electrification of the economy, the EU should phase out reduced rates and exemptions for fossil fuels as discussed in the last Survey (OECD, 2023[4]). High electricity tax rates compared to gas discourage the switch from gas to electricity (Figure 3.9 and Figure 3.10). Energy taxes are levied by governments on most forms of energy, notably mineral oils, but also gas, coal and electricity. The current EU’s Energy Taxation Directive sets a minimum excise duty rate for electricity at approximately the same level as natural gas, irrespective of carbon content. In practice, electricity is taxed more because gas benefits from fossil fuel subsidies such as reduced tax rates in many EU countries, although not all electricity is generated using low-carbon energy sources and low-carbon electricity benefits from a lower net effective energy tax rate due to subsidies for solar, wind and nuclear power (OECD, 2024[19]).
Nonetheless, net effective energy tax rates for gas continue to be relatively low and are only marginally higher than for low-carbon electricity, discouraging the switch from gas to low-carbon electricity. The European Commission proposed to reform EU-wide minimum energy tax rates for energy products. According to the proposal, exemptions and reduced rates for fossil fuel should be phased out, and taxation of fuel would no longer be based on volume but on energy content and environmental performance, with fossil fuels being taxed most heavily. The reform would also encourage the uptake of low-carbon electricity.
Electricity prices for households, EUR per MWh, 2024
Note: Electricity prices for household consumers in the consumption bands 2.5 MWh-5 MWh (band DC). "Other taxes" is negative when the environmental tax allowances' amount is higher than the amount of the environmental tax itself, and includes price support provided to electricity consumers during the energy crisis.
Source: Eurostat Electricity prices components for household consumers database.
Share of household regulated and fixed price electricity contracts, %, 2023
Note: Regulated fixed prices are fixed prices regulated by law. Market based fixed price, fixed term contracts are private contracts between retailers and consumers that set a fixed price for electricity for a fixed term.
Source: ACER based on data provided by National Regulatory Authorities.
Note: Panel A, consumption from 2 500 kWh to 4 999 kWh (band DC). Panel B, consumption from 500 MWh to 1 999 MWh (band IC). "Share of other taxes and levies" is negative when the energy tax allowances' amount is higher than the amount of the energy tax itself.
Source: Eurostat Electricity prices components for household consumers database; and Electricity prices for non-household consumers database.
Taxes by energy product, EUR per MWh, situation at 1 January 2025
Note: Data refer to taxes applied to energy products for non-business use.
Source: European Commission, Taxes in Europe database (TEDB); and OECD calculations.
3.4.2. Strengthening markets for low-carbon energy sources
The expansion of low-carbon energy sources such as renewables can help decarbonise electricity production and reduce the EU’s dependence on gas and oil imports. On the demand side, the electrification of final energy consumption is behind schedule due to the unequal uptake of electric vehicles and heat pumps. This reflects that fossil fuels still benefit from tax advantages compared to electricity, but also high costs of electric vehicles and heat pumps. Hence, a key challenge for the energy transition is to synchronise supply and demand. However, the current setup of electricity markets discourages supply and demand flexibility.
Higher demand flexibility is needed for a decarbonised energy system with a high share of intermittent renewable energy (IEA, 2024[20]; IEA, 2020[21]). However, regulated retail prices reduce the responsiveness of consumers to adjust their demand to changing supply. In addition, consumer pricing in most EU countries still involves flat rates that do not change over time (Figure 3.8). As a result, around three quarters of EU households do not adjust their consumption to price changes, although it also protects final consumers from the volatility of wholesale electricity prices. Exposing consumers to real-time electricity prices can encourage efficiency, energy savings, and lower on average electricity prices as shown for industrial consumers in Germany (Hirth, Khanna and Ruhnau, 2022[22]; Ruhnau et al., 2023[23]). It can also encourage more frequent changes of electricity providers and hence enhance competition.
In this regard, the EU requires its member states to ensure that the national regulatory framework enables suppliers to offer fixed-term, fixed-price electricity supply contracts but also dynamic electricity price contracts. Specifically, final customers who have a smart meter installed can request to conclude a dynamic electricity price contract. In Spain, for instance, the installation of smart meters has helped to raise the uptake of dynamic pricing schemes among households (ACER-CEER, 2024[24]). Already since 2009, the EU set the target for the roll-out of smart meters to cover at least 80% of the electricity end-users by 2020. However, the deployment of smart meters is behind schedule in many EU countries (Figure 3.11).
Roll-out of smart meters among households, %, 2023
Source: ACER based on data provided by National Regulatory Authorities.
EU countries are subsidising the expansion of domestic renewable energy production. Electricity levies (or charges) finance the costs of energy policies linked to the transition of the electricity sector, such as those supporting renewable energy. Electricity levies differ from general energy taxation, which is discussed above. Over 70% of new renewable capacity installed in 2023 and 2024 involved renewable support, including through feed-in tariffs, feed‑in premiums and Contracts for Difference auctions, where producers receive a subsidy from the government when the wholesale price is below the strike price (IEA, 2023[25]). This moves some the financial risk to the public sector to incentivize the rollout of renewable energy. If wholesale electricity prices are too low, or the cost of capital too high due to market failures, public support becomes necessary to maintain this level of capacity. In this sense, government support provides investors with long term price certainty to cover high capital costs of renewables.
However, government intervention may reduce supply flexibility. A growing share of the energy mix is subsidised, with production decoupled from wholesale market price developments. In 2023, already half of the EU’s electricity supply was provided by such subsidised renewable and nuclear generation (Figure 3.12, Panel A). Production subsidies, such as feed-in tariffs and production-based CfDs, mute price signals for producers and have contributed to more frequent production surpluses or deficits, and overall higher price volatility. For instance, episodes of low and even negative prices have become more frequent as periods of high renewable generation meet low demand, such as on weekends in summer, reducing investment incentives in renewables (Panel B).
A stronger role of market prices is called for to raise supply responsiveness to demand. In this regard, EU state aid rules require since 2022 that beneficiaries of state support measures should not be incentivised to offer their output below their marginal costs. Also, state aid should not be provided for production in any periods when wholesale electricity prices are negative. There are efficient, non-production based CfD designs that allow price support to provide long-term investment incentives without muting the market price signal. These include, for instance, 2-way production-independent CfDs with a strike price set based on competitive tendering. Hence, the EU state-aid framework should target government subsidies to low-carbon technologies without distorting the functioning of the market. Another important barrier to higher supply flexibility is limited energy storage capacity.
Moving to stronger local price signals (or locational pricing) that reflect local scarcity (or abundance) of electricity is economically efficient because generators have stronger price signals as to where to invest in generation and storage. A more efficient distribution of electricity would also dampen price volatility resulting from renewables (Cevik, 2025[26]). Hence, ACER should review the current EU bidding zones with a view to improving locational price signals. Another approach would be to include a stronger locational price element in network tariffs as proposed by the Commission (European Commission, 2025[27]).
Source: ACER calculations based on ENTSO-E transparency platform (actual generation per type), European Network of Transmission System Operators for Electricity (ENTSO-E) and regulation on wholesale energy market integrity and transparency (REMIT) data.
Private risk markets such as long-term contracts remain underdeveloped. Even in the most liquid risk market, Germany, market liquidity for contracts longer than one year is low and almost non-existent beyond three years (ACER, 2024[3]). A market with long term contracts could develop, but in current circumstances, producers have no incentives to participate in such a market. This is a competition issue and reflects that national incumbents that dominate energy markets in most countries are both electricity producers and retailers at the same time. Hence, they are naturally protected against financial risks because they benefit from wholesale or retail profits (Ambec, Crampes and Tirole, 2023[28]). A way to enhance risk markets is to encourage risk insurance for electricity providers in the form of long-term contracts.
Contracts for Difference auctions can help incentivise investment in new technologies for which markets do not yet exist or when risks are too high for the private sector, such as carbon capture. An alternative approach to support carbon capture technologies is to extend the EU’s Emission Trading System to carbon removals as discussed in the last Survey (OECD, 2023[4]).
Security of supply will also require stronger market integration. However, little coordination happens between EU countries when it comes to actual investment. A strict national approach to renewable support neglects dependencies among countries. Such externalities require a more regional or European approach to investment in energy supply. For instance, EU-wide or joint cross-border competitive auctions for renewable capacity could achieve an EU-wide optimisation of the renewable fleet that reflects cost advantages of energy-rich regions. The EU has already started such auctions in the case of hydrogen (European Commission, 2025[29]). The EU could support such projects with funding from Important Project of Common European Interest. This should be based on rigorous cost-benefit analysis (Chapter 4).
EU countries grant priority network access and dispatching, and limited balancing responsibilities for small renewable energy installations and larger historic renewable installations. Dispatching refers to a short-term change in how a power plant is utilised and comes at the behest of a transmission system operator to prevent bottlenecks in the electricity grid. In periods of high demand, priority is granted to national renewable plants (such as hydro, geothermal and biomass), discouraging imports of electricity, even if it can be imported at lower prices. This constitutes a barrier to the Single Market. All renewable producers should be subject to the same responsibilities and liabilities as conventional energy producers, including taking part in short-term balancing. Hence, priority dispatch for all renewable producers should be phased out and technology-neutral balancing requirements for renewable producers should be mandated.
Permitting times for renewable installations are lengthy as discussed in more detail in the last Survey (OECD, 2023[4]). To shorten permitting times, the EU proposed in 2023 to designate renewable projects as of overriding public interest (European Commission, 2023[30]). Since then, several EU countries such as Germany and Spain have introduced an overriding public interest principle for renewable installations, which was followed by double-digit increases in the volume of permits issued for onshore wind (OECD, 2023[31]; OECD, 2023[32]). However, lengthy permitting times often reflect legitimate environmental concerns. They also result from a technology bias of renewable support towards technologies that require agricultural land and other used land, creating tensions with local populations. A better focus on distributed energy production could ease these tensions, such as installation of solar photovoltaic capacity on unused rooftops in urban areas.
3.4.3. Bolstering investment in electricity grids
Barriers to the deployment of renewables include underinvestment in grids, notably local distribution networks, and lengthy planning and permitting processes (Box 3.3). Permitting times for new grid connections are on average longer than for new renewable installations, which leads to bottlenecks. Moreover, stronger European planning and funding is needed to incentivise investment in cross-border electricity connections.
Grid investment is regulated and needs to be approved by national Ministries. The regulatory framework is very short-term oriented because grid connections are approved only for existing power installations. Moreover, permitting times for new electricity grid connections are on average longer than for new renewable installations, which leads to bottlenecks (ENTSO-E, 2024[33]). Hence, there is a need for a more anticipatory regulatory framework for grid investment. For instance, national authorities could approve grid connections before planned renewable installations are built, as suggested by the Commission (European Commission, 2025[27]). The Commission should provide guidance to EU countries to fasten the permitting process of grid installations for instance by granting permits for connections to planned power installations. Priority should be given to cross-border grid connections, such interconnections in the North Sea and between France and Spain, which would strengthen connections between energy-rich and energy-poor regions in the EU.
Network tariffs accounted for 17% of the average EU household’s electricity bill in 2023 (Eurostat, 2024[34]). Network tariffs are expected to rise to finance the sizeable grid investment needs, which are projected to increase from 0.5% of GDP in 2024 to 0.6% of GDP per year until 2030 (European Commission, 2022[35]). Higher network tariffs, however, will discourage the switch from gas to electricity. Reducing the cost of capital for network companies could help lowering investment costs and thus network tariffs. One solution would be to apply a faster rate of depreciation to provide higher returns early on for investors, which could lower risk premia and capital costs (ENTSO-E, 2024[36]). The Commission announced it will provide guidance to EU countries as to how they can use their public budget to lower network charges in compliance with state aid rules, which is welcome (European Commission, 2025[27]). Another solution is prolonging the cost recovery period for grid expansions.
Accelerating the transition to renewable energy requires significant reforms to the national and sub-national regulatory frameworks for energy markets. Whilst important reforms have been adopted at EU level, EU countries have been slow to implement change. The Commission initiated infringement decisions against 26 of the 27 EU countries in September 2024 for failure to transpose the Renewable Energy Directive, for instance.
Distributed Generation: Renewable electricity often involves decentralised, variable, and geographically dispersed installations, unlike traditional centralised power. Outdated regulatory frameworks, initially introduced for conventional fossil fuel generated electricity, create barriers for innovative business models and hinder renewable deployment. To accelerate progress, regulations must be updated to support distributed systems. The EU’s Directive on Common Rules for the Internal Market for Electricity requires EU countries to develop a regulatory framework that enables market participation of such actors, but its implementation has been slow (see above).
Technology-specific Challenges: Regulatory frameworks need to be tailored to the unique features of renewable energy segments. For example, utility-scale solar installations typically face extensive spatial planning and environmental assessment procedures, unlike smaller rooftop or solar car park installations, which warrant streamlined permitting due to their simpler integration into existing grids. Solar energy production on agricultural land requires tailored local regulations to maintain agricultural land classification.
Local Regulatory Challenges: In most EU countries, sub-national and local authorities are responsible for local permitting procedures, spatial planning rules, and regulations for local distribution system operators such as private solar rooftops. These rules influence the ease of entry as well as the integration of distributed generation into local grids. Efficient permitting procedures, clear spatial planning guidelines, and operational rules for local distribution system operators are essential for renewable energy deployment.
Source: (OECD, 2025[37]).
There are trade-offs between competitiveness and decarbonisation when it comes to network tariffs. Currently, energy-intensive firms pay lower network costs than households in some countries such as Austria, France, and Germany. In contrast, costs between industry and households are more equally distributed in other countries such as the Netherlands (Heussaff and Zachmann, 2025[38]). Lowering energy costs for industry can support competitiveness. However, it introduces an uneven level playing field to the Single Market. It also reduces households’ incentives to invest in electrification such as electric vehicles and heat pumps. The EU announced to provide guidance to harmonise network tariff methodologies to limit distortions to the level playing field in the Single Market, which is welcome (European Commission, 2025[27]).
The EU’s integrated electricity grid allows countries to export their surplus energy, helping to ensure security of supply and lowering energy costs elsewhere. Overall, cross-border electricity trade is estimated to have lowered consumers’ electricity bill by 0.2% of GDP in 2021 (ACER, 2022[15]). Another advantage of an integrated electricity grid is its size, which helps to balance out production across countries, allowing for smoother integration of renewables. This allows to achieve climate targets in a more efficient way without compromising energy security.
However, further progress is needed to connect electricity grids between countries (Figure 3.13, Panel A). The investments announced or underway in new cross-border grids for 2030 only cover about a quarter of the needed EUR 6 billion annual investment (or 0.03% of EU GDP) (ENTSO-E, 2022[39]). Underinvestment in cross-border grids reflects that these projects are often not commercially viable due to regulatory differences across countries and disagreement over cost-sharing arrangements. Overcoming such differences involves higher costs and risks, which national government are not willing to do either. EU funding could overcome such barriers. But the central EU funding vehicles for cross-border grid investment, the Connecting Europe Facility, has an annual budget of less than EUR 1 billion (0.006% of EU GDP). Hence, the EU should reallocate funds to the Connecting Europe Facility to ensure sufficient funding is available for cross-border grid connections for which private funding is not available. This should be done based on cost-benefit analysis.
The EU’s ten-year network development plan identifies borders that should be prioritised for connections based on a cost-benefit analysis (ENTSO-E, 2025[40]). Such EU-wide priorities can receive EU funding. However, projects are proposed and selected with strong involvement of national grid operators, the owners of network infrastructure. National grid operators may have different priorities for grid expansion than a Pan-European grid operator would have. The European Network of Transmission System Operators for Electricity (ENTSO-E) and the EU Agency for the Cooperation of Energy Regulator (ACER) have a more European perspective on investment needs, but they cannot propose projects. The dominance of national interests in project proposal and selection introduces disincentives for most efficient investment in cross-border networks from a European perspective. ACER could be tasked to propose specific cross-border projects that meet cost-benefit analysis criteria.
Note: Panel B, Fmax indicates the maximum flow on critical network elements, respecting operational security limits.
Source: ACER calculations based on ENTSO-E and JAO Auction Tool data.
To open national markets to trade and competition, the EU requires countries to increase the utilization of their existing electricity cross-border capacity to 70% by 2025. However, progress on reaching this target is behind schedule in most countries (Figure 3.13, Panel B) (ACER, 2024[41]). This reflects that national transmission system operators have the discretionary power to apply derogations to soften cross-border capacity targets. In practice, these derogations constitute a major barrier to trade and competition as they reduce access to domestic markets for foreign electricity producers and retailers. Although ACER is responsible for monitoring the fulfilment of cross‑border capacity targets, it does not have powers to enforce such targets. Non-discriminatory access to the EU electricity network is fundamental for more market integration. Hence, ACER should receive powers to enforce cross-border capacity targets, for instance, by overriding national derogations to cross-border capacity targets.
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