EUROPEAN COMMISSION

Brussels, 10.12.2025

SWD(2025) 2000 final

COMMISSION STAFF WORKING DOCUMENT

IMPACT ASSESSMENT REPORT

[European Grids Package]

Accompanying the documents

Proposal for a REGULATION OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL on guidelines for trans-European energy infrastructure, amending Regulations (EU) 2019/942, (EU) 2019/943 and (EU) 2024/1789 and repealing Regulation (EU) 2022/869

Proposal for a DIRECTIVE OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL amending Directives (EU) 2018/2001, (EU) 2019/944, (EU) 2024/1788 as regards acceleration of permit-granting procedures

{COM(2025) 1006 final}
{COM(2025) 1007 final}
{SWD(2025) 2001 final}
{SEC(2025) 2000 final}

Table of Contents

1.Introduction: Political and legal context

1.1.Political context

1.2. Legal context

1.3.Synergies with other EU policy instruments

2.Problem definition

2.1.What are the problems?

2.2.What are the problem drivers?

2.3.How likely is the problem to persist?

3.Why should the EU act?

3.1.Legal basis

3.2.Subsidiarity: Necessity of EU action

3.3.Subsidiarity: Added value of EU action

4.Objectives: What is to be achieved?

4.1.General objectives

4.2.Specific objectives

5.What are the available policy options?

5.1.What is the baseline from which options are assessed?

5.2.Description of the policy measures and options

5.3.Options discarded at an early stage

6.What are the impacts of the policy options?

6.1.Economic impacts

6.2.Social Impacts

6.3.Environmental Impacts

7.How do the options compare?

7.1.Effectiveness

7.2.Efficiency

7.3.Coherence

7.4.Subsidiarity and proportionality

7.5.Summary

8.Preferred option

8.1.Identification of preferred policy option

8.2.REFIT (simplification and improved efficiency)

8.3.Application of the ‘one in, one out’ approach

9.How will actual impacts be monitored and evaluated?

Annex 1: Procedural information

Annex 2: Stakeholder consultation (Synopsis report)

Annex 3: Who is affected and how?

Annex 4: Analytical methods

Annex 5: Competitiveness check

Annex 6: Existing legal EU framework

Annex 7: Implementation reports

Annex 8: Monitoring

Annex 9: Description of policy measures

Annex 10: Comparison of options

Annex 11: Glossary

1.Introduction: Political and legal context

1.2.Political context

Energy network infrastructure plays a crucial role in reinvigorating European competitiveness, ensuring the security of our Union and in the energy transition and decarbonisation. At the same time, the development of energy networks is confronted with new and significant challenges.

Electricity grids will need to serve growing demand linked to clean mobility, heating and cooling, electrification of industry, data centres and the ramp-up of the hydrogen system. Electrification of final energy consumption should increase from around 23% currently to around 32 % in 2030. 1  Member States should aim for an electricity interconnectivity level of 15% by 2030. 2   Networks will need to integrate 2.2-2.4 TW of renewables capacity to meet 2040 EU targets. 3  Grids will need to adapt for the EU to have a more decentralised, digitalised and flexible electricity system with millions of rooftop solar panels and local energy communities sharing resources. By 2040, electricity transmission and distribution grids will require investments of EUR 1.2 trillion and hydrogen networks of EUR 240 billion. 4  Offshore renewables alone should increase by up to 360 GW by 2050 5 , which need to be connected to shore including through necessary onshore grid reinforcements. Hydrogen will be important in decarbonising industrial and transport processes where electrification is not an attainable solution. Hydrogen networks will connect production and demand centres across Europe, where on-site hydrogen production is not feasible.

The Draghi report 6 called for simplifying and streamlining permitting and administrative processes as well as for a coordinated strategic approach to cross-border infrastructure development between the EU and Member States. The Council invited the Commission to propose a strengthened framework for grid planning and rollout to be compliant with EU targets. 7  In its Conclusions of 16 June 2025 8 , the Council called on the Commission to propose a grids package consisting of measures to, inter alia, simplify EU rules on grids, integrate EU-level, regional and national needs, ensure the delivery of projects, develop effective cost sharing mechanisms for cross-border projects of common interest, and assess the need for further legislative proposals to accelerate permitting of energy infrastructure. The European Council in its Conclusions also called for Union-wide long-term investment planning to fully integrate and interconnect the EU electricity market, contributing to the Union’s energy security, and infrastructure protection and resilience. 9  The European Parliament highlighted the importance of modernising and expanding grids, as well as investment into digitalisation, with a focus on integrated cross-sector and cross-level planning. 10  It also emphasises cross-border infrastructure as a condition for successful deepening of the single market and for increasing the Union’s resilience. 11

This initiative responds to the Commission’s commitment in the Action Plan for Affordable Energy 12  to propose a European Grid Package. It should consist of legislative and non-legislative measures to, among others, simplify the trans-European energy networks (TEN-E) Regulation; ensure cross-border integrated planning and delivery of projects, especially on interconnectors; streamline permitting for renewable energy generation, grid, storage infrastructure, and recharging stations for cars and trucks 13 ; enhance electricity distribution grid planning; accelerate the ramp-up of the hydrogen market; boost digitalisation and innovation and increase visibility of manufacturing supply needs. It builds on the 2023 EU Action Plan for Grids 14  that focused on implementing the agreed legal framework to strengthen Europe’s energy networks, and on the 2022 Digitalisation of Energy Action Plan 15 that promoted electricity grid digitalisation.

This impact assessment addresses possible legislative measures for the Grids Package, focusing on grid planning and development for transmission and distribution grids with a cross-border dimension, cost-sharing mechanisms, as well as permitting-related measures covering energy infrastructure, renewable energy generation, storage and recharging stations. It also addresses possible legislative measures to improve the security and resilience of energy infrastructure. The initiative would entail a revision of the TEN-E Regulation on cross-border energy infrastructure, targeted amendments to the revised Renewable Energy Directive (RED) to accelerate permitting procedures for renewable energy, related grids and energy storage, as well as recharging stations. In addition, it would entail limited targeted amendments to the Electricity Directive and Regulation as well as the Gas Directive and Regulation to ensure full alignment and legal coherence as regards the framework for permitting procedures at EU-level. In view of ongoing implementation measures, planning and access to distribution grids 16 and resilient supply chains 17  will be mainly covered through non-legislative measures to be set out in a Communication and in a guidance document on grids connection 18  as part of the Package. In addition, the Commission will come forward with sectoral tripartites on offshore wind and grids as well as on energy storage by the end of this year which will also address supply chain constraints.

1.3. Legal context

The TEN-E Regulation 19 lays down rules for the timely development and interoperability of trans-European energy networks to achieve the EU’s energy objectives. The TEN-E Regulation was revised in 2022 to fully align its scope with the European Green Deal. The TEN-E Regulation is aligned to the provisions of the Electricity Market Regulation 20 and Directive 21 , the hydrogen and gas decarbonisation package 22  as well as the Renewable Energy Directive (revised RED) 23 . The Electricity Market Regulation and Directive set rules for network planning at national level and their efficient use as well as incentives for the use of smart and digital technologies and on grid access and transparency. 

The Gas Regulation, the Gas Directive and the revised RED, constituting the main pillars of the EU’s regulatory framework for hydrogen, aim to enable the integration of renewable and low-carbon gases in the gas system to create a competitive EU hydrogen market and infrastructure. The gas and hydrogen legislative framework brings important policy considerations that require close alignment in the TEN-E Regulation. ENTSO-E, ENTSOG and ENNOH 24 respectively, are required to adopt and publish biennially non-binding Union-wide ten-year network development plans (TYNDPs) to, among others, identify investment gaps, in particular with respect to cross-border capacities. 

The revised RED, as amended in October 2023, sets the permitting framework for renewables, related grids and co-located storage, as well as spatial planning requirements for renewable energy generation, grids and storage infrastructure.

The existing legal framework is in detail elaborated in Annex 6 and the Implementation Report (Annex 7) takes stock of its implementation.

1.4.Synergies with other EU policy instruments

The Grids Package is complementary to other initiatives that aim to create a more integrated European energy market. Energy infrastructure is crucial to achieve the proposed 2040 EU climate target. 25  The Commission proposal for the new Multiannual Financial Framework (MFF) 2028-2034 26  highlights “the vital importance of a genuine Energy Union and well-integrated EU infrastructure networks”, which is reflected in a substantially increased budget proposed for the Connecting Europe Facility (CEF) for Energy 27 . The TEN-E Regulation provides the basis for energy infrastructure projects funded under CEF. 

The Grids Package aims to support the goals of the electricity market legislation by ensuring that infrastructure brings additional socio-economic welfare and to further strengthen efficient use of existing infrastructure. The forthcoming Clean Energy Investment Strategy will cover the future framework for the financing of energy investment. Possible measures to enhance electricity interconnection targets enshrined in the Governance Regulation will be assessed as part of the revision of that Regulation and measures to further support the necessary national investment levels in energy infrastructure. The Grids Package will also complement the Environmental Omnibus proposal that is due end of this year, by proposing complementary sectorial measures that do not preclude the need and utility of the measures under the omnibus.

The 2026 revision of the EU Energy Security Framework will address energy security horizontally, complementing the network specific approach under this initiative. The security-related measures under this initiative also align with and build on the requirements of the horizontal security legislation, including the EU Critical Entities Resilience Directive, the NIS 2 Directive and the Network Code on sector-specific rules for cybersecurity aspects of cross-border electricity flows, and support its objectives and implementation. The Industrial Decarbonisation Accelerator Act will include measures to accelerate permitting of projects to decarbonise energy-intensive industries. Having sufficient grid capacity and timely grid connection is crucial to electrify industry, hence both initiatives are developed in close cooperation. 28  The initiative also complements the Trans-Mediterranean Renewable Energy and Clean Tech (T-MED) Initiative and the Pact for the Mediterranean.

In view of the planned Carbon Capture, Utilisation and Storage (CCUS) Package, the Grids Package will not address carbon dioxide cross-border infrastructure planning. Given a strong link between network planning on a national, regional and local levels and the heating and cooling sector, the recent revision of the Gas Directive requires stronger coordination among sectors. The Grids Package aims to build upon these requirements. In addition, the upcoming Electrification Action Plan and the Strategic Roadmap on Digitalisation and AI in the energy sector as well as the Heating and Cooling Strategy will provide important input for future grid planning. The Package also underpins the Cloud and AI Development Act to attract investment in data centres. 

2.Problem definition

2.1.What are the problems?

The key problems, corresponding drivers and consequences that are relevant for the Grids Package are presented in Figure 1 .

Figure 1: Problem tree

The revised TEN-E Regulation entered into force in 2022, and the revised RED was last amended in 2023 with some, but limited, experience on their implementation and impacts. Despite the recent revision of the TEN-E Regulation, however, the Implementation Report (Annex 7) demonstrates deficiencies in the current framework, in particular as regards scenario development, infrastructure needs identification, cost-sharing arrangements and the permitting framework for PCIs and PMIs. Besides the Implementation Reports (Annex 7), the analysis of the problems and their drivers relies mainly on most recent evidence, including ACER reports, ENTSOs’ TYNDP data and assessments, JRC modelling as well as relevant input from stakeholders and the public consultation on the Europeans Grids Package (Annex 2).

2.1.1.Problem 1: The existing and planned infrastructure projects are not sufficiently targeted to achieve the EU’s energy and climate objectives

There is a substantial gap between our cross-border electricity infrastructure needs for the energy transition and the speed and level of infrastructure development. According to ACER 29 , half of cross-border electricity infrastructure needs for 2030 (32 of 66 GW) have not been addressed under the 2022 TYNDP. The gap is even higher for 2040: 37 GW of 90 GW needed will not be addressed through the current project plans.  

The 2024 TYNDP found that the cross-border infrastructure needs have grown, amounting to 88 GW by 2030 and 108 GW by 2040, and that the 2024 TYNDP projects would still be insufficient to fully address needs, indicating the revision of the TEN-E Regulation in 2022 did not sufficiently ensure infrastructure needs are addressed. 30 Furthermore, ACER points to a mismatch in relation to investments included in the 2022 TYNDP, where capacity needs across certain borders are neglected, but others surpass the identified needs. 31  

Shortcomings in the planning framework lead to investment falling short of the identified needs. Stakeholders (59%) in the public consultation on the Grids Package highlighted insufficient financing as a key barrier to developing grid infrastructure at the necessary pace for the energy (see Annex 2). In addition to insufficient cross-border capacity, planned network developments for transmission grids (one quarter of required investments) and distribution grids (over half of required infrastructure investments) 32  at national level also risk being insufficient for the energy transition. 33  Failing to address electricity infrastructure needs could exacerbate system congestion, both within and between Member States, limiting the capacity to integrate renewable energy sources, industries and businesses, thus impeding system decarbonisation. The shortfall in infrastructure development may undermine security of supply by creating bottlenecks, potentially leading to further market fragmentation and higher energy prices.

As an example, average day-ahead prices in Europe in the period of July to September 2024 at 17:00 UTC showed a price difference of EUR 265/MWh between Finland and Greece (Greece being 6.5 times more expensive). 34  Underlying reasons for price differences within the EU include the lack of flexibility in certain regions, inefficient use of existing grid capacity and insufficient physical interconnection. Price differentials are not only caused by insufficient cross-border connection, but also insufficient national transmission infrastructure. Only two Member States were constantly meeting the 70% Margin Available for Cross-Zonal Trade (MACZT) rule in 2023. 35 ACER 36 pointed out that most limiting factors for cross-border capacity allocation are related to internal bottlenecks. 37  

In addition to insufficient transmission capacity, the existing power system is not optimally used. Smart grid technologies are insufficiently used by TSOs and DSOs. Implementation of such technologies is closely linked to network planning and these solutions have significant potential of freeing available grid hosting capacity at lower cost and more rapidly than infrastructure solutions. Hence, their non-consideration carries a risk of higher cost for end consumers.

The costs of an insufficient or suboptimal energy infrastructure are substantial. The cost of congestion already reached EUR 4.2 billion in 2023 38 , a yearly increase of 14.5%, and costs for renewables curtailment amounted to EUR 7.2 billion in 2024 in 7 countries alone 39 . Increasing queues of connection requests delay the integration of lower cost renewable energy generation, the electrification of the transport sector (charging points) and electrification of industry. In 2024-2025, 1,700 GW of renewable energy and hybrid projects were waiting for grid connections. 40  

The development of the hydrogen sector, especially electrolysis, will impact the power system both in terms of planning and operation. 41  ACER’s 2024 European hydrogen market monitoring report 42 called for more accurate demand forecasting during the planning phase, along with proper monitoring and adjustments during implementation to avoid infrastructure oversizing and underutilisation. At the same time, industrial projects frequently lack timely access to hydrogen infrastructures and affordable hydrogen, pointing at the importance of timely and sufficient grid expansion combined with early and accurate communication of industrial needs. There is a strong link between network planning at national, regional and local level, requiring strong coordination among sectors – electricity, gases including hydrogen, but also transport and heating and cooling sectors, where relevant. Not considering mutual interlinkages between sectors and planning levels leads to sub-optimal planning. 

2.1.2.Problem 2: Lengthy implementation of infrastructure, renewable energy and storage projects as well as recharging stations

Lengthy project implementation contributes to the gap in necessary electricity grid developments. Delays jeopardise the connection of new industries and businesses, the electrification of existing ones, it increases the risk and cost of new affordable energy generation projects, in particular from renewable energy sources, and, ultimately, it impacts the energy costs paid by consumers, including industrial decarbonisation projects. 43  The implementation of transmission and distribution infrastructure projects takes several years, during which they can come across challenges resulting from economic, technical and administrative complexities. The completion of electricity infrastructure projects takes 3.5-7.5 years for distribution grids and 7-10 years for transmission grids 44 .

Long delays increase overall project costs due to increasing inflation, higher capital cost due to uncertainties in projects realisation, higher prices of supplies due to global market uncertainties, interest rate, lack of revenues if the commissioning of a project is delayed due to slow permitting, and penalties for not meeting deadlines. Supply chain constraints are also often mentioned as cause of delays, including in in the public consultation (Annex 2). 45  Manufacturing industry points to lack of visibility and certainty of project execution making it challenging for offtakers to commit to producers. 46  The Commission has adopted several initiatives to address supply chain constraints and the availability of skilled workforce in recent years including the Net-Zero Industry Act and ongoing measures of the Grids Action Plan, and the EIB has adopted a dedicated Grids Manufacturing Package. 

Renewable energy and storage electricity projects, as well as recharging stations, also face delays, which hinder their fast deployment and risk jeopardising the achievement of the RED targets. While the pace of new installations has accelerated in the last years, it still falls short of the level required to achieve the EU climate and energy objectives and progress is uneven across Member States. In 2023, the EU achieved 24.5% renewables share in total final energy consumption, ranging from 11.6% to 66.4% depending on the Member States. In 2024, new renewable energy capacities installed in the Union reached 78 GW, still falling short from the KPI set in the Clean Industrial Deal to install 100 GW of renewable electricity capacity annually up to 2030. However, even if the rate of deployment of renewable energy generation was in line with such objectives, renewable energy installations still face barriers for their effective integration into the system and their actual consumption in the Union’s energy demand. 

The Emergency Regulation 47 , which included measures to facilitate the deployment of RES and grid projects, initiated during the energy crisis (2022-2023), accelerated renewable energy deployment in the EU, but progress is still insufficient. This remains the case despite the package of measures to accelerate permitting for renewables adopted in the revised RED. Difficulties, and delays, in reaching agreements on cost sharing for energy infrastructure projects amongst potentially benefitting countries further postpone or halt investments. 

2.1.3.Problem 3: Concerns over infrastructure security

Recent incidents in the Baltic Sea, including those involving the Nord Stream 2 (September 2022), the Balticconnector pipeline (October 2023) and the Estlink 2 power cable (December 2024), highlight the risk of hostile actors targeting energy infrastructure. Likewise, cyber-security incidents against energy infrastructure have increased over the past years. Such targeted attacks pose substantial risks to the stability and resilience of our energy system. The outage of the Estlink 2 interconnector between Estonia and Finland in 2024 resulted in repair costs of EUR 30 million (and a loss in socio-economic benefits of EUR 94 million), and the second outage in 2025 in total repair costs of EUR 50-60 million 48 . 

Beyond deliberate acts of sabotage, there is an increasing recognition of the risks stemming from non-deliberate incidents, including natural hazards and climate-related impacts. This was noted by stakeholders in the public consultation: 38% of respondents agreed that the EU legal framework does not sufficiently addresses such emerging risks (Annex 2).

Whereas problems 1 and 2 lead to direct consequences in terms of renewable energy curtailment, higher greenhouse gas emissions, higher energy system costs as well as longer grid connection queues undermining electrification, problem 3 is linked to higher risks in terms of energy supply disruption which, if they occur, can endanger EU independence and lead to significant costs in terms of socio-economic welfare losses as well as political, social and economic disruptions.

2.2.What are the problem drivers?

The problem tree (Figure 1) illustrates how the drivers relate to the identified problem 1 to 3.

2.2.1.Driver 1: Infrastructure needs not identified and inconsistencies across sectors

Driver 1 relates to three root causes: weak scenarios as a basis of infrastructure planning, inconsistencies between different sectoral and regional/national infrastructure planning exercises, as well as lack of clarity on identified needs. 

Scenarios not sufficiently robust: TYNDP scenarios constitute the first step for identifying the infrastructure needs as well as for assessing the benefits of projects. Despite the introduction of ACER framework guidelines 49 for the establishment of scenarios and the Commission approval of final scenarios, the current TYNDP scenarios have various shortcomings. They are subject to significant delays in each planning cycle 50 and assumptions are regularly criticised by stakeholders for being unrealistic, insufficiently transparent, not aligned with the NECPs, or even biased given the central role of the ENTSOs in this process 51 . The two-year cycles do not allow for sufficient time for effective feedback loops necessary to build robust scenarios. 52  This undermines the credibility of the infrastructure planning process and the robustness of needs identification and selection of priority projects. 53  In more than half of Member States, scenarios used by DSOs are not available (and not coordinated), impeding proper network planning. 54 Network planning cannot serve sufficiently for future connections, if it is not based on robust scenarios of future evolution. 55  

Inconsistencies between different levels and sector planning: The hydrogen and gas decarbonisation package strengthened cooperation between national transmission and distribution levels increasing consistency of related planning for electricity and gas, as well as other relevant sectors including heating and cooling. However, this national-level alignment does not avoid discrepancies between EU and national planning, as the scenarios used at the EU and national levels are not necessarily consistent. 56  Insufficient cross-sectoral planning on a European level risks an inadequate assessment of infrastructure needs and the costs and benefits of individual projects, which can entail substantial cost increases, e.g. through inefficiently high generation and back-up capacity expansions. 57  Several Member States’ scenarios for network planning seem not aligned with the EU’s 2030 targets. 58  On a national transmission level, planning is required only for a 5–10-year horizon, which may be insufficient given the lead times for transmission projects. 

Not all infrastructure needs are properly identified and prioritised: The current identification of infrastructure gaps does not consistently analyse all potential infrastructure needs at national and EU level. There are substantial differences between electricity infrastructure needs identified for certain borders in respective planning cycles. Moreover, under the current ‘bottom-up’ approach (Annex 6), projects submitted by national TSOs and third-party project promoters for the EU-wide TYNDP are assessed as possible needs. 59 While this approach, by default, confirms the need for most of the proposed projects, it fails to identify the optimal design of infrastructure. In addition, the involvement of Member States, ACER and NRAs is limited in certain steps of the planning processes preventing validation of critical steps. The public consultation indicated mixed views on the extent to which the TYNDP identifies all cross-border infrastructure needs, with 34% of respondents agreeing (companies 37%, business associations 33%, NGOs 14%, public authorities 20%). 60

In the current TEN-E framework, interconnections with a third country need to demonstrate significant benefits at Union level. The PMI selection processes have shown that this criterion is difficult or impossible to fulfil for certain electricity interconnections, when their system benefits go mostly to the third country. This is of particular concern for Energy Community countries including Ukraine and Moldova, with whom interconnections impact the EU electricity market and may improve system stability and resilience. The framework does not account for benefits for the Energy Community of projects between EU and contracting parties. 61  

2.2.2.Driver 2: Identified electricity infrastructure needs are not optimally addressed

Driver 2 encompasses two root causes: identified infrastructure needs are not systematically followed up with possible projects and non-wired solutions are not considered as priority. 

Not all identified infrastructure needs are addressed with possible projects, resulting in significant gaps: The TYNDP does not have a procedure to address cross-border or national gaps identified in ENTSO-E’s infrastructure gap report. Consequently, new projects do not necessarily reflect what should be prioritised to fill the identified gaps. ENTSO-E identified 25 new projects in the 2024 TYNDP that aim to address a gap identified in the 2022 TYNDP. However, there remain borders where no new project has been proposed to address identified gaps. This was highlighted by stakeholders as part of the public consultation, where 44% of respondents (companies 37%, business associations 43%, NGOs 86%, public authorities 50%) indicated that the TYNDP process falls short in addressing relevant projects to close infrastructure gaps (see Annex 2).

Member States may be reluctant to support investments in new cross-border infrastructure due to national economic and political considerations. Even if a new interconnection project demonstrates overall welfare gains, it may contribute to higher wholesale prices in certain Member States due to price convergence across borders. In addition, consumers need to pay for the investments in new cross-border infrastructure through higher network tariffs. By contrast, the benefits in terms of generation surplus and congestions rents may only indirectly reach consumers. Thus, there may be a misalignment between national and EU-level incentives for a certain interconnection project which contributes to identified infrastructure needs not being optimally addressed.

The electricity planning framework at the EU and national level fail to make full use of non-wired solutions 62 as alternatives to grid expansions. While the TEN-E Regulation requires alternatives to grid development to be listed in the grid planning, there is no obligation to follow up with concrete projects, hence remaining rather ineffective. 63 While there is a requirement both for transmission and distribution grid planning to include flexibility and demand response, there is no explicit requirement to first consider non-wired alternative solutions, accompanied by a CBA. 64

For internal transmission, the TEN-E Regulation requires projects to provide at least 500 MW impact in terms of cross-border capacity increase to prove their cross-border relevance. This threshold introduced in 2013 does not fully reflect the state of play of the EU electricity market where the average physically used capacity of interconnectors in Europe is 417 MW 65  per border between two countries. Therefore, the current threshold requires more than 100 % increase in average cross-border capacities. There is hence a risk that (smaller) projects which could increase capacities for cross-border trade are not adequately identified and supported. For smart electricity grids, while the last TEN-E revision simplified the rules for application of new project proposals, the number of project applications has not increased significantly.

2.2.3.Driver 3: Approach to the integration of renewable and low carbon gases not fully aligned with recent policy updates

Blending of hydrogen with natural gas risks diverting limited, costly renewable or low-carbon hydrogen from its priority use as a feedstock for industry and air and maritime transport, which cannot use blends. Blending poses challenges for gas quality, adaptation of equipment, and cross-border exchanges. Due to the high hydrogen costs compared to its energy value, blending increases costs for industry and households, and risks cross-subsidisation between users that benefit from injection or delivery and the users bearing the system costs.

These considerations have underpinned an evolving policy landscape, which is in particular reflected in the 2024 Gas Regulation and Directive. These legal acts consider that the production and use of hydrogen in its pure form and its transportation in the dedicated hydrogen system should be prioritised over the blending of hydrogen into the natural gas system which should be a last-resort solution (Annex 6). Yet, the vast majority of projects submitted in the 2023 and 2025 PCI selection process in the smart gas grid category aimed at high levels of hydrogen blending. Beyond issues of consistency with the latest policy developments, these projects also raised issues of interaction with Article 31 of the TEN-E Regulation, which enshrines the principle that for dedicated hydrogen assets converted from national gas assets, the transport or storage of a predefined blend should only be allowed for a transitional period ending on 31 December 2029.

As for the integration of biomethane, it is produced locally and injected at distribution level. Therefore, the cross-border impact of such projects is expected to be limited in most cases, or indirect. The current legal criterion that a smart gas grid project must have significant cross-border impact is purely formal in that it requires the involvement or close association of at least two TSOs that ensure interoperability. This falls short of ensuring in all cases a tangible significant cross-border impact.

Finally, whilst the smart gas grid category of the TEN-E Regulation is aimed at investment in digital equipment and digital installations to smarten the natural gas network for enabling the integration of renewable gases, projects submitted for PCI status have included substantial network elements going beyond what is indispensable for the functioning of such equipment and installations. These projects pose a risk of “greenwashing” and circumvention of the discontinuation of support to natural gas grids as decided with the TEN-E revision in 2022.

As for electrolysers, the current definition in the TEN-E Regulation — with a minimum threshold capacity of 50 MW— makes it difficult to demonstrate any meaningful cross-border impact. A substantial proportion of electrolysers that were PCI candidates for the Union list were planned for direct industrial use rather than fulfilling cross-border objectives (Annex 7), contrary to TEN-E Regulation.

2.2.4.Driver 4: Ineffective mechanisms for cost sharing for cross-border infrastructure projects 

Driver 4 encompasses the root causes related to current practices of cost sharing and benefits materialising increasingly outside the host countries of energy infrastructure projects.

While the current EU framework already includes instruments to facilitate investments in such cross-border projects, it has not been used very effectively. The TEN-E Regulation establishes a cross-border cost allocation (CBCA) framework. The CBCA tool has, however, so far only been used for the process of applying for CEF grants. 66 Therefore, the CBCA framework has been applied to relatively few projects. In addition, the CBCA decisions have primarily followed a territorial cost allocation principle (or a 50/50 split between hosting countries), which does not ensure that costs are shared in proportion to benefits. Since 2014, fewer than 10% of CBCA decisions have resulted in cost allocations involving non-hosting countries. 67  Two main causes have been identified. First, non-hosting countries are often engaged too late, being presented with the results of the benefit distribution and the cost-sharing request without being involved in the actual assessment. Second, there are insufficient tools and incentives for non-hosting countries to engage in this process, creating the possibility of free riding. This was confirmed by the public consultation, with 38% of the participants (companies 40%, business associations 37%, NGOs 36%, public authorities 20%) agreeing that the CBCA framework is not fit for purpose 68 citing its complexity, lack of transparency, and failure to incentivise cooperation among non-hosting countries as key issues.

As cross-border infrastructure becomes more integrated, the number of projects with benefits occurring outside the hosting Member States is expected to increase. A growing number of projects show that benefits will increasingly occur beyond hosting Member States, for instance in relation to offshore cross-border or hybrid projects. 69 As a result, allocating costs solely based on the territorial principle may risk these projects being delayed or not materialising. 

The TEN-E Regulation provides that PCI investment costs, when under the competence of NRAs in the Member States concerned, shall first be covered through congestion income 70 or other charges before any remaining costs are passed on to network users via network tariffs. However, in practice, both the application of congestion income and the resulting tariff impacts are confined to the hosting countries. This leads to a misalignment between where the costs are borne and where the benefits of the infrastructure are realised.

As for hydrogen infrastructure, there is currently no practical experience, given the early stage of hydrogen market development. The CBCA mechanism in the hydrogen sector will only become relevant once NRAs become competent for hydrogen infrastructure with the implementation of the hydrogen and gas decarbonisation legislative package.

2.2.5.Driver 5: Permitting procedures for energy projects take too long

Despite the introduction of permitting acceleration provisions in the energy acquis, important bottlenecks remain slowing down the permitting of infrastructure, storage and renewable energy projects and recharging stations. Electricity transmission grids take around 10 years for completion, of which permitting accounts for more than half of the time needed. 71  Permitting was ranked as the leading obstacle to ensuring Europe’s grid develops as needed for the energy transition by 78% of respondents to the public consultation (Annex 2). 

According to ACER’s 2023 report on the progress of PCIs, the most reported cause for delayed implementation is a delay in the permit granting procedure. In 2023, 26% of electricity PCIs were delayed by on average 12 months against their initially planned commissioning date. This share was fairly stable since 2020 despite some progress reported in the most recent ACER report with permitting accounting for approximately 51% of the total implementation timeline. 72  The clarifications and added flexibility introduced in the 2022 revision of the TEN-E Regulation have not led to substantial acceleration of procedures. However, the impact of introducing new acceleration measures was evident from when the Regulation was first introduced in 2013, leading to substantial acceleration of permitting procedures and ensuring the permitting of most PCIs falls under the maximum duration of the regulation. As reported by ACER in 2020, the average duration of permit granting for electricity transmission PCIs is about 3 years where permitting started after the entry into force of the Regulation and 9 years where projects started before, indicating a marked reduction. 73

Energy infrastructure projects often cover long distances involving many sections and authorities leading to challenges in terms of coordination among authorities and potential delays of implementation due to delays due to delays in permitting for sections of the project. In 7 Member States the permitting of these projects takes between 18 and 24 months, and in 11 Member States it takes over 24 months 74 .. For 7 Member States the general duration of permitting procedures is unclear and often depending on the project type.

Similarly, permitting of renewable energy projects can take up to 9 years depending on the Member State and technology. 75 Storage installations can take from 1-7 years depending on the technology. 76  The permitting for construction or transformation of recharging stations along highways and in depots can take up to 2 years in some Member States. 77  In 2020-2021, administrative and grid-related obstacles made up about 46% of identified barriers to renewable energy deployment because of incoherent administrative systems among multiple authorities, inadequate staffing in authorities, the duration of environmental assessments, public acceptance, limited digitalisation and data availability, administrative and judicial challenges. 78

Important measures were adopted in 2022 and 2023 to address some of these root causes. In December 2022, an Emergency Regulation was adopted to accelerate permitting for renewable energy and related infrastructure projects, 79 which was partially prolonged in December 2023 80 until 30 June 2025. This Regulation introduced binding and optional measures to accelerate permitting in a directly applicable legal instrument, including amendments to EU rules on environmental impacts assessments, shortening of deadlines and identification of acceleration areas. Germany has made an extensive application of the measures in this Regulation, in particular the voluntary ones, which has resulted in a substantial acceleration of permitting. In 2024, Germany approved approximately 14-15 GW of additional installed onshore wind capacity77, which represents an 85% increase compared to the previous year and which almost equals the total new installed wind capacity in Europe in the same year. 

In 2023 the revised RED was adopted 81 , with several measures to simplify and streamline permitting procedures, including simpler and shorter procedures, including targeted rules for specific types of projects such as repowering or small-scale installations; and new measures on spatial planning including the designation of acceleration areas where environmental impacts are lower and therefore procedures can be faster. Despite these recent measures, in 2025, the same permitting related bottlenecks were identified during the Implementation Dialogue on permitting held by the Commissioner for Energy and Housing on 11 June 2025. Moreover, in a recent report on the state of regions and cities, 82 one of the demands of regions and cities to Europe was the acceleration of permitting for renewables and they indicated administrative delays as one of the main obstacles to timely deployment that remains. At the same time, they asked the development of a harmonised EU-wide digital permitting system, which they believe reduce bureaucracy and support faster local approvals, echoing our proposal for further digitalisation and centralisation of the permitting procedures.

Several factors contribute to this. First, the revised RED did not address (or did only partially) all issues which delay permitting and integration of renewables, such as permitting for storage or recharging stations, public acceptance and digitalisation of procedures. Second, the revised RED included only some of the measures of the Emergency Regulation but lacks several important measures included therein which have ceased to apply, such as those to expand the priority of renewable energy projects beyond environmental aspects and to streamline compliance with certain environmental rules. Given the positive acceleration observed in Germany as a result of the application of the Emergency Regulation, the fact that the revised RED does not include all the measures of the Regulation calls for additional measures to ensure the necessary acceleration of renewable energy installations. Third, while the transposition dates for the relevant permitting provisions of the RED were July 2024 and May 2025, the available information shows varying results among Member States regarding implementation 83  and shortcomings in the application of rules. 84  The full implementation of the existing framework is still ongoing, but the feedback received by stakeholders shows that even in Member States where the existing framework has been transposed and is being implemented, there are bottlenecks that hinder fast permitting and deployment of the renewable energy projects. These are connected to a degree with the first two reasons mentioned above. Therefore, the long permitting procedures causing a slow project implementation can be attributed not only to the lack of complete and correct implementation of the existing framework in Member States but also to issues that have not been addressed fully or partially in the current legal system.   

Amongst the causes for lengthy permitting procedures, environmental assessments have been identified repeatedly as the step most prone to delays. 85  The Emergency Regulation and the revised RED introduced targeted measures to ease certain obligations stemming from EU legislation regarding environmental assessments, including through the introduction of the presumption of overriding public interest, exemptions from environmental impact assessment (EIA) for certain projects and by introducing deadlines for the permitting procedures including the environmental assessments. They did not, however, fundamentally address the way such assessments are conducted. Overall, the average duration of the EIA for projects in general (not renewable energy-specific) is estimated to be around 20.6 months 86 , thus affecting the ability to comply with the permitting deadlines in the revised RED (Annex 6). 87  According to stakeholders, the legal framework for environmental assessments leaves room for ambiguity and different interpretations by Member States. This leads to iterative interactions with diverse authorities, in some cases requiring applicants to address different administrative bodies for different parts of the assessment and repeated demands for additional assessments. In some Member States, the timeline for the EIA is unclear lacking precise deadlines and subject to multiple requests for reassessments and additional assessments. In the public consultation, a majority of respondents supported simplifying and streamlining environmental assessments (Annex 2).

Further, inefficient and ineffective public participation processes, leading to opposition in the form of administrative and judicial challenges continue to contribute to lengthy implementation. 88  Despite the general obligation to promote public acceptance introduced in the revised RED, lack of public acceptance remains a primary barrier to renewable energy permitting and thus market uptake. Studies and stakeholders 89 highlight the importance of transparency, early engagement of the public, its procedural participation, and a fair distribution of benefits as central to public acceptance. 90  However, measures aiming to ensure meaningful and early public consultation have faced problems in implementation linked to doubts over their interpretation and the procedural phase in which the consultation is inserted.

Limited resources in national permitting authorities are regularly voiced as one of the main factors contributing to delays in permitting procedures. Permitting authorities often do not have enough staff to process applications and/or lack the necessary technical expertise, for instance to handle the unclarity of environmental requirements and land use conflicts. Smart grid projects are a common example of project types affected by such limitations. These projects are comprised of different decentralised assets and are routinely not considered as a single project by competent authorities. Further, permitting procedures for renewable energy projects often require multiple permits awarded by different authorities (either in parallel or subsequently) and the lack of coordination mechanisms is an important bottleneck slowing down procedures. Digital resources to process applications are underused by authorities.

Moreover, the permitting rules for electricity storage under the revised RED have a narrow scope only covering co-located storage and not storage in general or so called “hybrid projects” despite its increasingly important role for system flexibility. Similarly, a lack of clarity on permitting for recharging stations for electromobility is creating undue complexities and delays (Annex 4). While the Alternative Fuels Infrastructure Regulation (AFIR) regulates recharging stations, it does not include permitting procedures. 91  This hinders the fast deployment of recharging stations and in turn the uptake of electric vehicles, which can serve as important source flexibility in particular as smart and bidirectional charging grows.

Overall, the permitting regime of energy projects is a frontrunner in terms of accelerated procedures.. However, this advanced starting point implies that many of the measures planned or recently adopted in other sectors 92 are already in place in the energy sector. The current permitting framework has not addressed all necessary bottlenecks to remove permitting from being a key barrier to the timely deployment of the projects necessary to reach the EU energy and climate targets.

2.2.6.Driver 6: Rising malicious physical and cyber-attacks on interconnectors, along with digitalisation heightening vulnerability

The frequency and sophistication of hostile acts undermining the security of the EU have increased. Hybrid campaigns 93 targeting the EU have intensified, featuring acts of sabotage targeting critical infrastructure, including in the energy sector.

Increasing system digitalisation of the energy system, combined with the evolving geopolitical context, creates substantial risks for interconnectors to be exposed to cyberattacks and cybersecurity incidents. According to Eurelectric, cyberattacks in the power sector doubled between 2020 and 2022, with 48 successful attacks targeting Europe’s energy infrastructure in 2022 alone. 94 Such acts of sabotage, which may form part of broader hybrid campaigns, represent a significant risk to the operational security resilience of the EU’s energy infrastructure and the energy security of Member States, and may directly affect access to heating, electricity, and essential services. A substantial share of existing cross-border energy infrastructure needs to be upgraded to strengthen its resilience against such potential failures.

While the EU horizontal framework on protection of critical infrastructure and cybersecurity 95 is comprehensive, it has yet to be meaningfully integrated into the TEN-E framework. Implementation of the related rules and requirements are currently not monitored in the context of the PCI/PMI framework and the TEN-E lacks the tools to operationalise its implementation in the EU cross-border energy infrastructure policy, especially for existing infrastructure. 96  

2.2.7.Driver 7: Increased exposure to foreign influence over cross-border energy infrastructure

In recent years, there has been increasing interest from third country actors to invest in EU energy infrastructure, notably interconnectors. While foreign investment can bring benefits such as increased financing options for capital-intensive projects, it can also increase the EU’s exposure to energy security related risks such as disruptions or reduced reliability of cross-border flows, in particular when such foreign investments originate from third countries with diverging geopolitical interests from the EU.

Foreign ownership or control over interconnectors can influence key decisions regarding infrastructure operation, maintenance and future expansion. This can be used to exert political or economic pressure, potentially compromising Member States’ autonomy in managing their security of supply. For instance, operational decisions could be manipulated to create artificial bottlenecks, prioritise certain energy flows, or delay necessary maintenance or upgrades.

2.3.How likely is the problem to persist?

The problems and drivers are likely to become even more important in the short and mid-term.

Problem 1: Under the current framework the gaps in cross-border and related internal energy infrastructure will persist or further aggravate given the non-identification of infrastructure needs and/or projects to address them. The further electrification of the energy system combined with an increased share of renewable energy generation carries a substantial risk to further increase grid connection queues, renewable energy curtailment and overall system costs.

Problem 2:  Adopted and planned initiatives such as the revised RED and the Hydrogen and Gas Package have tackled long permitting procedures for certain key projects. However, inefficiencies under the current permitting system 98 are expected to persist for PCIs and PMIs. Only a minority of Member States have made use of integrated or coordinated schemes leading to coordination delays and misalignment of permitting schedules and public consultations. Specifically for the permitting of renewable energy projects, the expected acceleration in their deployment, in line with the objectives of the revised RED, is already increasing the pressure on permitting authorities and is expected to increase the number of requests that such authorities will have to process. The permitting obstacles are expected to persist despite new rules still being transposed. Moreover, full implementation of the existing measures risks not addressing all the issues, particularly given the ambitious key performance indicators set in the Clean Industrial Deal of installing 100 GW of renewable energy yearly and reach an economy electrification rate of 32% until 2030. In addition, electricity infrastructure projects (other than PCIs and PMIs), storage (other than co-located storage), including pumped hydropower storage, and recharging stations, continue to be subject to different national or even local permitting provisions. Finally, under the current framework, investments will happen in a sub-optimal, uncoordinated manner at a higher cost, reinforced by the absence of effective cost sharing tools.

Problem 3: it is expected that the threats to physical and cybersecurity would rather increase without sufficient protection against possible incidents. The problem and possible consequences is reinforced by possible exposure to certain foreign investors.

3.Why should the EU act?

3.1.Legal basis

Article 170 of the Treaty on the Functioning of the European Union (TFEU) stipulates that the ‘Union shall contribute to the establishment and development of trans-European networks’, including in the area of energy infrastructure. In addition, the ‘Union shall aim at promoting the interconnection […] of national networks’. The TEN-E Regulation is based on Article 172 TFEU, which provides for the legal basis to adopt guidelines covering the objectives, priorities and broad lines of measures envisaged in the sphere of trans-European networks as set out in Article 171. The guidelines are to identify PCIs that are necessary for making the TEN-E fit for purpose and set the conditions under which the EU may financially support the PCIs.

Article 194 of the TFEU stipulates that the Union shall aim to promote the development of new and renewable forms of energy and in accordance with Article 192 of the Treaty on the Functioning of the European Union (ex. Article 175 TEC), to decide on actions in accordance with the Union policy on the environment. The revised RED is based on Articles 194 and 192 of the TFEU, which constitutes the legal basis to establish measures to achieve the objectives of climate neutrality and decarbonisation of the economy via clean energy technologies. The proposed measures relate to the fields mentioned above aiming to develop trans-European networks and promoting the faster deployment and integration of renewable energy (Annex 9).

3.2.Subsidiarity: Necessity of EU action

Energy transmission infrastructure and, increasingly, electricity distribution grids have a trans-European or at least cross-border nature or impact. The TEN-E Regulation has contributed to achieving results regarding the EU energy market integration, competition and security of supply. A framework for regional cooperation across Member States is necessary to develop cross-border energy infrastructure. National regulation and planning are not sufficient as individual national administrations do not have the power to deal with cross-border infrastructure planning. The internal network elements significantly influence the possibilities of cross-border infrastructure development, which in turn affects cross-border trade. More closely coordinating national and European planning is necessary due to the character of the EU’s meshed network and to build a more efficient energy system. Further, as regards electricity transmission and distribution infrastructure, despite the recognised need to accelerate their development to integrate renewables into the system 99 , there is currently no permitting acceleration provisions at the EU level that mirror those available to gases infrastructure in the Gas Directive.

Reaching the EU energy objectives without additional action on the RES deployment at EU level would not be cost efficient. An EU approach is needed to provide the right incentives to Member States to accelerate, in a coordinated way, the energy transition towards a more energy-efficient energy system largely based on renewables. The revised RED already includes provisions on permitting for renewables, co-located storage and related grids. EU action is needed to further improve that regulatory framework in a coordinated way, bringing faster permitting procedures for renewables, storage and recharging stations, ensuring alignment among Member States and the good functioning of the Energy Union.

3.3.Subsidiarity: Added value of EU action

The TEN-E Regulation has provided additional value compared to what could have been achieved at national or regional level alone. More than 100 projects were completed thanks to the PCI status between 2013-2025. The accelerated electrification, decarbonisation and digitalisation of industry and deployment of renewable energy projects call for the reinforcement of the energy infrastructure at an unprecedented pace, that cannot be met by national measures alone. More effective cross-border planning will improve the integration of clean energy sources as well as meeting electricity market needs, which would help the EU reach its energy and climate targets. A more integrated market encourages the development and uptake of innovative technologies for transmission and distribution of energy and contributes to system flexibility and security of supply. This can result in a more efficient network and improve cross-border trade for a more cost-efficient and secure energy system.

EU action on renewable energy under the revised RED brings added value because it is more efficient and effective than individual Member States’ actions, avoiding a fragmented approach by addressing the transition of the European energy system in a coordinated way. It ensures net reduction of greenhouse gas emissions and pollution, protects biodiversity, harnesses the benefits of the internal market, fully exploits the advantages of economies of scale and technological cooperation in Europe, and it gives investors certainty in an EU-wide regulatory framework. By acting at EU-level in combination with action at Member State level, several barriers to public and private investments can be tackled supplementing and reinforcing national and local action.

4.Objectives: What is to be achieved?

The objective of the initiative builds on the general objective of the current TEN-E Regulation (Annex 7) but develops it further by including the related topic of the development of renewable energy, storage and recharging stations. By a stronger focus on ensuring efficient and effective infrastructure planning, extending the timeframe beyond 2030 as well as security of cross-border energy infrastructure, the revised general objective reflects the new political context.

4.1.General objectives

The general objective is the timely and efficient development and interoperability of resilient energy infrastructure, renewable energy and flexibility, including storage and recharging stations, across the EU. This will enable the EU to deliver on its energy and climate objectives, including ensuring energy affordability through better interconnectivity, leading to price convergence, reduced wholesale electricity prices and lower volatility of electricity prices, as well as to accelerated connection of generation and demand.

4.2.Specific objectives

The general objective can be disaggregated into four specific objectives, which are to be pursued by the policy options are to address the problems and underpinning drivers identified in Section 2, namely to:

·Ensure that projects included in network development plans and selected as PCI/PMIs address appropriately and effectively identified infrastructure needs ensuring timely and efficient development of energy infrastructure. The aim is to ensure clear matchmaking of projects included in network development plans with the identified needs. Selected PCI/PMIs projects should be assessed and validated based on clearly defined criteria, demonstrating that they effectively address infrastructure needs identified. This should lead to a reduction in the gap between planned infrastructure projects in the TYNDP and the identified cross-border infrastructure needs over time.

·Facilitate the use of cost-sharing tools for faster deployment of cross-border infrastructure projects, leading to an increased use of cost-sharing tools and a reduction in project deployment time.

·Shorten and simplify permitting procedures for energy infrastructure, renewable energy and storage projects, as well as recharging stations, leading to shorter time to obtain necessary permits, making it feasible to meet the existing deadlines, and simplified permit requirements.

·Enhance physical and cyber security and resilience of cross-border energy infrastructure (PCIs/PMIs) by increasing the number of protection and resilience equipment and installations on critical network elements.

Figure 2 illustrates how the problem drivers relate to the objectives of the initiative. The last column indicates how the policy options (Section 5) relate to the problem drivers and objectives.

Figure 2: Problem drivers, specific objectives, and general objectives

5.What are the available policy options?

5.1.What is the baseline from which options are assessed?

Under the baseline scenario, the TEN-E Regulation, the Electricity Directive, Electricity Regulation, the Hydrogen and Gas Package are assumed to continue to apply as currently in force (Annex 6). The proposal for an EU climate target 2040 and the possible revision of RED, the Energy Efficiency Directive as well as energy security framework should also be taken into account.

Regarding network planning and needs identification, the frequency of the TYNDP process (every two years) remains unchanged and the existing challenges in terms of delays in the process (scenarios, needs and project assessment) will likely continue to negatively affect the PCI and PMI selection process due to required input not being available on time. The infrastructure needs identification process remains primarily a bottom-up analysis. The granularity of the needs assessment remains the same. Uncertainties about completeness and robustness of the needs identified continue to be unaddressed. Acceptance and credibility of the results of the TYNDP and the needs assessment likely remains weak due to limited involvement of Member States or NRAs. While cross-border energy infrastructure will continue to develop under the current framework, it is expected to occur in a non-optimal manner due to the issues identified in section 2, therefore also failing to address growing grid congestion and renewable energy curtailment which could become as high as 310 TWh by 2040 in the BAU scenario.

With regard to cross-sectoral planning, once the gas package is transposed and implemented, it will provide for stronger cross-sectoral coordination. However, the implementation might be challenging, also due to missing mirroring requirements on the electricity side and technical constraints under the two-year TYNDP cycles. These requirements demand national-level coordination between TSOs and DSOs on scenario development across the electricity, hydrogen, and gas sectors as well as alignment with the NECPs and, where applicable, consideration of local heating and cooling plans, and alternative fuel infrastructure needs.

On cost sharing, the current TEN-E framework to facilitate cost-sharing agreements for cross-border infrastructure projects continues to apply. For PCIs/PMIs that have reached sufficient maturity to start the construction within 36 months, project promoters can submit an investment request, including cross-border cost allocation. Experience shows that the framework is unlikely to lead to cost-sharing agreements between hosting and non-hosting beneficiary countries.

On permitting, for energy infrastructure assets, the dedicated permitting requirements and acceleration provisions for PCIs and PMIs (TEN-E Regulation), and grid assets necessary to integrate renewables (revised RED), will continue to apply. Permitting for hydrogen infrastructure will start to be regulated with the transposition of the Gas Directive (deadline 2026). For the permitting of renewable energy and co-located storage installations, the baseline is the revised RED while there is no permitting framework for non-co-located storage and recharging stations. Implementation of these measures would be supported by the Commission through ongoing transposition checks and continuous engagement with Member States. While for renewable energy projects, co-located storage and their related infrastructure, the full transposition and implementation of the permitting framework under the amended RED is expected to bring some positive results, as explained in the problem section, this change will not be enough to meet our 2030 goals. The remaining issues in parts of the permitting procedures not touched upon before keep hindering the proper implementation of the permitting framework. This is in combination with an aligned permitting framework for grids, stand-alone storage and recharging stations, necessary for the integration of renewable energy, are a clear indication on the difficulty to be phased to reach our 2030 targets and KPIs only with the baseline scenario.

As for the security of cross-border energy infrastructure, the EU horizontal framework on protection of critical infrastructure and cybersecurity applies, notably the CER Directive and the NIS 2 Directive as well as the Network Code on cybersecurity. The TEN-E Regulation does not include provisions for addressing resilience against possible physical malicious acts and cybersecurity disruptions to cross-border energy infrastructure.

With regard to electricity distribution grid planning, the baseline option assumes that provisions in the draft electricity network code on demand side response, as submitted by ACER in March 2025, will be kept in the final text of the network code, to be adopted in 2026. 100  For grid connections, the baseline assumes relevant provisions of the Electricity Directive on grid hosting capacities transparency and flexible connection agreements are fully implemented. The Commission will support Member States and all relevant stakeholders in the implementation of existing legal provisions. This concerns exchange and sharing of best practices on grid planning, coordination among DSOs and TSOs, as well as smart and digital technologies. As these initiatives would be proposed and implemented regardless of the present package (Guidance on grid connections would be presented as committed in the Automotive Action Plan, as well as the strengthened options on DSO grid planning under network code), they form a part of the baseline against which policy options are assessed. Lastly, to support new smart electricity grid PCI candidates to be proposed, the Commission will engage in further communication and awareness efforts, inter alia with Member States, including for the integration of electrified industry, electromobility charging infrastructure, electrified heating and cooling and data centres, as long as a cross-border impact of the project can be demonstrated.

Regarding delays caused by supply chains related constraints, the baseline assumes implementation of the existing legal framework and non-legislative actions: the Grids Action Plan, the Net-Zero Industry Act 101 , the EIB Grids Manufacturing Package, and the Union of Skills. 102  

5.2.Description of the policy measures and options

Based on the consultation and desk research undertaken for this Impact Assessment, the Commission identified individual policy measures having the potential to address the problem drivers identified in the problem definition (Section 2) and achieve the specific objectives (SO) (Section 4.2). The policy measures were grouped into policy packages (Section 5.2.2).

The following process was applied for establishing the policy packages: (i) identifying the policy measures which can be discarded based on a first preliminary assessment; (ii) identifying a list of retained policy measures addressing the problems and respective problem drivers; (iii) combining retained measures into policy packages constituting viable policy alternatives for achieving all the objectives of the initiative.

5.2.1.Description of the policy measures 

This section provides a summary of the identified policy measures to address the problem drivers and specific objectives. For further details see Annex 9.

A.Infrastructure planning and project implementation

Four policy measures were identified to respond to problem 1 (drivers 1-3) and SO1.

A.1 Strengthening the existing framework

Measure A.1 proposes limited changes to strengthen the existing infrastructure planning framework. It maintains most of the current responsibilities of the main stakeholders but better defines and strengthens certain existing requirements to ensure a leaner and more robust planning process. To simplify and streamline the PCI/PMI selection process, there would be a shift from the ex post opinions by the Commission and ACER as well as approvals on the draft scenarios and draft infrastructure gaps identification report developed by the ENTSOs towards ex ante steering through strengthened ACER’s and NRAs’ roles in the verification of the TYNDP inputs to the PCI/PMI process and in monitoring the implementation. Moreover, scenario-building should consider national developments as regards the development of industrial hubs for electrification, deployment of data centres, electromobility charging infrastructure, heating and cooling plans and the revised NECPs. It would also include a simplified application and evaluation process for mature PCIs and PMIs. In addition, the planning would be expanded to better consider non-wired solutions and internal grid reinforcements to ensure infrastructure needs are optimally addressed.

A.2 Increased EU level steering and coordination

Building on measure A.1, measure A.2. would entail moving from a bottom-up towards a top-down cross-border infrastructure planning approach ensuring greater transparency, scrutiny and coherence of inputs used in network planning both at EU and national levels. It involves the Commission, ACER and NRAs earlier in the planning process and simplifies applications for mature PCIs/PMIs. The Commission would be responsible for the development of a comprehensive central scenario at least every 4 years (instead of 2 years), with the possibility to conduct interim reviews in case of very significant changes, as a basis for a strengthened, streamlined, more predictable and simplified infrastructure needs identification conducted by the ENTSOs and ENNOH based on framework guidance developed by ACER in line with the principles defined in the TEN-E Regulation. Project collection and assessment for the TYNDP and the PCI/PMI selection process would continue to be conducted every 2 years. The central scenario would allow for better comparability of projects and their costs and benefits. It would be less driven by (national) TSOs, represented by ENTSOs, but rather by the Commission and the Agency with close involvement of all Member States ensuring network planning captures EU policy targets as well as Member States’ perspectives and ensures alignment. There would be a closer link between the EU central scenario and national scenarios used in network planning, improving coordination between the EU and national levels of infrastructure development.

A new gap filling mechanism would be introduced to ensure that all needs are addressed by requiring the submission of project proposals by TSOs when the identified infrastructure needs are not being adequately matched by the project proposals submitted in the standard process for project collection for the Union-wide TYNDP. This should ensure that infrastructure needs are more optimally addressed reducing the gap over time. First, relevant TSOs would be required to propose possible solutions under the scrutiny of NRAs and Member States. Second, in case no projects are proposed, the Commission, in cooperation with hosting Member States, may launch a call for project proposals. For the electricity sector this option would introduce requirements to better link national and European planning. This measure would also prolong the period of network planning on a national transmission grid level for electricity from existing minima of at least 5-10 to at least 15 years. Measure A.2 would also require to fully consider non-wired alternative solutions as a priority when addressing the identified needs.

A.3 Fully centralised approach

Measure A.3 entails a full shift from the current bottom-up planning and needs identification approach to a full top-down coordination and project selection at the European level. The main activities of the scenario development, needs assessment and projects assessment under the TYNDP for cross-border infrastructure would be done by an entity at EU level (e.g. an EU energy agency) responsible of the entire planning process complementing national planning processes. Relevant national actors, such as system operators and regulators would still be involved, providing relevant information on local and national grid characteristics. The gap filling mechanism (see measure A.2) would also be steered by this entity. However, Member States would retain their right to veto any PCI/PMI candidate projects to be located in their territory in line with the TFEU, and would therefore have to approve projects in their territory

No existing entity would seem equipped with the necessary expertise, and this would therefore require the transformation of an existing one or the creation of a new entity. A transitional period would therefore be needed.

A.4 Alignment of scope (smart gas grids/blending, electrolysers, projects of mutual interest)

Measure A.4 involves strengthened requirements to ensure that electrolysers recognised under the TEN-E have significant cross-border relevance. This is achieved by increasing the installed capacity threshold of electrolysers projects eligible for PCI status from the current 50MW to 500MW. The changes cater for a better alignment of this category with the objectives of the TEN-E. To promote infrastructure dedicated to the exclusive use of hydrogen this measure also removes any incentives for projects for blending hydrogen with natural gas, including by removing the smart gas grid category from the scope of the TEN-E Regulation, removing the possibility of blending and amending definitions of ‘dedicated hydrogen assets’ and ‘repurposing’ to ensure these exclusively target pure hydrogen. Finally, candidate projects for PMI status with the Energy Community contracting parties would not need to demonstrate net benefits to the Union as long as all other criteria are fulfilled.

A.5 Broadening scope of PCI categories (modernisation and digitalisation)

Measure A.5 introduces a change to electricity grids PCI category to more prominently include non-wired solutions and better acknowledge the role of internal lines contributing to cross-border electricity trade (and flows), to enable optimal grid development.

B.Cost and benefit sharing

Four policy measures were identified to respond to problem 2 (driver 4) and SO2.

B.1 Enhancing transparency and strengthening EU principles for cross-border energy infrastructure costs and benefits sharing

Measure B.1. involves enhancing early transparency in the assessment of project benefits and costs to encourage the involvement of non-hosting countries. It also aims to establish a streamlined CBCA process and a more harmonised EU cost-sharing framework. It would require ENTSO-E and ENNOH to publish cost-benefit analysis results showing how the benefits of TYNDP projects are distributed across countries, including non-hosting countries who substantially benefit from such projects. ACER would be mandated to update its recommendation on the treatment of investment requests for PCIs and PMIs (or CBCA recommendation) based on CBCA principles outlined in the TEN-E Regulation.

B.2 Use of congestion income for financing of cross-border electricity infrastructure as an incentive to cost-sharing

Under measure B.2, congestion income is used to create an additional tool for unlocking cost-sharing discussions with the aim to increase the use of cost-sharing tools. The Commission would be empowered to provide detailed rules on the use of congestion income for financing cross-border electricity infrastructure under the Electricity Regulation. TSOs would be required to allocate a share of the congestion income to PCIs addressing the biggest bottlenecks in the European or regional energy systems.  This should facilitate reaching agreements on cross-border cost allocation, particularly for projects that generate substantial benefits for Member States other than the host country.

B.3 Enabling framework for voluntary bundling of projects

Measure B.3. seeks to incentivise increased financial contributions from Member States towards cross-border energy infrastructure projects that generate benefits beyond their host countries by establishing an EU-level framework for the identification and voluntary bundling of cross-border projects to enable and encourage discussions amongst relevant Member States (and third countries). These projects would be grouped together to enable cost-sharing discussions amongst relevant Member States or third countries and facilitate joint PCI applications and access to CEF. While the voluntary bundling of projects is already possible in principle, certain legislative changes are required to allow for project bundles to fully benefit from the cross-border cost allocation provisions under the TEN-E framework. For instance, a new definition of project bundles would be introduced that would allow for specific references in the cross-border cost-allocation framework currently designed for project-specific PCIs/PMIs.

B.4 Mandatory offshore regional planning and cost-sharing

Measure B.4 introduces a mandatory regional planning for offshore cross-border infrastructure projects within sea-basins where hybrid or cross-border radials are already planned, building on existing processes in view of possible application in other areas.

C. Permitting 

Three policy measures were identified to respond to problem 2 (driver 5) and achieve SO3.

C.1 Supporting the implementation of existing legislation and issuing guidance

Measure C.1 entails reinforcing policy efforts to implement the current permitting acceleration framework and adopting new non-legislative measures. It does not, however, introduce new legislative measures. The Commission would also support Member States to implement best practices. The Commission would issue or update guidance on the implementation of certain aspects of the environmental assessment framework for permitting procedures, support implementation via dialogue with Member States in dedicated fora such as CA-RES and may establish additional technical fora to address implementing barriers. 

C.2 Targeted legislative changes to accelerate permitting

Measure C.2 involves legislative amendments to further accelerate and simplify permitting procedures for cross-border, national transmission and local distribution grids as well as renewable energy and storage projects and recharging stations. These amendments could include: (1) establishing an EU level framework for the accelerated permitting of electricity distribution, transmission and storage projects and recharging stations including alignment with and further strengthening of the EU level permitting provisions applicable to hydrogen infrastructure; (2) strengthening the permitting acceleration provisions of the TEN-E Regulation; (3) introducing changes in the revised RED with regards to the permitting framework, introducing a fast permitting framework for non co-located storage assets, and recharging stations, making permanent measures from the Emergency regulation and addressing any remaining shortcomings (that have not been addressed before or that have addressed only partially) that hinder permitting and compliance with the existing framework; (4) simplifying and streamlining environmental assessments applicable to energy assets; exempting certain projects due to their characteristics from certain assessments or elements thereof.

The permitting measures that are assessed as part of the Grids Package can be summarised as follows building on the description in Annex 9:

·Presumptions of overriding public interest for all PCIs/PMIs and temporarily for all transmission and distribution system infrastructure. Expanded scope of the presumption under the revised RED and deletion of the possibility of exemptions.

·One-stop-shop/single point of contact for electricity system infrastructure and digitalisation and centralisation of procedures and data gathering.

·Time limits: introducing (for electricity infrastructure, non co-located storage and recharging stations).

·Expand tacit approvals and introduce exemptions from environmental assessments (EIA, assessments under the Water Framework and Marine Strategy Directive). 

·Make permanent measures of the Emergency Regulation for alternative tests and compensation measures.

·Introduce measures with regards to public participation and acceptance and strengthen cross-border procedures under the TEN-E regulation applicable to all PCIs.

·Introduce obligation of adequate administrative resources in the TEN-E Regulation, Electricity Directive and Gases Directive.

The proposed measures build on the acceleration measures introduced in previous sectorial initiatives to facilitate that these deadlines can be met, procedures simplified, and the lead time for permits is shortened. These elements would also ensure a better implementation of the EU rules for permitting at national level and by the different administrative entities involved, thus promoting the effectiveness of the different permitting frameworks.

Court proceedings are not under the scope of the permitting rules for renewable generation and grid infrastructure, for storage and charging stations projects, so no direct measures are proposed, but the measures on public participation aim at decreasing litigation and therefore delays by court proceedings. Furthermore, the Commission will deal with long and complex court proceedings via non-legislative actions, including discussions in the context of the Permitting Expert Group.

C.3 Centralised EU-wide permitting coordination regime for certain large-scale energy infrastructure projects

Measure C.3 would introduce a centralised EU (“28th”) regime for the permitting of very large energy projects such as interconnectors and large-scale renewable energy projects with cross-border characteristics. 103 This would shift responsibility of coordinating permitting processes from Member States’ one-stop shops to the EU through a permanent European coordination authority. National permitting authorities would retain a critical role in the permit granting procedure as projects have an impact on land use, property and the environment within their territory. The centralised EU coordination entity would liaise with national and local authorities to verify that the necessary approvals are granted on time, without having direct impact on the national procedures. A transitional period would likely be needed to set up and operationalise a new EU-level entity or expand the scope of an existing one.

D. Security

Three policy measures were identified to address problem 3 (drivers 6 and 7) and achieve SO4.

D.1 Including physical and cyber-risk resilience considerations in the monitoring of PCIs and PMIs

Measure D.1 would require project promoters to include a risk assessment as part of their implementation plan and, where needed, provide details on the envisaged physical and cybersecurity mitigation measures in their annual reports with the aim to enhance physical and cyber security and resilience of cross-border energy infrastructure (PCIs/PMIs).

D.2 Additional transparency requirements regarding the ultimate beneficial owners of candidate PCIs/PMIs

Measure D.2 introduces transparency requirements regarding the ultimate beneficial owners of all candidate PCI/PMI projects and their internal shareholder structure to address increased exposure to foreign investments. Project promoters would be required to share information about their ultimate beneficial owners during the TYNDP application process to be taken into account in the assessment of candidate PCI and PMIs.

D.3 Including security and resilience-related equipment for the upgrade of existing electricity cross-border infrastructure under TEN-E scope

Measure D.3 introduces the possibility to include PCIs related to security upgrades of existing electricity infrastructure under the TEN-E framework.

5.2.2. Description of the policy options 

The measures described in Section 5.2.1 have been grouped in 3 policy options. Table 1 provides an overview of the policy measures and their links with specific objectives and policy options. The design of policy options follows a logic of varying degrees of EU-level intervention and coordination in achieving the general and specific objectives.

The design of the policy options takes into account the compatibility of the respective policy measures and their governance implications. Alternative groupings of the policy measures have been considered but were not pursued due to lack of internal coherence or non-compatibility. Further, several policy measures were included across the policy options as they do not compromise the internal coherence of the options.

Table 1: Specific objectives, policy options and policy measures

Policy option 1 entails an enhanced bottom-up approach. It introduces only a limited number of changes to the current EU legislative and policy framework in comparison to the business as usual (“BAU”) and involves minimal additional EU-level intervention.

Policy option 2 entails moving from a bottom-up more towards a top-down approach with stronger steer from the EU level and enhanced coordination with the current actors at Member State level. It introduces more significant changes to the current EU legislative and policy framework as compared to PO1, with additional EU-level coordination and reallocation of certain responsibilities among relevant stakeholders.

Policy option 3 entails a full top-down approach for cross-border infrastructure. It includes substantial structural and institutional changes to the status quo and a higher degree of centralising and streamlining at EU level, including through entrusting infrastructure planning and coordination of permitting for cross-border infrastructure projects to EU bodies. It also includes a mandatory offshore regional planning and cost-sharing framework.

Stakeholder views:

On infrastructure planning (Measures A), a majority (54%; companies 49%, business associations 63%, NGOs 71%, public authorities 40%) indicated that the current governance framework of the TYNDPs, including stakeholder roles, should be revised to enhance its effectiveness. About half (44%; companies 37%, business associations 43%, NGOs 86%, public authorities 50%) believed the TYNDP falls short in addressing identified infrastructure gaps and a majority (60%; companies 53%, business associations 70%, NGOs 100%, public authorities 50%) agreed that national projects should more clearly support EU-wide priorities (in line with PO2 and PO3). A majority of respondents (61%; companies 56%, business associations 61%, NGOs 93%, public authorities 60%) also agreed that there is a need for stronger alignment between national transmission development plans as proposed under PO2. A majority of respondents were positive to the inclusion of internal reinforcements (72%; companies 66%, business associations 78%, NGOs 93%, public authorities 70%) and non-wired solutions (54%; companies 49%, business associations 63%, NGOs 71%, public authorities 40%) in infrastructure needs identification (all POs). Moreover, a majority of respondents (59%; companies 63%, business associations 57%, NGOs 36%, public authorities 50%) were positive to streamlining the PCI/PMI application process by amending requirements for projects with PCI-PMI status to reapply during each process (provided certain conditions are met). On the frequency of the processes, most stakeholders (85%) found the current two-year cycle appropriate in line with PO1 as reflected in the possible updates in PO2 and PO3.

When asked whether the TYNDP should have a more top-down approach to infrastructure planning more in line with PO2 and PO3, 41% of respondents (companies 41%, business associations 43%, NGOs 14%, public authorities 40%) disagreed whereas 36% agreed indicating mixed views. Note that there is wide variance in responses within the company category. While a strong majority (70%) of TSOs disagreed with the statement, only 19% of project promotors, 29% of energy suppliers, 38% of energy offtakers, and 46% of DSOs disagreed. Similarly, 41% of respondents (companies 42%, business associations 46%, NGOs 7%, public authorities 30%) expressed disagreement with the TYNDP having a more top-down European approach to better link identified needs and priority projects of common European interest (agreement 36%, neutrality 12%, uncertainty 12%). Again, a strong majority (70%) of TSOs and DSOs (62%) disagreed with the statement, while only 19% of project promotors, 24% of energy suppliers, and 38% of energy offtakers disagreed.

As regards the cost-sharing (Measures B), 38% 105 (companies 40%, business associations 37%, NGOs 36%, public authorities 20%) of respondents stated that the current framework is not fit for purpose. Further, 37% 106 (companies 30%, business associations 39%, NGOs 43%, public authorities 30%) of respondents thought that an investment request within the CBCA framework could also cover several projects (‘bundling’) and 36% 107 (companies 31%, business associations 35%, NGOs 57%, public authorities 30%) favoured that it would develop further to facilitate the sharing of investment costs, in line with PO2 and PO3. 

Concerning permitting (Measures C), the OPC indicated a vast majority of stakeholders across respondent categories support the digitalisation of permitting procedures, shortening of legal deadlines for permitting of networks, and establishment of such deadlines where missing – suggesting support for further action than PO1. Views were more mixed on the simplification and streamlining of environmental assessment with a majority of companies (92%), business associations (83%) and public authorities (70%) expressing support, and about a third (29%) of NGOs.

On security (Measures D), over a third of stakeholders agreed that the EU legal framework does not sufficiently address emerging security risks (38%; companies 37%, business associations 44%, NGOs 36%, public authorities 40%) 108 and that additional security criteria for PCIs and PMIs are needed to enhance protection against physical and cyber risks (36% companies 33%, business associations 31%, NGOs 29%, public authorities 60%). 109  Furthermore, only 14% indicated that the framework addresses the exclusion of non-trusted actors from participating in critical infrastructure projects, indicating support for further measures in line with PO2 and PO3. 110  

5.3.Options discarded at an early stage

As mentioned in the previous section, alternative groupings of the policy measures on A) infrastructure planning and project implementation, B) cost and benefit sharing, C) permitting, and D) security were considered but discarded due to a lack of internal coherence or non-compatibility of the measures.

6.What are the impacts of the policy options?

This section presents the main expected economic, social and environmental impacts of each policy option 111 . To the extent possible, the impacts are quantified based on available assessments or modelling by the JRC. Considering that all policy options entail changes to governance structures, the impacts of the proposed measures will be linked to the outcomes of their implementation in the longer term. Where modelling was not possible due to the lack of tools or data, qualitative assessment is used building on available studies and input from stakeholders. Additional data are provided in Annex 4.

6.1.Economic impacts

Economic impacts are assessed against their impact on the EU energy system, competitiveness and digitalisation as well as in relation to the administrative and adjustment costs.

6.1.1.Energy system benefits

The economic impacts of the proposed policy options in terms of reduced energy system costs can be quantified for the electricity system, whereas this is not possible to a reasonable degree of certainty for the hydrogen sector given the early stage of hydrogen infrastructure development. The assessment builds mainly on ENTSO-E data, complemented by JRC modelling (Annex 4).

The expected impacts of the BAU scenario are estimated under assumption of timely implementation of the TYNDP projects portfolio and need to be adjusted considering expected delays and challenges to project deployment under the BAU. The implementation of 2024 TYNDP project portfolio by 2040 (211 projects) would lead to the increase of EU GDP by EUR 247 billion by 2040. 112  The BAU is based on the scenario compliant with the Union energy and climate targets and takes into account to the extent possible future developments of demand and supply indicated in the national energy and climate targets.

The benefits of the proposed policy options are assessed by looking at their potential to achieve the optimal grid where all needs for energy transmission capacity 113 are addressed leading to a cost-effective energy system compliant with the Union energy and climate targets. As it is difficult to assess which investments would materialise, it is assumed that they would lead to partial implementation of the optimal grid and hence achieve partial benefits associated with it. Partial implementation of the optimal grid would mean lower costs of investments but at the same time higher overall energy system costs (due to redispatch or renewables curtailment) offsetting the savings from lower investment costs. It is thus not possible to associate economic costs of specific options in a meaningful way. Consequently, the benefits and investment costs of each option are assumed to be up to the levels associated with deployment of the optimal grid, without specific levels associated to the options.

PO2 and PO3 would increase benefits –to a similar degree– by ensuring that identified projects better match and fully cover the identified needs (SO1), leading to an optimal and resilient grid. PO1 would achieve these benefits only to a limited extent, as it lacks a gap filling mechanism to match project planning and development to identified infrastructure needs.

For 2030, the optimal grid (see Annex 4) could lead to additional EUR 8 bn/year reduction in electricity system costs, which compared with the required additional investment of EUR 5 bn/year would lead to EUR 3 bn/year savings for the EU economy. However, the impact of the proposed measures might be limited until 2030 in view of their expected entry into force. For 2040, investments of EUR 6 bn/year into the optimal grid would lead to EUR 14 bn/year reduction in system costs, that is EUR 8 bn/year net saving (only part of these savings could be achieved by the already planned projects under the BAU scenario, corresponding to 78 GW new capacity to be added by 2040) . . PO2 and PO3, which include a gap filling mechanism, would help bridge the gap of 30 GW not covered by any projects, corresponding to EUR 1.8 bn/year in additional net savings. 114 The actual savings would most likely be higher because the proposed options would also reduce delays and difficulties in implementing planned projects.

Net savings achieved via PO2 and PO3 would benefit consumers, electricity producers and system operators, but the distribution of benefits is not possible to estimate. While higher electricity grid investments could lead to higher network tariffs for all consumers, the overall lower energy system costs would also be transferred to consumers via lower wholesale electricity prices. These impacts depend on the number of electricity consumers and the level of electricity consumption (see Section 6.2 on social impacts). The geographical distribution of impacts will depend on the actual projects.

PO2 and PO3 would have a similar, substantial impact on wholesale electricity prices. Better interconnectivity leads to price convergence and, overall, more stable and lower prices, with some countries facing an increase and others a decrease of prices, ranging from EUR +10/MWh to EUR -10/MWh. 115 Still, the increase of prices should not be considered as a welfare loss since generation surplus and congestion rents related to the new interconnectors should also be taken into account. This is reflected in the overall reduction in energy system costs. Addressing infrastructure needs would lead to a reduction of wholesale electricity prices in several Member States, including the Eastern part of Europe where the problem of high and volatile electricity prices is most prominent.

PO2 and PO3 also bring positive economic impact for RES deployment and integration. Better planning and faster permitting of electricity grids may help avoid approximately EUR 37 billion in annual redispatching costs in 2040, if the grid is expanded accordingly (see Annex 4 for more details). 116  

Deployment of grid enhancing technologies, which would be prioritised in all policy options when identifying possible projects, could expand network capacity by 20-40% by 2040 and save up to 35% in conventional grid expansion costs. 117  The deployment of dynamic line rating, one of the well-established grid enhancing technologies, on most congested network elements could bring net benefits of EUR 2.67 billion 118  over a period of 20 years through additional 27 GW of available transmission capacity. 119  PO2 and PO3 are expected to create higher benefits from grid enhancing technologies due to broadened scope.

PO2 and PO3 bring greater possibility to account for anticipatory investments, but also long grid development lead times (up to 10 years as mentioned earlier) as they would prolong national grid planning horizons to at least 15 years. Underinvesting in grid infrastructure may become costlier to society in the medium term than making anticipatory investments under controlled scrutiny and risk management processes. 120  While estimates are not available for the whole EU, examples indicate the potential benefits. In Austria , anticipatory grid investments of EUR 133 million could prevent costs of EUR 1.5 billion in 2040. 121  Furthermore, the Scottish TSO , for instance, estimates that customers would save up to GBP 750 million over the two and a half years if an equivalent grid capacity at a cost of around GBP 25 million per year was built. 122

To accommodate the growing demand for renewable and low carbon hydrogen—while ensuring the competitiveness of key European industries—a substantial expansion of hydrogen infrastructure is required. In its 2024 Hydrogen Monitoring Report, ACER highlights the need for integrated planning to accurately assess infrastructure needs, prevent overinvestment, and mitigate cost recovery risks. The BAU scenario and PO1 risk fragmented, inefficient development, leading to higher economic costs. In contrast, PO2 and PO3 promote enhanced cross-sectoral planning, better adapting infrastructure to evolving supply and demand, thereby ensuring more cost-effective outcomes. While the quantification of potential benefits comes with a high level of uncertainty, positive impacts of cross-sectoral planning could bring synergies across energy vectors and efficiency gains across the energy system. 123  Integrated planning of all sectors in Europe could bring as much as EUR 561 billion savings between 2030-2050 124 , with significant reduction of investment needs. Up to EUR 200 billion in savings from avoided back-up capacities could be achieved. 125

Changes in the assessment rules for PMI candidates with Energy Community Contracting Parties should bring positive benefits from market coupling and security perspectives. Better interconnected networks in the synchronous European area can improve integration of renewable energy sources and loads, decreasing the risk of supply disruptions and related socio-economic costs, including in countries of high geopolitical importance in our neighbourhood, notably Ukraine and Moldova.

Establishing the cross-border nature of electrolysers had proven challenging based on the 50MW capacity threshold stipulated in the TEN-E Regulation in force. Electrolysers that applied for PCI status of 50MW capacity were very often not connected to a (planned) hydrogen network, but rather supplied on-site or local consumption – usually industry. While it appears that electrolysers as large as 500MW may also serve on-site demand (as evidenced by the applications and complementary analyses of the European Commission in the PCI/PMI selection process), the likelihood of large-scale electrolysers realizing economies of scale that could feed a hydrogen transmission system and be part of an integrated hydrogen network planning is higher with larger capacities than the relatively modest 50MW size. By focussing TEN-E recognition on large-size electrolysers with cross-border relevance, project promoters can expect to be able to more efficiently distribute fixed costs, realise operational efficiencies and capitalise on their bargaining power especially vis à vis technology suppliers in the early stages of market development.

Furthermore, removing incentives for the blending of hydrogen with natural gas, as foreseen in all policy options, would lower system costs since it would ensure a more efficient use of hydrogen while preventing barriers to the internal market. In the impact assessment accompanying the hydrogen and gas decarbonisation package, the Commission estimated that while a 5% allowed hydrogen blending cap at cross-border points would lead to lower emissions (8 Mt CO2/year of avoided emissions), with an adaptation cost of EUR 3.6 bn/year, a 10% or a 20% cap would increase the adaptation costs drastically (EUR 5.4 bn/year for 10% or EUR 12.5 bn/year for 20%). Importantly, whilst blending of hydrogen in the natural gas network at a limited percentage may enable decentralised renewable hydrogen production in a transitional phase at the level of local networks, the TEN-E Regulation aims at the promotion of investments that have a significant cross-border impact and is therefore neither a suitable nor efficient tool to promote such local networks. The same applies to the integration of biomethane.

As for cost and benefit sharing (SO2), the BAU scenario would involve substantial welfare losses caused by delayed implementation or non-materialisation of projects due to complex or deadlocked discussions on cost sharing. While a quantitative assessment of direct economic impacts is challenging given that the allocation of benefits per project is not currently disclosed within the TYNDP or the PCI/PMI lists, assessments carried out for offshore developments in the EU’s sea-basins provide an indication on the potential impacts both for offshore and onshore.

According to ENTSO-E’s 126  cost-benefit sharing assessment of the EU’s sea-basins offshore network development plans (ONDPs) 127 , the benefits of future hybrid offshore projects are expected to extend beyond the hosting countries. ENTSO-E estimated that the potential installed capacity of such projects, with benefits beyond host countries (not yet existing or planned), amounts to 25 GW by 2040 and 44 GW by 2050. 128 These assets are expected to incur investment costs of approximately EUR 23 billion, while generating almost EUR 70 billion in socio-economic welfare over their economic lifetime. 129  It can be assumed that all of these projects are unlikely to materialise or only with significant delays in the absence of more effective cost-sharing tools. The resulting economic impacts under a BAU scenario in terms of the loss of net socio-economic welfare (SEW) over their lifetime would be at least EUR 20 billion for 2040 and an additional EUR 10 billion for 2050 assuming that 30-50% of the projects would be delayed or not realised (see Table 2 ).

Table 2: Loss of socio-economic welfare of non-realised hybrid offshore projects

Source: Own calculations based on ENTSO-E assessment

The measures foreseen in PO1, PO2 and PO3 to facilitate more effective cost-sharing are expected to help realise these potential socio-economic benefits but to different degrees. Enhanced transparency and updated recommendations on the preparation of CBCAs will support cost-sharing agreements. The impact of PO2 and PO3 is expected to be higher as a result of an enabling framework that allows TSOs and Member States to voluntarily bundle projects. This would further facilitate cost sharing as demonstrated in past examples. 130   The framework would provide visibility on possible incentives, such as the PCI status and related CEF funding and could enable the establishment and implementation of a first project bundle in the North Sea and provide inspiration for other offshore and onshore regions. PO3 could lead to higher impacts given it is mandatory although this might weaken a trust-based approach and would be limited to offshore, where projects are already planned, hence likely lead to similar impacts as PO2.

Under all policy options congestion income is considered as source for financing of cross-border electricity infrastructure, acting as an incentive to cost-sharing. The account balance for congestion income not used in the previous years and placed in a separate account line amounted to more than EUR 9 billion. 131  This would increase to more than EUR 11.4 billion in 2025 (see Annex 4 for more details). This data indicates that a substantial portion of congestion income remains available and could be utilised to facilitate cost-sharing agreements providing an additional incentive to hosting Member States. This would be possible without reducing current spending on other priorities, hence would not create additional costs. Socialising a share of the congestion income to finance new cross-border electricity infrastructure projects could reduce the need to increase network tariffs to finance these investments in the hosting countries. 

As for permitting (SO3), under the BAU scenario, permitting procedures face significant delays (Section 2.2.5). Delays in permitting of energy infrastructure represent an impact on total generation cost of at least EUR 450 million/year. 132  The example of the “Garenfeld substation” project (Germany) shows a delay of 2 years may cost over EUR 150 million in redispatch costs, which would otherwise have resulted in a EUR 70 million reduction to consumer bills. 133  

PO1 would contribute little to accelerating permitting procedure and addressing high and volatile energy prices, as impacts will be limited to the results achieved under the existing framework. Through creating a clear framework with concrete shorter deadlines and simpler procedures for the development of RES projects, grids, storage and recharging stations, PO2, and to a lesser extent PO3 134 , would lead to shorter lead time for projects and thus bring positive economic benefits. This is supported by the experience with the implementation of binding and optional measures to accelerate permitting as introduced by the Emergency Regulation. Germany has made extensive use of the measures in this Regulation resulting in a substantial acceleration of permitting. In 2024, Germany approved approximately 14-15 GW of additional installed onshore wind capacity 135 , which represents an 85% increase compared to the previous year. Faster permitting for recharging stations would provide more planning certainty, reduce costs and hence improve the business case for charging operators and accelerate the roll out of charging infrastructure. By 2040, during peak times, electric vehicles utilising bidirectional charging could supply up to 15–20% of electricity demand, serving as a large virtual power plant 136 and provide system flexibility. 

Addressing the delays in project implementation is expected to generate benefits in terms of overall reduced wholesale electricity prices and increase total welfare. Comparing the initial planned commissioning dates for on-going cross-border infrastructure projects against the latest information from the project promoters shows an average delay of 4 years, equivalent to a welfare loss of EUR 6.5 billion until 2030; delays in permitting alone amount to a welfare loss of at least EUR 515 million per year, when compared to a “no delays” scenario. 137  

While the time required to implement the proposed options may not substantially change the situation for 2030, they are expected to support timely project implementation for 2040 and hence prevent welfare losses of an even higher magnitude given the higher number of projects expected to be implemented. In addition to stricter permitting deadlines, PO2 and PO3 would introduce stricter requirements for project assessment which should reduce delays for projects (also linked to delays of other interlinked projects). By introducing an EU-wide approach, PO3 will further enhance coordination in the permitting of projects with a cross-border dimension and very large-scale renewable energy projects in the EU.

As for security (SO4), the policy options would have varying economic impacts. The additional risk assessments in relation to physical and cybersecurity measures, included in all POs, together with better inclusion of security and resilience-related equipment under PO2 and PO3, would lead to benefits in terms of avoided costs of incidents, such as outages and emergency repairs. For instance, the outage of the Estlink 2 interconnector between Estonia and Finland in 2024 resulted in repair costs of EUR 30 million compared to a loss in socio-economic benefits of EUR 94 million. The second outage in 2025 resulted in total repair costs of EUR 50-60 million.

Including security and resilience-related equipment for the upgrade of existing electricity cross-border infrastructure under TEN-E scope as foreseen under PO2 and PO3, would allow for the possible financing of part of this equipment via the CEF. This would reduce costs for project promoters and could have a positive impact on consumer bills.

6.1.2.Competitiveness

Impacts on competitiveness are closely linked to economic but also social impacts. An optimal energy infrastructure would result in lower energy system costs (Section 6.1.1). In this regard, all policy options bring positive impacts in terms of avoided cost and hence avoided network tariff increases with the highest impact expected under PO2 and PO3. It is however not possible to further credibly quantify the impact of the measures on competitiveness beyond reduced energy system costs and expected effects on wholesale electricity prices.

Regarding the impact on manufacturing capacities, given that most of the supply chain for high-voltage technologies is coming from EU suppliers 138 , further increase in grid investments is expected to benefit primarily EU companies. The completion of the 2024 TYNDP project portfolio by 2040 (211 projects) with a total CAPEX of 288 bn EUR in the EU would lead to EUR 603 billion mobilised in production and create 4.1 million jobs in the EU. 139  

In general, if Europe can significantly shorten planning and permitting procedures, besides achieving direct economic benefits, its competitive position vis-à-vis direct competitors could also be improved, by through e.g. cost-efficient electrification of industry. This concerns for instance connection of data centres or gigafactories, for which grid connection is one of important considerations based on which they decide on their placement. 140

6.1.3.Digitalisation

All three policy options show positive impact on digitalisation through stronger emphasis on the use of non-wired alternative solutions in grid planning, including in project assessment and filling the identified infrastructure needs. PO2 and PO3 have higher impact due to better reflection of non-wired alternative solutions in scope of the electricity PCI category. All non-wired solutions must in practice be encompassed by digital solutions. 141  By this priority treatment of non-wired alternative solutions, all three policy options also positively contribute to innovation, by providing clear investment signals for such technologies.

In terms of permitting, PO2 and PO3 would require Member States to digitalise their permitting procedures. To do so, permitting authorities would have to integrate digital tools, create and continuously update platforms with relevant data and to upskill their staff to handle the new digital elements. The impact of using such platforms and tools was seen in Portugal and Denmark, where environmental and heritage sensitivity maps that simplify the planning and approval of energy infrastructure facilitated the identification of potential impacts. 142

6.1.4.Administrative and adjustment costs

PO1 would entail minimal additional administrative and adjustment costs, as limited changes are made to the existing framework. As regards infrastructure planning, for PO1 the administrative and adjustment costs are very limited for ACER and the Commission and include one-off costs (to develop framework methodologies) and recurrent costs (verification/monitoring). The one-off costs are comparable to the current situation and the recurrent costs would likely be offset by savings gained through streamlined procedures (e.g. removal of Commission and ACER Opinions which take 3-4 months each). Integrated scenario modelling across sectors is already required under the TEN-E, hence targeted improvements via earlier inclusion of ACER and Commission in the process should not entail significant adjustment costs.

PO1 would also reduce administrative costs for the Commission, NRAs, ACER and Member States by streamlining the hydrogen-related categories under the TEN-E and thereby reducing the number of project applications.

As for cost sharing, the requirement for ENTSO-E and ENNOH to publish benefits of TYNDP projects, would involve minimal effort, as this information already exists and would simply be made public. Preliminary, non-binding cost-sharing discussions for mature projects may anticipate part of the workload for concerned stakeholders but would not increase the overall burden and could facilitate more effective coordination later on. ACER would face one-off implementation costs to update its CBCA recommendation (estimated to 1 FTE) and develop a template, and recurrent costs to establish a repository. EU-level CBCA principles would help streamline and harmonise the cost-sharing process, without creating additional burden compared to the BAU scenario. The use of congestion income to finance cross-border infrastructure will introduce new administrative responsibilities, including coordination with other TSOs and relevant NRAs. However, adjustment costs are expected to be very limited since TSOs and NRAs already deal with congestion income and manage the relevant accounts.

As for permitting, PO1 would not create new legal requirements, hence no additional adjustment or compliance costs are expected for national authorities. The Commission would support Member States to reduce administrative costs by identifying technical assistance and funding opportunities to support investments in tools, reforms of procedures and trainings needed to increase the capacity of authorities. Moreover, by establishing guidance on the implementation of environmental legislation in connection to permitting procedures, procedural ambiguities would be minimised, reducing authorities’ administrative costs.

Concerning security related measures, PO1 may incur additional compliance costs. Project promoters who are currently considered as critical entities under the CER Directive, such as TSOs, would experience minimal added burden compared to the status quo. For those not currently subject to obligations under the CER Directive or the EU cyber-security framework, additional costs may include specialised expertise to identify, evaluate and mitigate risks related to physical security and cybersecurity. Taking the example of the first PCI/PMI list, this would concern around 8% of project promoters.

PO2 would entail some administrative and adjustment costs, as it involves a more comprehensive revision of the legislative and policy framework. As regards infrastructure planning, PO2 would mainly entail additional administrative costs for the Commission being responsible for the central scenario development and changes related to the scope of the PCI and PMI process. The former would require additional resources in terms of personnel (18 FTEs) with possible additional costs for external support. At the same time, administrative savings would occur for ENTSO-E and ENNOH as they would no longer be responsible for the scenario development. Additional administrative costs could be expected for national authorities, TSOs and ACER to ensure data collection and verification for the scenario development as well as for the verification, approval, and follow-up of identified needs. However, they already conduct such tasks under BAU and the reduction of the frequency of TYNDP processes from every 2 years to every 4 years as well as optimisation of the planning process would reduce costs compared to BAU and PO1. The cost impact on ACER can be considered a slight increase.

Regarding infrastructure categories and scope of PCIs/PMIs (all POs), broadening the scope for digital technologies and security upgrades for existing energy infrastructure and lowering the 500 MW cross-border impact threshold for internal electricity lines should attract more candidate projects, hence leading to higher administrative costs for assessing and monitoring the projects. The decrease in number of electrolysers and smart gas grids projects may be offset by increase of projects under the electricity grids category 143 , not leading to additional administrative costs.

As regards cost sharing, PO2 requires additional resources and administrative responsibilities from stakeholders, especially if TSOs will carry out an extra regional planning exercise. This process would build on existing tools, supported by a specific framework in the TEN-E Regulation and facilitated by the Commission. Member States and the Commission would also need to allocate extra resources to support this process, as well as NRAs who would have to conduct assessments and take decisions. NRAs will be required to get involved in the regulation of projects not situated in their territory and to cooperate with other NRAs and TSOs from several different Member States. As for ACER, the cluster approach should not create additional costs.

On permitting, PO2 would introduce new measures requiring implementation by national and local authorities, specifically regarding: equipping permitting authorities with all necessary staff, skills and tools to handle the growing number of permitting requests, the accelerated permitting timelines and simplification of permitting procedures for certain projects and repowering, the creation of digital platforms and tools for the permitting process and for the design of benefit-sharing schemes for public participation in renewable energy projects and new procedures as single points of contacts for electricity transmission and distribution infrastructure in general and storage and recharging stations, not covered by the revised RED. However, this short-term cost effect would translate into savings from a streamlined, simpler and quicker procedures over mid- and long-term.

Security-related measures under PO2 and PO3 are not expected to impose additional costs on project promoters, as the required information regarding ultimate beneficial owners is generally already accessible and will be handled confidentially, thereby minimising risks related to competition or commercial sensitivity.

The most substantial administrative costs are expected for PO3 and making an EU entity (new or existing) responsible for infrastructure planning and permitting. To estimate the administrative costs of such an EU entity to cover all tasks in relation to infrastructure planning (PO3), the current budget of ENTSO-E and ACER can serve as examples (see Annex 4). For the entity, staffing of 50 employees with an annual budget of around EUR 10 to 15 million might be required to carry out all tasks, also considering cost for IT infrastructure. While there might be some offsets due to staff transfers, a substantial part would be in addition to the budget required to operate the already existing entities. Since the entity would be independent from TSOs/project promoters, the budget would have to be financed from other sources than membership fees. Whereas some posts of the current entities might be transferred to the new entity, all horizontal functions would have to be established in case of a new entity. However, due to a competence transfer to a new entity, some administrative savings in ENTSOs could be expected.

For cost and benefit sharing, the administrative costs are also highest for PO3 on the side of the Commission, Member States, NRAs and system operators, where regional planning and cost-sharing are mandatory for some offshore sea basins where hybrid or cross-border radials are planned. In the short term, this is expected to mainly affect North Sea Member States. Nevertheless, North Sea TSOs, under the OTC, and Member States, under NSEC, have already initiated this process saving some of the necessary resources in the region.

On permitting, PO3 would require, in addition to the costs of PO2, the setting up of a coordination entity at the European level. Such a body would be expected to coordinate permitting procedures for at least 250 projects with a cross-border dimension. 144 To do so, it will have to liaise with national and local authorities for authorisation. Taking a conservative assumption in terms of staffing, this authority would require 50 FTEs and an annual budget of around EUR 10 million per year. This administrative cost does not save resources in local administration who would still have to perform the national/local level assessment and implement the decisions on the ground and not preclude the need for reinforcement of the national permitting authorities with additional staff and tools, given that for sovereignty reasons these are still necessary and responsible for the final decisions concerning the projects in question. 145

6.2.Social Impacts

Grid infrastructure is primarily financed through network tariffs. Therefore, grid investments are reflected in the overall level of network tariffs unless compensatory measures are implemented. Impacts of new grid costs on individual customers will depend on projections for the future energy demand since redistribution of total costs over a larger customer base will reduce network tariffs per unit. This effect is illustrated in Figure 3. 146 On the left-hand side, standard recovery is linked to the situation where assumptions on future grid usage (i.e. volume of loads connected) materialise, in alignment with optimised network planning. On the right-hand side, weak demand means the expected demand (as assumed in the network planning before the investment was made) does not materialise, offtake from electricity grid is lower, and hence fixed CAPEX cost must be spread across a smaller consumer base. A part of the tariff increases could be mitigated by public support such as EU grants and financial instruments or state budget interventions.

Figure 3: Average grid tariffs for different consumer base

Source: Heussaff/Zachmann (2025)

This indicates that PO2 and PO3 will limit costs on consumers compared to PO1 and BAU, as infrastructure planning under both options is based on the assumption of more precise estimates of future development of demand and supply linked to agreed policies, hence limiting the possibility of future stranded assets and limited use of grid infrastructure. To the extent that PO2 and PO3 will enable further electrification, they will also contribute to an expansion of electricity consumption allowing to spread grid investment costs over a higher number of kWh.

Regarding cost and benefit sharing, PO1, PO2 and PO3 would have distributional impacts which are however not possible to quantify for each option. Consumers in Member States with significant consumption needs from electricity imports, are likely to contribute more in terms of network tariffs under all policy options, since these Member States would be the main beneficiaries of such cross-border infrastructure projects. At the same time, they are likely to benefit from higher socio-economic welfare in terms of lower wholesale electricity prices. The exact distributional effects would have to be established for each project or bundle of projects as part of the cost-sharing agreements due to differences in generation and consumption mixes.

Regarding permitting, PO1 is not expected to have a substantial social impact, as it will not introduce any change of approach to public engagement. Assets covered under the revised RED, the Gas Directive and the TEN-E Regulation, will experience a perpetuation of the public participation framework leading to no change regarding unease and public opposition towards them. These would be only mitigated by way of ongoing initiatives such as the Pact for Stakeholder Engagement. Further, for electricity transmission and distribution grids, storage assets, and recharging stations in general, impacts are neutral as these assets will not be covered.

PO2 and PO3 entail additional measures strengthening early and effective public engagement and fostering public support for renewable energy projects. The measures expressly include provisions aiming at increasing public participation and therefore social acceptance of renewables projects. By revising the current measures on public acceptance of renewable energy projects, the Commission will be able to assess the opportunity to propose the adoption of measures by the Member Staes that could benefit consumers directly or indirectly, e.g. benefit-sharing schemes and job creation. Indirect financial participation may include measures to promote contracts and job creation for local communities, including training programmes; community benefit funds; financial compensations to local communities in proximity of the project; construction and maintenance of public infrastructure in proximity of the project etc. However, the long-term economic benefits can be limited, as maintenance and operational roles are frequently outsourced to external companies rather than creating jobs for residents. For example, benefit-sharing mechanisms in Australia and South Africa encourage domestic production of components and contractually obligated companies to rely on local workers and permanent local employees. This has supported local creation of construction and operation jobs and fostered the development of skills. 147  This will support the EU’s position as a leading job market in the field of renewable energy where it already counts with 1.8 million jobs. 148  The impacts will be the same under PO2 and PO3 as regards benefit-sharing schemes and prospects for local job creation, since PO3 includes alle PO2 measures. 

However, the 28th permitting regime included in PO3 risks significantly deteriorating public acceptance of cross-border projects as they could be perceived as directly imposed by the EU on local communities. Projects subject to this regime, therefore, may risk delays due to court claims linked with public opposition to EU-level decisions.

The social impacts of the security measures relate to avoiding increases in energy prices caused by supply disruptions and related repair costs. The additional measures under PO2 and PO3 further reduce risks of possible supply disruptions. Given the lack of available data on the probability of supply disruptions linked to security incidents, the social impact of the policy options cannot be quantified. However, these avoided costs are expected to be substantially higher than the additional costs incurred by each policy options (Section 6.1.1.) that would be passed through to consumers through network tariffs unless covered by other funding.

6.3.Environmental Impacts

GHG emission reductions would bring positive environmental impacts. In line with the climate law, a huge increase of installed RES capacity is required by 2040 to meet the EU’s CO2 emission targets. A recent JRC study 149 shows the correlation between grid development and amount of curtailed energy, where substantial amounts of renewable generation are curtailed due to grid bottlenecks. While some levels of RES curtailment are projected to occur under all future scenarios, ambitious grid expansion would reduce grid related RES curtailment by 40 TWh in 2030 and 110 TWh in 2040 compared to a BAU scenario.

The positive impact of grid expansion on RES integration is also confirmed in the ENTSO-E analysis: the optimal grid would decrease curtailed renewable energy by 143 TWh in 2040 in the EU. The additional 108 GW cross-border capacities needed by 2040 in line with the 2024 TYNDP would also allow to substitute 65 TWh of electricity produced by gas by RES generation, by allowing a better integration of non-CO2 emitting generation, leading to a significant reduction of European CO2 emissions estimated at 27 million tonnes of CO2 emissions avoided in 2040. 150  

Positive environmental impacts are also illustrated by a recent IEA study 151 , although with limitations as it covers a broader region than only the EU. The IEA came to the conclusions that cumulative CO2 emissions from the power sector from 2023 to 2050 would be 58 gigatonnes higher in the Grid Delay Case than in a scenario aligned with national climate targets. This is equivalent to the total global power sector CO2 emissions from 2018-2022. Specifically for advanced economies, including the EU, the Grid Delay Case results in significantly higher natural gas use beyond 2030, limiting emission reductions in the power sector. 

These positive environmental impacts can be mostly expected from measures included in PO2 and PO3. By supporting fossil fuels phase-out, PO2 and PO3 would also lead to a reduction of non-CO2 emissions. While the cumulative impact is difficult to assess, all TYNDP candidate projects lead to a reduction of non-CO2 emissions regardless of the scenario used (see Table 3 ).

Table 3: Average reduction of non-CO2 emissions for TYNDP 2024 transmission projects in 2040

Source: ENTSO-E

As regards cost and benefit sharing, taking the previous example of offshore projects in the EU’s sea-basin, the implementation of offshore hybrid projects needs which are likely to generate benefits beyond their host countries (25 GW by 2040 and 44 GW by 2050) would result in the following environmental benefits: around 40 TWh of additional RES capacity by 2040 and between 80 and 90 TWh by 2050 resulting in a reduction of more than 4 million tonnes of CO2 emissions by 2040 and an additional reduction of at least 1.2 million tonnes by 2050. If, as for economic impacts, 30-50% of the projects were delayed or were not to materialise, the resulting environmental impacts would be as follows:

Table 4: Possible non-materialised environmental benefits

As established above, ensuring the development of energy infrastructures, especially electricity grids, is essential to increase the share of renewable energy generation integrated in the energy mix, preventing environmental losses due to curtailment. RES integration will allow to curb the use of fossil fuels reducing GHG emissions and thus addressing two major drivers of biodiversity loss: climate change and air pollution. The Commission “EU Climate Action Progress Report 2024” mentions that in 2023 alone, there was an 8.3% GHG emissions drop, clearly linked to a strong transition to renewable energy sources, particularly wind and solar, which now supply nearly 45% of EU electricity.  152 Further, according to the IEA, in different model scenarios, renewables sources account for three-quarters of the CO2 emissions reductions by 2050. 153 Therefore, accelerating permitting procedures for energy infrastructure, storage assets, renewable assets and recharging stations, must be treated as a priority as it will lead to a quicker, and thus larger, reduction of CO2 emissions by ensuring these key assets are in place as soon as possible. 

As regards permitting, PO1 would not produce additional negative impacts on the environment, since it just assists in the implementation of the existing framework, which includes rules related to streamlined environmental assessments under the revised RED. However, as this option does not provide a framework for energy networks, storage and recharging stations in general (only for PCIs/PMIs) the benefits of accelerated RES integration are limited. PO2 and PO3 include measures that aim at faster permits and therefore faster and widespread deployment, which relates to more space being used and therefore have an effect on the environment, but they are designed not to decrease the level of environmental protection. Specifically, the proposed measures on digitalisation and centralisation of data required for environmental assessments would improve and speed up administrative processes, freeing administrative capacity in concerned authorities. This, combined with digitalising and centralising environmental data, would enable a more efficient and effective deployment of mitigation and compensation measures as well as facilitate public access to data on all projects, including those not benefiting from the exemptions proposed.

Relevant impacts 154 on the natural and man-made environment, go beyond GHG and non-CO2 emissions. These impacts are strongly dependent on the technology used and the assets’ location and the environmental status of the surrounding fauna and flora. Therefore, a general quantification of impacts, or generalisation of impacts per project type, is not possible. These impacts are however addressed in the design of the proposed measures through introducing safeguards. In what concerns potential environmental impacts caused, specifically by granting a presumption of overriding public interest for grids projects, this is rebuttable and on the concerned parties to prove that the negative impacts of the project outweighs the benefits it brings, including towards the needed development of the renewable or infrastructure project. At the same time, the exemptions from any permits are set for only certain types of projects with limited impacts on the environment and the exemption from environmental assessments is always combined with the use of appropriate criteria when setting the new rules that aim to keep impacts at a non-significant level. Therefore, the proposed measures take into account both high environmental standards and the need to accelerate grid and renewable energy deployment to meet our 2030 targets.

The environmental impacts of security measures under PO1, PO2 and PO3 relate to avoiding increases in CO2 and non-CO2 emissions caused by supply disruptions and related repair costs.

The environmental impacts of the measures related to smart gas grids and the blending of hydrogen with natural gas would be positive since any possibility to circumvent the discontinuation of support to fossil fuel infrastructure and to “greenwash” projects would be excluded. At the same time, removing the smart gas grids category would be without prejudice to the contribution that biomethane can bring to decarbonisation at the local and national level, which is the more appropriate level for addressing the grid investment challenge. Indeed, the decentralised production of biomethane in small quantities poses logistical challenges, as locally produced biomethane must be served by only a limited number of injection points. 155  

The primarily national dimension of the biomethane grid challenge is underpinned by the need for Member States to reconcile their varying biomethane potentials and ambitions with Article 57 of the Gas Directive, which provides that Member States must ensure that gas distribution system operators develop network decommissioning plans where a reduction in natural gas demand requiring the decommissioning of natural gas distribution networks is expected.

All policy options are consistent with the EU’s long-term decarbonisation and environmental objectives and adhere to the do-no-significant-harm principle. They are also assessed to be consistent with the European Climate Law, as they will contribute to accelerating energy system decarbonisation, the reduction of greenhouse gas emissions in line with the Climate Law, albeit to different extents depending on their ability to achieve the optimal grid scenario.

7.How do the options compare?

Figure 4 provides a comparison of the policy options against the specific objectives showing their increased degree of EU-level coordination, PO1 implying a limited number of changes to the status quo and minimal additional EU level intervention, PO2 a more top-down approach, and PO3 involving the highest degree of top-down approach and streamlining at EU level.

Figure 4: Comparison of policy options against specific objectives

In this section the three policy options are compared against the criteria of effectiveness, efficiency, coherence as well as subsidiarity and proportionality, based on the assessment of the impacts in the previous chapter.

7.1.Effectiveness

Effectiveness concerns the extent to which the general and specific objectives (SO) of the intervention (Section 4) are met. Table 5 links the policy objectives to assessment criteria.

Table 5: Links between objectives and assessment criteria

All policy options contribute to the general objective of timely and efficient development and interoperability of resilient cross-border energy infrastructure, because the proposed measures will improve planning, provide tools to accelerate deployment of priority projects via improved permitting and cost-sharing instruments and enhance resilience of cross-border infrastructure.

Regarding SO1:

-PO1 would be slightly more effective than the BAU in identifying the infrastructure needs based on ex ante steering through framework methodologies by ACER. 

-PO2 and PO3 would be more effective than PO1 in providing for a more robust identification of infrastructure needs which would be based on a comprehensive central scenario. In addition, the needs identification would have to be approved by the Commission and Member States after ACER and NRAs validated the correct application of the framework guidance. Most importantly, only PO2 and PO3 foresee a new planning element for the systematic follow-up of the identified needs with planned projects through the TYNDP and PCI/PMI selection process (‘gap filling mechanism’). The assessment of the impacts of the different options (Section 6) confirmed that ensuring the implementation of a more optimal cross-border infrastructure grid, as would be the case under PO2 and PO3, would lead to significant economic benefits. PO2 and PO3 would also ensure that non-wired solutions are prioritised and internal lines relevant for cross-border electricity trade are adequately reflected in future grid planning and PCI/PMI selections by adjusting the cross-border criteria. 

-The effectiveness of PO3 might be affected by limited and cumbersome access to data and availability of skilled staff as it would to a large extent depend on sufficient access to data and experience from system operation, which might be delivered late or in a poor quality. Similarly, an entity separate from TSOs responsible for the planning of cross-border infrastructure would weaken the link between the planning of cross-border and internal infrastructure. However, a strong link between these planning processes is essential for effective grid planning. In addition, dissociating the responsibility and liability for the secure operation of the system from network planning, the former remaining with TSOs and the latter placed on a single EU entity, could potentially lead to inconsistencies, the identification of non-operational solutions and potentially undermine system security, for which specific safeguards would have to be established. In addition, PO3 could entail delays in terms of implementation as establishing fully functioning network models could take between 5-6 years, postponing achievement of the benefits. For these reasons and considering the aforementioned limitations, at this stage PO3 may not meet the SO1 as effectively as PO2.

Regarding SO2, all policy options would enhance transparency in the cost-sharing process by involving a broader range of stakeholders earlier on. The updated ACER recommendation on the treatment of investment requests for PCIs and PMIs would clarify and streamline procedures, promoting a harmonised approach across Member States and projects. Additionally, the introduction of incentives linked to congestion income could motivate stakeholders to engage more actively in cost-sharing negotiations, potentially reducing the overall costs borne by project beneficiaries.

-PO1 would be more effective than BAU to trigger discussions on cost-sharing but could be insufficient in securing contributions from non-hosting countries, as it relies primarily on improved transparency and clarity. Overall PO1 is considered somewhat effective, but likely not able to reach the SO2. 

-PO2, by providing a framework coupled with strong incentives for the bundling of projects (joint application for PCI/PMI status and possible CEF funding) and associated cost-sharing process, would ensure a more comprehensive approach to cost-sharing. This approach could overcome the reluctance by Member States to contribute financially to projects outside their territory considering that the cluster will be overall beneficial to them and provide access to the benefits under the TEN-E framework.

-PO3, by making mandatory the offshore regional planning would ensure that Member States’ offshore commitments are followed up with regional planning and agreements on cost sharing. However, instead of an incentive-based approach (PO2), this mandatory approach could be considered premature and pre-empting Member States’ own assessments. Based on past experience with bilateral cost-sharing discussions, mandating multilateral cost-sharing agreements at this stage might face opposition from some Member States and ultimately undermine the actual purpose of strengthening regional cooperation for more effective cost sharing.

Concerning SO3, all policy options include permitting acceleration measures.

-PO1 would be more effective than the BAU as it would provide further support and guidance to Member States in implementing the current permitting acceleration framework. However, effectiveness is capped to implementation of current framework, which also does not cover permitting of electricity grids and storage infrastructure. 

-PO2 would introduce legislative amendments ensuring shorter permitting times than the BAU and PO1. It would cover cross-border, national transmission and local distribution grids as well as renewable energy, storage and e-mobility charging infrastructure projects. The proposed measures would result in fewer permitting requirements and shortened procedures and thereby address SO2 more effectively. 

PO3 is expected to have a similar impact with regard to shortening and simplifying national permitting procedures as PO2, as both options include the same measures in this respect. By introducing a centralised 28th regime for monitoring and coordinating permitting procedures for cross-border grids and large-scale cross-border RES projects, PO3 may facilitate national authorities’ interpretation and application of the relevant permitting provisions of EU law. This could result in a more predictable permitting process, preventing situations of preferential treatment and blockage of projects due to national interests. However, PO3 would entail the creation of an additional administrative level to the permitting process, creating further risks of delays in the form of misalignments and of inefficiencies between the EU-level entity and the national authorities. Further, the EU-level entity would lack autonomous competence to decide over permitting procedures (see Section 5.2.1), which raises doubts over the potential coordination benefits. In addition, setting up an EU-level regime to coordinate permitting for cross-border projects would require resources and risks disrupt ongoing permitting procedures and/or delay new ones, though a transitional period could offset this to a certain extent. 156  EU-level permitting monitoring and coordination may also not be welcomed by Member States and other stakeholders, who are mostly calling for targeted changes to the permitting regime to allow sufficient time and resources to implement the existing legislation (see Annex 2).  Finally, it risks undermining public acceptance at local level and may therefore result in additional court cases challenging whether national or local circumstances have been adequately taken into account. The overall effectiveness of PO3 as regards permitting is therefore not ensured.

Finally, as regards SO4:

-Under PO1, the risk assessments reporting would give more prominence to potential physical and cyber-security risks and mitigation measures earlier in the project development cycle

-PO2 and PO3, would provide incentives to enhance security of cross-border energy infrastructure under the TEN-E framework and hence would be more effective.

7.2.Efficiency

Efficiency concerns the ‘extent to which objectives can be achieved for a given cost (cost effectiveness). The Commission also assessed to what extent the options contribute to administrative and process efficiency (reaching objectives with the least administrative burden). In all policy options, the benefits outweigh the increase in costs, relative to the baseline.

As regards SO1:

-PO1 would reduce costs by streamlining the planning steps but would still keep the resource intensive 2-year cycle, which would continue to require significant resources.

-PO2 would be the most cost-efficient option by reducing the frequency of scenarios and needs assessment to 4-year cycles and eliminating some ex-post verification requirements. The new gap filling step would still be less resource intensive than the 2-year cycle. PO2 is also linked to only a limited need of additional resources in terms of staffing.

-PO3 would be equally efficient with PO2 when it comes to reduction of frequency of scenarios and elimination of ex post verification requirements. While bringing a number of competences under one entity could create operational efficiencies, it would require substantial reshuffling of resources and both high upfront administrative costs for the creation of a new entity or a new section under an existing one (see Annex 9)and additional operational costs to run such an entity. Making an entity operational for these tasks is expected to be very resource intensive and disruptive to the governance of infrastructure planning, possibly offsetting potential gains of a centralised and streamlined approach. It would take several years for such an entity to be fully operational, although this would to a certain extent be addressed with transitional measures. 

Regarding SO2:

-PO1 and PO2 are both expected to increase the use of cost-sharing tools and facilitate the acceleration of project implementation, where accepted by all relevant stakeholders. Both options offer tools to achieve SO2 at a relatively similar cost compared to the BAU scenario. Several policy measures under these options help reduce the burden on stakeholders by streamlining and enhancing the transparency of the CBCA process. Measures related to congestion income would generate limited additional compliance costs within existing structures. These measures are considered efficient, as the benefits –particularly in financing cross-border infrastructure and encouraging cost-sharing agreements– are expected to outweigh the associated costs.

-PO2 involves a voluntary process, meaning that any potential additional resources or costs would not be imposed on stakeholders. This would entail significant efficiency gains for Member States and TSOs with a high number of planned hybrid or cross-border radials, since they could bundle projects and simplify cost-sharing frameworks to lower negotiation efforts and, thereby, resources and costs, of conducting multiple and parallel cost-sharing negotiations. 

-PO3 would impose additional costs on all stakeholders as it would require offshore regional planning and cost-sharing agreements. In particular, this would entail costs for Member States and TSOs with a high number of planned hybrid or cross-border radials and hinder the achievement of consensus. In addition, processes would, to a certain extent, overlap with national planning related to cross-border infrastructure, as the approval of investments required at national level.

As for SO3:

-PO1 is more efficient than the BAU scenario, as it supports implementation of acceleration measures at a low cost. However, its effectiveness is significantly lower than PO2 and PO3, while it represents costs for Member States just slightly lower than PO2. This results from the fact that under PO1 Member States are still expected to invest in administrative capacity building.

-Under PO2, costs for Member States increase slightly in the short-term as Member States would be required to introduce and implement legal changes. The costs are, however, likely to significantly decrease in the long-term as a result of digitalisation. Further, the measures on public acceptance and participation, like the benefit-sharing mechanisms for renewable energy projects, will assist in decreasing opposition and lead to less administrative costs in the form of administrative challenges to permits and judicial disputes.

-Under PO3, both upfront and recurrent costs increase due to the need to implement further legislative changes and empower with relevant tasks a permanent European coordination entity. PO3 involves continuous operational costs of such EU body that are not required by PO1 and PO2. PO3 might also entail additional costs to support public acceptance and related to an increase in court cases (see above).

-For both PO2 and PO3, following the initial investment costs, simplification, better coordination and digitalisation of procedures will decrease the relative administrative burden for national authorities leading to efficiency benefits. In comparison, PO2 appears more efficient than PO1 and PO3.

As for security related measures (SO4):

-PO1 enables earlier consideration of security risks during the initial stages of PCI/PMIs development. While the associated measures may incur additional costs for some project promoters, the number of affected promoters is expected to be limited 157 , as most are already subject to comparable obligations under the existing EU regulatory framework. The economic benefits linked to the implementation of identified measures are anticipated to outweigh these costs (see above) and is therefore more efficient than BAU.

-PO2 and PO3 would be significantly more efficient as they also involve broadening the scope of the TEN-E to reinforce EU cross-border energy infrastructure security, as well as additional oversight concerning possible control by untrusted actors over the projects, without incurring additional costs.

7.3.Coherence 

Internal coherence assesses how well the various provisions of the initiative fit together and work in a coordinated manner to achieve its objectives. The measures under each policy option are compatible with each other. However, the effectiveness of some measures may be limited by their co-existence. For PO3, the requirement of mandatory regional planning and cost-sharing are incompatible with the objective of a voluntary enabling framework for project bundling.

As for external coherence, all policy options are consistent with EU and national provisions on infrastructure planning and permitting. PO2 and PO3 would achieve higher coherence by better linking national and EU planning, requiring the use of the central scenario as one of the scenarios as prerequisite for NRA approval of NDPs. The policy options are in line with the EU objective to improve infrastructure planning in the context of the climate transition and complementing other relevant policy initiatives (see Section 1.3 ). All options would align the TEN-E Regulation with the policy framework on hydrogen as established with the hydrogen and gas decarbonisation package by removing smart gas grids and blending from its scope. PO2 and PO3 would also be most coherent with the Commission’s simplification agenda, removing unnecessary provisions related to monitoring and opinions. However, PO3 also brings substantial new administrative implications in terms of setting up new entities or expanding existing ones, and need for related coordination, which may not fully align with the simplification agenda. All policy options are coherent with the existing EU regulatory framework on critical infrastructure protection and cybersecurity, and Foreign Direct Screening Investments. Building on existing provisions and ensuring consistency between regulatory frameworks, they are expected to accelerate implementation of the EU horizontal framework for EU cross-border energy infrastructure.

7.4.Subsidiarity and proportionality

All options fulfil the principle of subsidiarity, as they contribute to market integration through better cross-border energy infrastructure and integration of renewable energy sources. This could not be achieved to the same extent with national measures, especially in cases with cross-border dimension. All options preserve the prerogative of Member States to choose their energy mix, level of competence and cross-border energy infrastructure projects. PO1 provides for the lowest level of intervention but is not sufficiently effective in meeting the initiative’s objectives. PO2 entails a more top-down approach with new responsibilities at EU level while maintaining and strengthening competences at national level and is therefore considered following the subsidiarity principle. PO3 entails the most intensive intervention through an EU level entity for cross-border infrastructure planning, prescribing regional planning and cost-sharing, and introducing a 28th regime for permitting of cross-border infrastructure projects based on a permanent European permitting coordination authority. This option may therefore be seen by Member States and stakeholders as interfering too much with national processes. A more top-down infrastructure planning approach at EU-level could improve alignment between national and EU-level objectives. However, as described in Section 5.2, approval by Member States is still required in line with the subsidiarity principle enshrined in the TFEU making the close involvement of the relevant national actors, which in any case have the best information regarding national grid characteristics, inevitable. Similarly, as regards a centralised permitting regime coordinated at the European level and implemented by an EU. entity, the EU regime would come on top of national frameworks, requiring the permanent EU Authority to liaise with national and local authorities to verify that the necessary approvals are granted on time, without having direct impact on the national procedures.

As for proportionality, PO1 and to a significantly larger extent PO2 contribute to improving the more rapid and targeted development of cross-border energy infrastructure, renewable energy, storage and recharging stations effectively, without imposing significant costs for TSOs/project promoters and Member States, NRAs and ACER. PO3 may raise concerns of disproportionality, due to the involvement of new EU-level entities as regards infrastructure planning and permitting with significant implications both in terms of the costs needed to set-up and operate the new entities as well as the greater top-down EU-level involvement in the network planning and permitting processes.. Creating a new entity or using an existing entity for the purpose of cross-border infrastructure planning may be considered disproportionate in comparison to the expected effectiveness and costs-efficiency of the measure (Sections 7.1 & 7,2)., and considering energy system planning aspects would remain at Member State level due to their responsibility for infrastructure planning and their right of approval as guaranteed under Article 172 TFEU. Mandatory regional planning and CBCAs within EU’s sea-basins is considered disproportionate as imposing such binding processes at this stage, possibly undermining trust and overall willingness to engage in such processes. Similarly, the 28th regime for permitting would have considerable limitations in effectiveness as well as cost implications (Sections 7.1 & 7.2), raising concerns over the proportionality of this option. PO2 would appear more proportional to the nature of the problem by focussing on streamlining the current processes and offering new substantive tools that are considered effective to meet the objectives of this initiative without imposing significant additional costs.

7.5.Summary

Table 6 provides a summary of the comparison of the options against the baseline scenario in terms of effectiveness, efficiency, coherence, subsidiarity and proportionality. The following ranking symbols have been used: from '+' (more effective/efficient/coherent/ proportionate than the baseline) to '+++' (much more effective/efficient/coherent/ proportionate than the baseline); from '-' (less effective/efficient/ coherent/proportionate than the baseline) to '---' (much less effective/efficient/coherent/proportionate than the baseline). See Annex 11 for a detailed comparison. The policy measures under each option do not all carry the same weight in the comparison of each option, as certain measures are expected to have a more significant impact than others on achieving the objectives of the initiative.

Table 6: Comparison of the policy options

8.Preferred option

8.1.Identification of preferred policy option

All policy options address the identified problems and their drivers and contribute to achieving the specific and general objectives, although with a different level of effectiveness and efficiency.

From the comparison of the policy options in section 7, PO2 and PO3 are significantly more effective, more efficient and more coherent with the overall EU policy framework than PO1. PO1 only performs slightly better in terms of subsidiarity and proportionality compared to PO2 and PO3. Therefore, PO1 is not considered as possible preferred policy option.

While PO2 and PO3 both perform better than PO1 as concerning their effectiveness in meeting the specific objectives, PO2 seems overall more effective at this stage. when it comes to ensuring that projects included in network plans and selected as PCI/PMIs address appropriately identified infrastructure needs as well as to shorten and simplify permitting procedures. As regards the efficiency of PO2 and PO3, PO3 on balance is considered less efficient due to the additional resources needed and high-up front costs coupled with potentially lengthy implementation times to set up two new entities at EU level (or reinforce existing ones) responsible for infrastructure planning and coordinated permitting procedures. In terms of subsidiarity and proportionality, measures proposed in PO3 (EU entities responsible for infrastructure planning and permitting as well as mandatory offshore grid planning) with a high degree of EU level intervention appear disproportionate at this stage considering they do not result in a higher level of effectiveness and are expected to entail substantially higher additional costs.

Without prejudice to political considerations and the final Commission legislative proposal for the European Grids Package, based on the technical assessment presented in this document, PO2 appears as the preferred option. It is expected to enable achievement of the specific objectives to ensure projects included in the network development plans and selected as PCIs/PMIs effectively address identified infrastructure needs in line with the optimal grid scenario, to ensure an increased use of cost-sharing tools and reduced project deployment time for cross-border projects, to ensure a shorten the necessary times to obtain permits and to enhance physical and cyber security resilience of cross-border infrastructure.

The preferred policy option is largely in line with the views expressed by stakeholders in the public consultation (see Section 5.2.2 and Annex 2) including by strengthening tools to address infrastructure gaps, better reflecting internal reinforcements and non-wire solutions in infrastructure needs identification, streamlining PCI/PMI application procedure for mature projects. It strikes a balance between a full top-down approach and a bottom-up approach, thus also taking under consideration the mixed views of stakeholders in this respect. In addition, it addresses shortcomings of the CBCA framework indicated by stakeholders and promotes bundling of projects. The preferred option addresses delays to permitting procedures which was highlighted as a key barrier by stakeholders, through measures such as digitalisation and shortening/setting of deadlines, which received broad support in the consultation. Finally, it includes measures to strengthen the energy-security dimension of the EU’s infrastructure framework in line which was highlighted by stakeholders as being insufficient.

8.2. REFIT (simplification and improved efficiency)

The preferred policy option (PO2) brings positive impacts in terms of simplification and improved efficiency. The following measures would reduce compliance and regulatory costs:

·Removal of opinions by ACER and the Commission on draft scenarios and draft infrastructure gaps identification reports as these take in total 6 months and their impact on final deliverable is limited due to late delivery in the process. These ‘ex post’ measures would be replaced by ‘ex ante’ measures.

·Removal of ACER opinion on draft PCI/PMI list in particular on the consistent application of the criteria and the cost-benefit analysis across regions. The opinion comes late in the process – after the validation of the draft lists by the technical decision-making body of the regional groups – and hence has very limited impact on the final outcome. Instead, the use of the existing ACER PCI/PMI monitoring and NRA assessment would be strengthened in the PCI/PMI selection process so that these results could be more visible and taken into account in the assessment of candidate projects.

·Simplified application/evaluation process for mature PCIs and PMIs. PCIs and PMIs which have already reached final investment decision or regulatory approval in such a way that the progress of the project is irreversible, or have received a CEF grant for works and show continued progress in their implementation, should retain their PCI/PMI status without the need for reassessment.

·Streamlining the use of priority corridors and Regional Groups to have leaner and more agile approach adapted to changing circumstances.

·Streamlining the CBCA process through enhanced transparency of project specific benefits early in the infrastructure planning process and an updated CBCA Recommendation from ACER will facilitate processes for TSOs and NRAs. 

·Shortening permitting deadlines simplifies the process and clarifies the existing framework, reduces the administrative burden on promoters.

8.3.Application of the ‘one in, one out’ approach 

The preferred policy option (PO2) imposes limited additional administrative and adjustment costs on businesses, which would mainly affect TSOs (see Annex 3 and Section 6.1.4). The costs created by the measures under the preferred option (PO2) relate to new security reporting requirements for TSO and project promoters, and a requirement for TSOs to engage in the gap filling mechanism. These costs would either be limited to a small share of TSOs/project promoters or be offset by other measures. Notably, as regards infrastructure planning, the administrative burden on ENTSOs, TSOs and project promoters is expected to be reduced as a result of the Commission taking over central scenario development and simplifications such as the reduced frequency of the TYNDP processes and the simplified application and evaluation process for mature PCIs. The streamlined, simplified and digitalised permitting procedures would also reduce the administrative burden for businesses. The annual costs savings for businesses cannot be fully estimated as relevant data were not available, but it can be concluded that the preferred policy option would lead to recurrent cost saving. In terms of adjustment costs and administrative costs for citizens, the preferred option is not expected to entail any costs. While the costs are limited or non-existent for businesses and citizens, the preferred option would create additional adjustment and administrative costs for the European Commission and ACER, which would take on a greater role in infrastructure planning, and national as well as local authorities for permitting procedures.

9.How will actual impacts be monitored and evaluated?

The Commission will monitor and evaluate the impacts of the legislation against a set of indicators allowing to measure progress in achieving the specific. The monitoring builds on a well-established monitoring system under the existing TEN-E framework where ACER and the Regional Groups monitor the progress of projects implementation. Project promoters will continue to submit annual reports to the national competent authorities, which are then subsequently sent to ACER, which consolidates the reports and submits updates to the Regional Groups. This regular reporting provides information on the progress achieved, possible delays and plans to overcome them. These monitoring arrangements are complemented by detailed monitoring by CINEA for PCIs and PMIs that receive grants under CEF.

With regards to permitting measures, the Commission will also rely on the existing channels of interaction with Member States’ authorities and relevant stakeholders 158 to monitor implementation of the new measures and potential issues. The effects on renewables generation and integration are also covered by the annual reporting done by Member States. Further, new measures on digitalisation and centralisation of information on permitting procedures will enable an improved management of permit applications by national authorities.

A review of the effectiveness of the new legislation could take place by the end of 2032, when 2 new PCI and PMI selection procedures will have been completed and providing sufficient time for the transposition and implementation of amendments to other legislations in relation to permitting.

The success of the preferred policy option can be measured against operational objectives based on a set of indicators as listed in Annex 8 in particular addressing:

·the extent to which projects included in network developments and selected as PCIs/PMIs address appropriately and effectively identified infrastructure needs;

·the effective use of cost-sharing tools;

·the shortening of permitting procedures;

·the enhanced physical and cyber security and resilience of energy infrastructure.

Annex 1: Procedural information

1.Lead DG, Decide Planning/CWP references

The Directorate-General (DG) for Energy was leading the preparation of this initiative and the work on the Impact Assessment in the European Commission. The planning entry was approved in Decide Planning under the reference PLAN/2024/2554. It is not included in the Commission Work Programme 2025.

2.Organisation and timing

The initially planned adoption date (Q1 2026) included in the Clean Industrial Deal and the Affordable Energy Action plan was anticipated to Q4 2025 due to the urgency of the initiative. An inter-service steering group (ISG) was established for preparing this initiative composed of the following Commission services: Secretariat General (SG), CLIMA, GROW, ENEST, REGIO, ENV, JRC, MOVE, HOME, ECFIN, MOVE, TRADE, COMP, SJ. The ISG met 3 times in the period from April until adoption in December 2025.

3.Consultation of the RSB

The Impact Assessment report was submitted to the Regulatory Scrutiny Board (RSB) on 27 August 2025. It was presented and discussed with the RSB on 24 September 2025. The RSB gave a positive opinion with reservations on 26The below tables summarise how the revised Impact Assessment report addresses the requested improvements.

4.Evidence, sources and quality

The impact assessment draws on evidence from implementation reports, the stakeholder input to the extensive consultations carried out in this respect, as well as from the results of a series of topical studies on key elements of the TEN-E Regulation, which will be presented below.

Formal conclusions adopted in the framework of the Copenhagen Forum in 2023, 2024 and 2025 were also considered in the analysis. The Copenhagen Forum gathers annually representatives of the EU institutions, transmission system operators, project promoters, regulators, energy companies, NGOs and civil society and the financing community to discuss the challenges of developing Europe’s energy infrastructure.

ACER’s annual consolidated monitoring reports on the progress of electricity and gas PCIs, incremental capacity projects and virtual interconnection points, on the electricity and gas market monitoring and capacity allocation and congestion management, as well as other updates on the cross-border cost allocation decisions, project-specific risk-based incentives were equally considered.

Further information was gathered through several support studies previously commissioned to external contractors to support the development of policy options and assessment on:

Investment needs in infrastructure, infrastructure planning and costs of delays

·European Commission: Directorate-General for Energy, Artelys, LBST, Trinomics, Finesso, A. et al., Investment needs of European energy infrastructure to enable a decarbonised economy – Final report, Publications Office of the European Union, 2025, https://data.europa.eu/doi/10.2833/8232521

·European Commission: Directorate-General for Energy, Fraunhofer, Guidehouse et. al. Study on network development planning, tariff structures and connection requests for electricity distribution grids – Final report, Publications Office of the European Union, 2025,

·European Commission, Joint Research Centre, Thomassen, G., Fuhrmanek, A., Cadenovic, R., Pozo Camara, D. and Vitiello, S., Redispatch and Congestion Management, Publications Office of the European Union, Luxembourg, 2024, https://data.europa.eu/doi/10.2760/853898 , JRC137685. 

·ENTSO-E: Opportunities for a more efficient European power system by 2050: TYNDP 2024 Infrastructure Gaps Report, 2025, https://eepublicdownloads.blob.core.windows.net/public-cdn-container/tyndp-documents/TYNDP2024/foropinion/Infrastructure_Gaps_Report.pdf  

Permitting and delays in projects implementation

·Directorate-General for Energy, Milieu, Bruggeman, V., Vona, L., Moreira, G. et al., Study on national permit granting process applicable to energy transmission infrastructure projects with a focus on projects of common interest and projects of mutual interest under Chapter III of Regulation (EU) 2022/869 – Overview report, Publications Office of the European Union, 2025, https://data.europa.eu/doi/10.2833/2566900  

·Technical support for RES policy development and implementation – simplification of permission and administrative procedures for RES installations https://op.europa.eu/en/publication-detail/-/publication/949ddae8-0674-11ee-b12e-01aa75ed71a1

Annex 2: Stakeholder consultation (Synopsis report)

This annex provides a summary of the outcomes of the consultation activities carried out for the preparation of the European Grids Package. In line with the Better Regulation guidelines, the Commission carried out a comprehensive consultation based on a consultation strategy that included a range of consultation methods and tools that combined both backward and forward-looking elements. The strategy was designed in line with the intervention logic.

The consultation strategy aimed to ensure that all relevant evidence were taken into account, including data about costs, societal impact, and the potential benefits of the initiative.

In line with the Better Regulation guidelines, the goal of the stakeholder consultation was:

·To collect views, experience and concrete examples from stakeholders that will illustrate particular opportunities, challenges and impacts resulting from the implementation of the EU legal framework for grids, in particular the TEN-E Regulation, as well as relevant permitting provisions with the view to fill any potential information/data gaps, and facilitate the analysis of the different evaluation criteria;

·To solicit opinions on the extent to which the current legal framework is meeting its objectives.

As a crucial part of the data collection strategy for the evaluation and the forward-looking elements in the impact assessment, a stakeholder mapping exercise has been carried out in order to identify and group the main stakeholders that are involved in and affected by the initiative. The consultation targeted stakeholders inside the EU, both at national and European level. In force since 2022, the current TEN-E Regulation has built an established and well-defined group of stakeholders.

The consultation strategy included a combination of consultation methods (i.e. open/targeted) and tools (including an online public consultation and in-depth interviews) to provide well-reasoned responses and generate the information and evidence necessary to respond to the evaluation questions and inform forward-looking elements in the policy preparation. In particular, an online public consultation was conducted, giving all interested stakeholders and opportunity to submit evidence, provide their views and respond to the structured questionnaire (please see below).

1. Results of the Open Public Consultation

An online open public consultation (OPC) was undertaken between 13 May to 5 August 2025 on the ‘Have Your Say’ website. All interested parties were invited to contribute their views on the performance of the TEN-E Regulation, related legal provisions, and areas where further EU action may be needed.

Moreover, the questionnaire for the OPC did not cover all evaluation criteria, but rather non-technical elements on which citizens and the general public can share their views. The consultation covered the following topics: i) the general functioning of the TEN-E Regulation, ii) EU infrastructure planning, iii) electricity network planning at national level, iv) electricity grid hosting capacity, v) permitting, vi) investments in grid infrastructure, vii) supply chains, viii) digitalisation and resilience, and ix) simplification.

The consultation received a total of 197 responses. In addition, 2 emails were received via a functional mailbox for the consultation. There were 197 responses to every multiple-choice question in the OPC, meaning that every respondent answered each question. For some questions, respondents were asked on a five-point scale the extent to which they agreed or disagreed with statements. The scale was i) Strongly disagree ii) Slightly disagree, iii) Neutral, iv) Slightly agree, v) Strongly agree. A “don’t know” option was also given. For the purposes of this analysis, responses marked as "strongly agree" and "slightly agree" are grouped under "agree," and similarly, "strongly disagree" and "slightly disagree" are grouped under "disagree".

Table 8 provides an overview of the stakeholder categories participating in the OPC and a brief description of each group's role and relevance to the consultation, ranked according to their respective share of the total consultation responses. The list demonstrates a good coverage of all parties affected by the Regulation.  The main category of respondents were companies (90 responses, 45.7% of total), followed by business associations (54 responses, 27.4% of total), NGOs (14 responses, 7.1% of total), EU citizens (12 responses, 6.1% of total), and public authorities (10 responses, 5.1% of total).

Table 8: Distribution of responses to the consultation by category

Furthermore, to analyse the responses in more depth, the stakeholder category ''Company/ business'' was divided into further subcategories. The analysis details the responses of each subcategory of companies/businesses, where a sizable variance can be seen. It should be noted that, when dividing responses into subcategories, desk research on the respective stakeholder as well as professional judgement was used for the disaggregation; this therefore does not represent a classification explicitly provided by the respondents. The subcategories identified and the distribution of respondents are as follows: 27 TSOs, 13 DSOs, 19 Project promoters, 21 Energy generator/suppliers, 8 Energy offtakers, and 2 can be classified as other. 159

In terms of the distribution of responses to the OPC by country (see Figure 5), most responses were received from Belgium (46 responses, 23.4% of total), followed by Germany (24 responses, 12.2% of total), and Italy (16 responses, 8.1% of total).    

Figure 5: Distribution of responses per country

2.Findings

2.1.General questions

When asked to what extent the current EU legal framework for grids delivers on its main objectives (market integration, interconnections, competition/affordable energy prices, energy security), more than half of respondents (53%; companies 56%, business associations 50%, NGOs 43%, public authorities 60%) agreed that it supports market integration, while 12% expressed neutrality and 6% were unsure. Less than half of respondents (40%; companies 41%, business associations 39%, NGOs 14%, public authorities 70%) agreed that it supports interconnections, with 20% expressing neutrality and 8% reporting uncertainty.

Overall, public authorities believe that the framework performs well on interconnections: one public authority mentioned that, for interconnections, there is no reason to expand the legal framework as certain benefits were seen for border connections. Further, another public authority mentioned that the current legal framework has enabled a high level of integration of national markets, which should be seen as a positive outcome, as it has allowed wholesale markets to reach satisfactory levels of liquidity and foster stronger complementarities between markets.

Slightly higher levels of support (45% agreement; companies 49%, business associations 54%, NGOs 14%, public authorities 40%) were observed for energy security, with 15% expressing a neutral stance and 3% being uncertain. Less than a third of respondents (30%; companies 31%, business associations 31%, NGOs 21%, public authorities 50%) agreed that the legal framework supports competitiveness (energy price affordability), while 20% expressed a neutral stance and 3% were unsure.

Regarding key barriers to developing grid infrastructure at the necessary pace for the energy transition, most respondents ranked lengthy permitting as the leading obstacle (78%; companies 83%, business associations 89%, NGOs 57%, public authorities 40%), followed by insufficient financing (59%; companies 61%, business associations 67%, NGOs 36%, public authorities 40%) and regulatory uncertainty (58%; companies 69%, business associations 56%, NGOs 43%, public authorities 40%). Several TSOs and DSOs mentioned that the current permitting procedures for grid infrastructure are too long, leading to significant delays in the overall process. Further comments were made by TSOs about insufficient funding as one of the reasons for major grid delays. One TSO stated that currently TSO face unprecedented investment needs to meet the current demand of the energy transition, and a further TSO argued for the need of improved national regulatory funding models to encourage grid investments.

About a third of respondents, also pointed to additional challenges, including a lack of skilled workforce and poor coordination between grid planning and energy transition needs.

2.2.EU Infrastructure planning

Respondents were asked to assess whether the current framework for the Ten-Year Network Development Plan (TYNDP) and national transmission development plans ensure integrated and coherent planning across EU and national levels. Little more than a third of respondents (37%; companies 44%, business associations 37%, NGOs 7%, public authorities 30%) agreed with the statement, while a similar proportion (34%) disagreed, 14% expressed neutrality and 15% were uncertain.

Views on the extent to which the TYNDP identifies all cross-border infrastructure needs were mixed: 34% (companies 37%, business associations 33%, NGOs 14%, public authorities 20%) agreed, 22% expressed neutrality and 18% were uncertain. In terms of addressing relevant projects to close infrastructure gaps, only 18% said the TYNDP sufficiently captures these needs, while 44% (companies 37%, business associations 43%, NGOs 86%, public authorities 50%) believed it falls short, 22% expressed neutrality and 16% reported uncertainty. When analysing the replies of stakeholders that strongly disagree that the TYNDP sufficiently captures project needs, stakeholders mentioned that a stronger alignment is needed between the TYNDP, national development plans and EU level scenarios. Further, another stakeholder mentioned that the current TYNDP framework is not sufficiently adapted to the realities of more isolated regions, like island regions where systems are not physically interconnected with Mainland Europe. A further criticism mentioned is the absence of views and plans of DSOs DNDP in the TYNDP and the build-up of future scenarios.

When asked whether the TYNDP should have a more top-down European approach to infrastructure planning aimed at aligning network development with EU and Member State climate and energy goals, 41% of respondents (companies 41%, business associations 43%, NGOs 14%, public authorities 40%) expressed disagreement and 36% reported agreement (12% of respondents expressed a neutral stance, 11% did not know). Note that there is wide variance in responses within the company category. While a strong majority (70%) of TSOs disagreed with the statement, only 19% of project promotors, 29% of energy suppliers, 38% of energy offtakers, and 46% of DSOs disagreed.

Similarly, 41% of respondents (companies 42%, business associations 46%, NGOs 7%, public authorities 30%) expressed disagreement with the TYNDP having a more top-down European approach to better link identified needs and priority projects of common European interest (agreement 36%, neutrality 12%, uncertainty 12%). Note that variance in responses within the company category mirrors the previous question. While a strong majority (70%) of TSOs and DSOs (62%) disagreed with the statement, only 19% of project promotors, 24% of energy suppliers, and 38% of energy offtakers disagreed.

Yet, a majority of respondents (60%) (companies 53%, business associations 70%, NGOs 100%, public authorities 50%) agreed that national projects should more clearly support EU-wide priorities (17% was neutral and 13% uncertain). For those respondents who agreed, the argument of serving pan-European interests was mentioned, especially for interconnectors. Further, one TSO mentioned the need for a more top-down European view in identifying cross-border needs, although the implementation of projects should remain at the regional level. Further, several stakeholders mentioned that the TYNDP should adopt a stronger top-down European approach to identify cross-border infrastructure needs and should go beyond the current bottom-up project collection.

When asked which elements should be included in the EU-level needs identification, a large majority of respondents (76%; companies 79%, business associations 76%, NGOs 93%, public authorities 70%) favoured the inclusion of cross-border projects, as well as internal reinforcements required to support those projects (72%; companies 66%, business associations 78%, NGOs 93%, public authorities 70%), and the adoption of a cross-sectoral planning approach (71%; companies 64%, business associations 87%, NGOs 86%, public authorities 50%).

Additionally, 64% of respondents supported the idea of establishing connections with third countries, and 54% supported the inclusion of non-infrastructure solutions such as grid-enhancing technologies.

On whether the current two-year frequency of the system needs identification and scenario-building processes is appropriate, the vast majority, about 85% of respondents, found the current interval suitable; others suggested alternatives, particularly annual simplified updates. Finally, 54% of the respondents (companies 49%, business associations 63%, NGOs 71%, public authorities 40%) indicated that the governance framework of the TYNDP, including stakeholder roles, should be revised to enhance its effectiveness. Note there is a wide variance in responses within the company category. A strong majority (70%) of TSOs disagreed with the statement, followed by 50% of project promotors, energy offtakers and others and only 31% of DSOs and 38% of energy suppliers.

2.3.Electricity network planning at national level

Half of respondents (companies 61%, business associations 46%, NGOs 14%, public authorities 50%) considered the current legal framework for transmission network planning fit for purpose. Note there is a wide variance in responses within the company category. Whereas a vast majority of TSOs (85%), DSOs (62%), energy suppliers (76%) and 50% of energy offtakers and other companies agreed with the statement, 84% of project promoters disagreed. Furthermore, a majority, 61% (companies 56%, business associations 61%, NGOs 93%, public authorities 60%) highlighted the need for stronger alignment between Member States in national transmission development plans. In the company category, 78% of TSOs and 54% of DSOs stated that they consider there to be sufficient alignment, whereas 52% of energy suppliers, 88% of energy offtakers and nearly all (95%) project promotors expressed disagreement with the statement.

A larger majority, 73% (companies 69%, business associations 76%, NGOs 93%, public authorities 60%) supported the idea of a need for better alignment between national transmission and distribution network development plans across the EU. From the company category, a strong majority of project promotors (95%), DSOs (77%), energy offtakers (75%) and energy suppliers (67%) expressed this need, against only 48% of TSOs. Among the reasons mentioned were increased transparency and that DSOs should be part of the scenario-building process in the TYNDPs. One respondent stated that there is currently insufficient linkage between national and cross-border plans and that national development plans currently support national needs, but are not necessarily linked to identifying that support optimum cross-border growth.

Among the elements identified for improvement, common scenarios were the top choice, though still supported by little less than half of respondents (48%; companies 44%, business associations 50%, NGOs 86%, public authorities 40%), followed by alignment of planning scope and outlook period (43%).

Concerning the national distribution network development plans, 34% of respondents agreed that the existing legal framework is not fit for purpose (companies 24%, business associations 44%, NGOs 50%, public authorities 50%), while 16% were neutral and 23% expressed uncertainty. Regarding whether the coverage of small DSOs is sufficient, 30% of respondents were uncertain (companies 39%, business associations 30%, NGOs 21%, public authorities 20%), 30% disagreed, and 21% were neutral. On whether there is sufficient transparency of distribution network development plans, 37% disagreed (companies 28%, business associations 39%, NGOs 71%, public authorities 30%), with 17% neutral and 20% uncertain. Similarly, 37% of respondents found the implementation of these plans insufficient and that their objectives are not met (companies 26%, business associations 37%, NGOs 64%, public authorities 70%), while 17% were neutral and 24% uncertain.

Respondents mentioned the plans lack standardisation and could benefit from a more holistic approach, with better coordination when implementing the plans. It was mentioned that DSOs across the EU can benefit from sharing the DNDPs through a common EU repository to enhance cooperation and share best practices. When asked whether distribution grid operators have sufficient capacity to properly plan distribution grids, 27% expressed uncertainty (companies 34%, business associations 30%, NGOs 29%, public authorities 10%), 27% disagreed, and 21% were neutral. Finally, 29% agreed that stronger coordination of distribution network planning is needed at the EU level (companies 23%, business associations 33%, NGOs 64%, public authorities 30%), with 20% neutral and 24% uncertain.

2.4.Permitting

About a third of respondents (34%; companies 36%, business associations 37%, NGOs 14%, public authorities 10%) reported that the permitting provisions of the TEN-E regulation are not clear and easy to implement, with 16% remaining neutral and 34% unsure. A vast majority of 83% (companies 92%, business associations 83%, NGOs 29%, public authorities 70%) supported simplifying and streamlining environmental assessments (only 5% neutral and 5% uncertain). Similarly, 82% of respondents (companies 83%, business associations 81%, NGOs 79%, public authorities 80%) agreed that permitting procedures should be fully digitalised (only 7% neutral and 9% uncertain). Additionally, 77% of respondents (companies 78%, business associations 85%, NGOs 50%, public authorities 70%) agreed that deadlines for the permitting of networks should be shortened or established where missing, with only 7% neutral and 9% uncertain.

Moreover, 64% of respondents agreed that permitting procedures for storage assets should be simplified (companies 59%, business associations 81%, NGOs 50%, public authorities 70%), with 13% remaining neutral and 18% uncertain. Slightly more (69%) supported simplifying permitting procedures for distribution network projects, small-scale renewable projects, and activities such as repurposing, refurbishment, and repowering (companies 67%, business associations 80%, NGOs 50%, public authorities 60%), while 8% were neutral and 19% uncertain. Furthermore, 71% agreed that permitting procedures for hybrid projects (those combining different technologies, including storage) and other innovative solutions should be simplified (companies 72%, business associations 85%, NGOs 43%, public authorities 60%), with 11% neutral and 14% uncertain.

2.5.Facilitating investments in grid infrastructure

As regards the functioning of the cross-border cost-allocation (CBCA) framework under the TEN-E Regulation, 38% of the participants (companies 40%, business associations 37%, NGOs 36%, public authorities 20%) stated that the framework is not fit for purpose, while 20% of respondents remained neutral and 35% expressed no opinion. Participants cited CBCA’s complexity, lack of transparency, and failure to incentivise cooperation among non-hosting countries. They also highlighted the need for alternative financing mechanisms, clearer cost-sharing models, and stronger political commitment to support cross-border infrastructure investments.

In total, 37% of respondents (companies 30%, business associations 39%, NGOs 43%, public authorities 30%) thought that an investment request within the CBCA framework could also cover several projects (‘bundling’) to facilitate cost sharing amongst more Member State beneficiaries – importantly, 25% were neutral and 32% uncertain. Similarly, 36% (companies 31%, business associations 35%, NGOs 57%, public authorities 30%) favoured that the CBCA framework further develops to facilitate the sharing of investment costs among countries, beyond hosting Member States, in proportion to the expected benefits – importantly, 18% were neutral and 31% uncertain.

On the role of involved actors (Member States, NRAs, ACER, TSOs), 34% (companies 33%, business associations 33%, NGOs 43%, public authorities 20%) supported revising their responsibilities to improve the process, while 22% expressed neutrality and 32% uncertainty. When asked about other instruments beyond CBCA that should be considered or modified to facilitate financing of cross-border infrastructure, 20% (companies 18%, business associations 20%, NGOs 21%, public authorities 40%) favoured sharing congestion income, 18% agreed with the Inter-Transmission System Operator Compensation (ITC) mechanism, 17% preferred a common/regional RAB, and 8% endorsed ex post conditionalities.

Regulatory risk (70%; companies 79%, business associations 67%, NGOs 57%, public authorities 30% - only 8% expressed neutrality and 14% uncertainty) and access to public funding (70%; companies 76%, business associations 70%, NGOs 64%, public authorities 40% - only 11% expressed neutrality and 13% uncertainty) were identified as the most significant financial obstacles to infrastructure investment, followed by access to equity (55%), access to debt (53%), and access to counter-guarantees (44%). Respondents pointed out that the current regulatory and financial environment is generally covers the needs, but required investments for the energy transition increase uncertainty, particularly in the development of hydrogen infrastructure. Respondents also proposed improving grid digitalisation, streamlining permitting procedures, and enhancing coordination between stakeholders to reduce investment risks. They emphasised the need for regulatory clarity, political commitment, and better planning to attract private capital and support long-term infrastructure development.

2.6.Supply chains

Supply chain constraints and shortages in skilled labour appeared to remain key obstacles to grid development. When asked whether current EU and national network development plans offer sufficient visibility for supply chain investment planning, more than a third of respondents (37%; companies 39%, business associations 37%, NGOs 50%, public authorities 10%) disagreed, with 23% remaining neutral and 15% uncertain. Additionally, half of the respondents (51%; companies 57%, business associations 56%, NGOs 57%, public authorities 20%) agreed that there is a need for better visibility to ensure sufficient investment in the supply chains, with 20% remaining neutral and 16% abstaining.

Regarding the need for harmonisation of equipment requirements across the EU, a similar fraction of respondents (52%; companies 52%, business associations 44%, NGOs 50%, public authorities 50%) agreed that this idea would help scale up production and repair capacities, while 19% were neutral and 17% uncertain. Moreover, 66% of respondents (companies 71%, business associations 67%, NGOs 36%, public authorities 20%) agreed that further EU-level action is needed to address supply chain bottlenecks, while 12% were neutral and 14% uncertain. A slightly lower fraction though still a majority of respondents (60%) (companies 56%, business associations 74%, NGOs 43%, public authorities 40%) agreed on the need for additional EU action in the field of skills for the energy sector, following recent initiatives such as the Union of Skills, while 18% were neutral and 16% uncertain.

2.7.Digitalisation and resilience

On whether more EU-level action is needed to enhance the visibility and quantified benefits of digital, innovative, and grid-enhancing technologies, 62% of respondents (companies 56%, business associations 67%, NGOs 79%, public authorities 50%) agreed, with 14% reporting neutrality and 8% uncertainty. A larger majority, 76% (companies 71%, business associations 78%, NGOs 86%, public authorities 90%) argued that further measures are needed to increase the efficiency of the existing grid.

With respect to flexibility planning, about a third of participants (31%; companies 33%, business associations 31%, NGOs 14%, public authorities 20%) agreed that the current regulatory framework sufficiently integrates flexibility needs into network planning and development, with 16% showing neutrality and 8% uncertainty.

On the topic of security and resilience, 38% of respondents (companies 37%, business associations 44%, NGOs 36%, public authorities 40%) advocated that the EU legal framework, beyond the TEN-E Regulation, does not sufficiently address emerging risks such as climate change impacts; however, 18% of respondents were neutral and 32% uncertain. Moreover, 36% (companies 33%, business associations 31%, NGOs 29%, public authorities 60%) agreed that extra security criteria for PCIs and PMIs to enhance protection against physical and cyber risks are needed, with 14% indicating neutrality and 27% uncertainty. Furthermore, only 14% indicated that the framework addresses the exclusion of non-trusted actors from participating in critical infrastructure projects, with 19% revealing neutrality and almost a majority, 45% (companies 41%, business associations 48%, NGOs 86%, public authorities 40%) being uncertain.

2.8.Simplification

When asked about simplifying the PCI/PMI selection process, 42% of respondents (companies 50%, business associations 28%, NGOs 29%, public authorities 30%) opposed the idea of reducing the current frequency of the selection process (every two years), for example to every three years, with 17% remaining neutral and 28% uncertain. A majority of 59% (companies 63%, business associations 57%, NGOs 36%, public authorities 50% - 12% neutral and 25% uncertain) agreed that projects with PCI/PMI status should not be required to reapply for each PCI/PMI process, provided certain conditions are met, and also advocated that the application process should be further simplified (companies 63%, business associations 61%, NGOs 21%, public authorities 40% - 12% neutral and 24% uncertain).

Within the company subcategory, opinions vary significantly. 93% of the TSOs, 67% of the energy suppliers and 50% of the energy offtakers agree that projects with PCI/PMI status should not be required to reapply for each selection process. In contrast, only 46% of DSOs and 31% of the project promoters support this exemption.

Some stakeholders advocated for other ways to simplify the PCI/PMI process and to reduce its length, for example by adopting a lighter approach to maintaining its PCI status for reapplication. Further suggestions to improve the PCI/PMI status mentioned for the application to be reviewed only on a limited number of occasions and questioned only in case of major discrepancies between the situation when it was awarded and the latest set of scenarios. One stakeholder mentioned that this would help avoid diverting scarce resources from project promoters and decrease the uncertainty they face when preparing their project financing.

A similar pattern is observed for the simplification of the application process. Support is the highest among TSOs (74%), energy generators (76%), DSOs (54%), and energy offtakers (50%), while only 44% of the project promoters agree with simplification of the application process.

Regarding additional simplification measures, 45% (companies 50%, business associations 46%, NGOs 14%, public authorities 30%) agreed on simplification in PCI/PMI project monitoring and reporting, 160 followed by 38% supporting simplification in the TYNDP process, and 31% favouring simplification in the offshore network development planning process. One stakeholder mentioned that the PCI/PMI project monitoring and reporting should be harmonised by bundling data collection activities and submission to a single platform. Another stakeholder mentioned that scenario building can be made more dynamic, infrastructure gap identification more transparent and data-driven, and project assessment more streamlined. Offshore planning can benefit from a more integrated and simplified approach to accelerate deployment.

Looking more closely at the company subcategories, support for simplification in PCI/PMI project monitoring and reporting was highest among TSOs (89%) and energy suppliers (52%). Only 15% of DSOs and 31% of project promotors support this measure.

In the TYNDP process, support for simplification varied across the components:

·Infrastructure gap identification: The highest levels of support came from TSOs (59%), and energy suppliers (43%). Moderate support was observed among energy offtakers (38%), while project promoters (19%) and DSOs (8%) showed the lowest levels of agreement.

·Scenario building: Again, TSOs (70%) expressed the strongest support. This was followed by energy generators (38%) energy offtakers (25%), and DSOs (23%). Support among Project Promoters remained low at 19%.

·Project assessment: The majority of TSOs (59%) agreed to simplification efforts. Only 38% of energy suppliers agreed, while project promoters (25%), DSOs (15%), and Energy Offtakers (13%) expressed even fewer agreement.

In the area of offshore network development planning, the company subcategories’ views were mixed, with a notable degree of uncertainty. 37% of all company/business type respondents selected "Don't know", with this figure rising sharply to 77% among DSOs, indicating a lack of clarity or familiarity with the topic. Among those expressing a clear opinion, TSOs showed the highest level of support for simplification, with 44%. This was followed by Energy Offtakers (38%), Energy Generators/Suppliers (34%), and Project Promoters (22%).

Annex 3: Who is affected and how?

1.Practical implications of the initiative

Summary of the implementation of the preferred policy option

The primary objective of the initiative is to improve the energy infrastructure planning framework so that it fosters deployment of the most effective and efficient solutions. It will also help speed up deployment of priority infrastructure, improve its climate resilience and security. The improved robustness and coordination of scenario building and needs identification at EU level will support infrastructure planning at national level by TSOs and NRAs.

The following key target groups have been identified for this initiative:

·European citizens and consumers

·Project promoters, including Transmission System Operators

·European TSO associations (ENTSO-E, ENTSO-G, and ENNOH)

·National Competent Authorities and their local and regional representatives (i.e. Ministries and outermost regions)

·National Regulatory Authorities

·European Union Regulators

·Distribution system operators and DSO branch organisations (including EU DSO entity)

·Energy producers / Industry

·Charging point operators

The below table outlines the practical implications of the initiative for all key target groups identified

Table 9: Implications of initiative for key target groups identified

2.Summary of costs and benefits

The assessment of benefits distinguishes between direct and indirect benefits of the preferred policy option (policy option 2).

Direct benefits of the preferred option are mainly related to reduction of energy system costs due to improved infrastructure planning, reduced CO2 emissions from optimal grid functioning, reduced re-dispatching of renewable energy sources and increased renewable energy integration.

Indirect benefits include overall reduced electricity price, increased competitiveness for European businesses and industry, improved electrification and grid access for transport, industry and data centres and greater energy system security.

Costs and benefits should usually be based on market price (reflecting the opportunity cost of action). However, these are not always available and so other methods may be needed to express impacts in monetary terms or indeed sometimes the impacts cannot be expressed in monetary terms.

The below table summarises the direct and indirect benefits for the preferred policy option based on best available data.

(1) Estimates are gross values relative to the baseline for the preferred option as a whole (i.e. the impact of individual actions/obligations of the preferred option are aggregated together); (2) Please indicate in the comments column which stakeholder group is the main recipient of the benefit;(3) For reductions in regulatory costs, please describe in the comments column the details as to how the saving arises (e.g. reductions in adjustment costs, administrative costs, regulatory charges, enforcement costs, etc.;);.

For assessing the costs of the preferred policy option, the analysis distinguishes between direct costs and indirect costs. The preferred policy option results in direct costs in terms of adjustment costs, administrative costs and enforcement costs for businesses and administrations (national competent authorities, national regulatory authorities, the Commission and ACER) in order to comply with the substantive obligations or requirements contained therein. The application of the preferred policy option could result in indirect costs for citizens/consumers and businesses in some countries where energy prices could increase due to price convergence resulting from further market integration. The European Grids Package is not envisioned to introduce any regulatory charges such as fees, levies, taxes etc. Additional enforcement costs at national and EU level will depend on the implementation.

The below table summarises the direct and indirect costs for those actions of the preferred policy options for which costs have been identified and compared to the baseline. It is not possible to estimate these costs for all actions at this stage, but where they are not included they are considered as non-significant.

(1)Estimates (gross values) to be provided with respect to the baseline; (2) costs are provided for each identifiable action/obligation of the preferred option otherwise for all retained options when no preferred option is specified; (3) If relevant and available, please present information on costs according to the standard typology of costs (adjustment costs, administrative costs, regulatory charges, enforcement costs, indirect costs;).

(*) Net administrative burdens = INs – OUTs;

(**) Adjustment costs falling under the scope of the OIOO approach are the same as reported in Table 2 above. Non-annualised values;

(***) Total administrative burdens = Net administrative burdens for businesses + net administrative burdens for citizens.

3.Relevant sustainable development goals