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
Date: 2025-12-10
Institutions: Directorate-General for Energy, European Commission
Subjects: EU energy policy, administrative formalities, carbon neutrality, electrical energy, energy grid, energy storage, hydrogen, natural gas, renewable energy, security of supply, trans-European network

EN 

  EN 

   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 

1.1.  Political context ................................................................................................. 1 
 Legal context .................................................................................................... 3 
1.2. 
1.3.  Synergies with other EU policy instruments ..................................................... 3 
PROBLEM DEFINITION .................................................................................................................... 4 

2. 

2.1.  What are the problems? ..................................................................................... 4 
2.2.  What are the problem drivers? .......................................................................... 9 
2.3.  How likely is the problem to persist? .............................................................. 18 
3.  WHY SHOULD THE EU ACT? ........................................................................................................ 19 

3.1.  Legal basis ....................................................................................................... 19 
3.2.  Subsidiarity: Necessity of EU action ............................................................... 19 
3.3.  Subsidiarity: Added value of EU action .......................................................... 20 
4.  OBJECTIVES: WHAT IS TO BE ACHIEVED? ............................................................................... 21 

4.1.  General objectives ........................................................................................... 21 
4.2.  Specific objectives ........................................................................................... 21 
5.  WHAT ARE THE AVAILABLE POLICY OPTIONS? .................................................................... 22 

5.1.  What is the baseline from which options are assessed? .................................. 22 
5.2.  Description of the policy measures and options .............................................. 24 
5.3.  Options discarded at an early stage ................................................................. 32 
6.  WHAT ARE THE IMPACTS OF THE POLICY OPTIONS? ........................................................... 32 

6.1.  Economic impacts ........................................................................................... 33 
6.2.  Social Impacts ................................................................................................. 42 
6.3.  Environmental Impacts .................................................................................... 44 
7.  HOW DO THE OPTIONS COMPARE? ............................................................................................ 47 

7.1.  Effectiveness .................................................................................................... 48 
7.2.  Efficiency ........................................................................................................ 51 
7.3.  Coherence ........................................................................................................ 53 
7.4.  Subsidiarity and proportionality ...................................................................... 54 
7.5.  Summary .......................................................................................................... 55 
PREFERRED OPTION ...................................................................................................................... 55 

8. 

8.1. 
Identification of preferred policy option ......................................................... 55 
8.2.  REFIT (simplification and improved efficiency) ............................................ 56 
8.3.  Application of the ‘one in, one out’ approach ................................................. 57 
9.  HOW WILL ACTUAL IMPACTS BE MONITORED AND EVALUATED? .................................. 57 
ANNEX 1: PROCEDURAL INFORMATION ............................................................................................ 59 

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ANNEX 2: STAKEHOLDER CONSULTATION (SYNOPSIS REPORT) ................................................ 63 
ANNEX 3: WHO IS AFFECTED AND HOW? .......................................................................................... 73 
ANNEX 4: ANALYTICAL METHODS ..................................................................................................... 82 
ANNEX 5: COMPETITIVENESS CHECK ................................................................................................ 93 
ANNEX 6: EXISTING LEGAL EU FRAMEWORK .................................................................................. 96 
ANNEX 7: IMPLEMENTATION REPORTS ........................................................................................... 106 
ANNEX 8: MONITORING........................................................................................................................ 144 
ANNEX 9: DESCRIPTION OF POLICY MEASURES ............................................................................ 147 
ANNEX 10: COMPARISON OF OPTIONS ............................................................................................. 158 
ANNEX 11: GLOSSARY .......................................................................................................................... 159 

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1. 

INTRODUCTION: POLITICAL AND LEGAL CONTEXT 

1.1. 

Political context 

infrastructure  plays  a  crucial  role 

Energy  network 
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  20505,  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 report6 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  20258,  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 

1 Clean Industry Deal COM(2025) 85 final 
2 Regulation (EU) 2018/1999 on the Governance of the Energy Union and Climate Action 
3 COM(2025) 524 final: Proposal for a Regulation establishing the framework for achieving climate neutrality 
4  Artelys,  LBST,  Trinomics,  Finesso,  A.  et  al.,  Investment  needs  of  European  energy  infrastructure  to  enable  a 
decarbonised economy, 2025; investment needs for distribution grids alone amount to EUR 730 billion. 
5  https://energy.ec.europa.eu/news/member-states-agree-new-ambition-expanding-offshore-renewable-energy-2024-
12-18_en 
6 https://commission.europa.eu/topics/eu-competitiveness/draghi-report_en#paragraph_47059 
7 Energy Council Conclusions of 30 May 2024 on Advancing Sustainable Electricity Grid Infrastructure, 10459/24 
8 Council of the European Union, 10279/25 
9 Conclusions of the European Council of March 2025 EUCO 1/25 
10 European Parliament resolution of 19 June 2025 on electricity grids (2025/2006(INI)) 

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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 
Energy12 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 trucks13; 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 Grids14 that focused on implementing the 
agreed legal framework to strengthen Europe’s energy networks, and on the 2022 Digitalisation of 
Energy Action Plan15 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 grids16 and resilient supply chains17 
will be mainly covered through non-legislative measures to be set out in a Communication and in 
a guidance document on grids connection18 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. 

11 EP resolution of 7 May 2025 on a revamped long-term budget for the Union in a changing world (2024/2051(INI)),  
12 COM(2025) 79 final 
13 Excluding  recharging  stations  in  residential  and  non-residential  buildings,  already  covered  by provisions  in  the 
Energy Performance of Buildings Directive, as amended by Directive (EU) 2024/1275. 
14 COM(2023) 757 final 
15 COM(2022) 552 final 
16 In view of the recently revised legal framework on grid planning, grid capacity transparency and incentives for 
smart and digital technologies, and the upcoming (legally binding) network code on demand side response, which 
will address distribution grids, as described in the Annex 6, no  additional legislative changes concerning network 
planning  or  smart  technologies  on  DSO  level  are  proposed  in  the  TEN-E  revision,  which  addresses  cross-border 
infrastructure including smart electricity grids. The transposition and implementation of the existing framework and 
upcoming network code will address the main challenges at distribution level for non-cross-border needs, including 
with regard to the sufficient grid capacity for connection of industry, automobile sector and data centres for AI. In 
addition,  in  view  of  the  revision  of  the  Governance  Regulation  and  the  transformation  of  NECPs  into  strategic 
investment plans, the Commission will assess whether additional targeted action is required. 
17 Building on the existing legal framework such as the Net-Zero Industry Act and ongoing measures of the Grids 
Action Plan as well as the EIB Grids Manufacturing Package.  
18 As announced in the Automotive Action Plan, the Commission will present as part of this initiative a guidance on 
grid connections to equip Member States with sufficient tools to manage grid connection requests more effectively.  

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1.2. 

 Legal context 

The TEN-E Regulation19 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 Regulation20 and Directive21, the hydrogen and 
gas decarbonisation package22 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 ENNOH24 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. 

1.3. 

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-
203426  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  Energy27.  The  TEN-E  Regulation  provides  the  basis  for 
energy infrastructure projects funded under CEF.  

19 Regulation (EU) 2022/869 of 30 May 2022 on guidelines for trans-European energy infrastructure 
20 Regulation (EU) 2019/943 on the internal market for electricity (recast) (OJ L 158, 14.6. 2019, p.54) 
21 Directive (EU) 2019/944 on common rules for the internal market for electricity (recast) (OJ L 158, 14.6.2019, p. 
125). 
22 Regulation (EU) 2024/1789 on the internal markets for renewable gas, natural gas and hydrogen and Directive (EU) 
2024/1788 on common rules for the internal markets for renewable gas, natural gas and hydrogen 
23 Directive (EU/2018/2001) on the promotion of the use of energy from renewable sources (RED),  as amended by 
Directive (EU/2023/2413) 
24 As of January 2027. Until then the planning task remains with ENTSOG – Article 58 Regulation (EU) 2024/1789 
25 COM(2025) 524 final: Proposal for a Regulation establishing the framework for achieving climate neutrality 
26 COM(2025) 570 final: The Multiannual Financial Framework 2028-2034 
27 COM(2025) 547 final: Proposal for a Regulation establishing the Connecting Europe Facility for 2028-2034  

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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. 

28 For instance, the needs of industry in terms of energy consumption should be well reflected in national network 
development  plans  and,  vice-versa,  there  is  a  need  for  recognition  of  infrastructure  planning  in  industrial  policy 
considering the need for grid and pipeline infrastructure for H2 and CO2. 

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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 
ACER29, 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 

29 ACER (2024): Electricity infrastructure development to support a competitive and sustainable energy 
System (2024 Monitoring Report) 
30 ENTSO-E (2025), TYNDP 2024. Opportunities for a more efficient European power system by 2050. Infrastructure 
Gaps Report. 

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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 ACER36 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 202338, a yearly increase of 14.5%, and costs for 

31 ACER (2024): Electricity infrastructure development (2024 Monitoring Report) 
32  Artelys,  LBST,  Trinomics,  Finesso,  A.  et  al.,  Investment  needs  of  European  energy  infrastructure  to  enable  a 
decarbonised economy, 2025. 
33 Ember (2024): Putting the mission in transmission: Grids for Europe’s energy transition  
34ACER (2025): Market monitoring report, Key developments in European electricity and gas markets - 2025 
35 Pursuant to Article 16 of Electricity Market Regulation (2019/943), 70% of transmission capacity after deduction 
of  contingencies  /  respecting operational  security  limits  shall  be  allocated  for  cross-border  trade.  Derogations  are 
granted by NRAs for individual TSOs on a national level. 
36 ACER (2024): Market monitoring report, Transmission capacities for cross-zonal trade of electricity and congestion 
management in the EU. 
37 For instance, in the period between June 2022 and December 2023, in Romania, Germany and Slovakia, internal 
network elements were responsible for 99%, 82% and 77% of capacity constraints respectively. Network planning 
for internal infrastructure can hence significantly impact implementation of the internal market rules. 
38 ACER (2024): Market monitoring report 

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renewables curtailment amounted to EUR 7.2 billion in 2024 in 7 countries alone39. 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 
report42 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 grids44. 

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 

39 How Europe‘s grid operators are preparing for the energy transition, Ember, E3G, Beyond Fossil Fuels, Institute 
for  Energy  Economics  and  Financial  Analysis  report,  2025.  Note:  these  costs  are  broader  than  redispatching  as 
referred to by ACER and may concern also economic losses of respective power pants operators linked to curtailment. 
40 Beyond Fossil Fuels, E3G, Ember and the Institute for Energy Economics and Financial Analysis, How Europe’s 
grid operators are preparing for the energy transition (2025). REPORT_FINAL.pdf, pg 5 
41 ENTSO-E (2025): Impact of Renewable Hydrogen in the Power System:  
42 ACER (2024) European hydrogen markets, 2024 (Market Monitoring Report) 
43 ENTSO-E and Renewables Grids Initiative, Value of timely implementation of "better projects”, May 2019  
44 European Court of Auditors (2025): Review 01/2025: Making the EU electricity grid fit for net-zero emissions 
45 Building the future transmission grid – Strategies to navigate supply chain challenges; IEA, February 2025  
46 T&D Europe policy recommendations “Towards future-proof grids”, July 2024 

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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 Regulation47, 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 million48.  

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. 

47 Council Regulation (EU) 2024/223 of 22 December 2023 amending Regulation (EU) 2022/2577 laying down a 
framework to accelerate the deployment of renewable energy.  
48 Elering (2024): article  

8 

 
 
 
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 guidelines49 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  cycle50  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 process51. 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.  

49 ACER (2023): Framework Guidelines for the joint TYNDP scenarios to be developed by ENTSO-E and ENTSOG 
50 For more detailed assessment, see ACER Opinions on TYNDP, e.g. Opinion on ENTSO-E’s draft TYNDP 2024 
51 ACER (2024): Opinion on the draft electricity ten-year network development plan  
52 Ibid. 
53 Sikow-Magny, Catharina (2025): Trans-European energy networks (TEN-E) – ideas for simplification in view of 
accelerating project implementation, RSC Policy Paper 2025/13 
54 ACER (2025): Guidance on distribution network planning 
55Commission Notice on a guidance on anticipatory investments for developing forward-looking electricity networks  
56 ACER Opinion No 7/2025 on the electricity national development plans 
57  Agora  Energiewende  (2025):  Integrated  Infrastructure  Modelling  and  Climate  Neutrality,  presentation  at  11th 
Energy Infrastructure Forum, 3 June 2025 
58 Ember (2024): Putting the mission in transmission: Grids for Europe’s energy transition  

9 

 
 
 
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 

59 Two categories of projects: “real” projects already investigated in the previous TYNDP cycle and “concept” projects 
with expected commissioning date after 2040 and with technical and economic parameters less certain. 
60 22% respondents expressed neutrality and 18% were uncertain. 
61  Experience  from  previous  PCI  and  PMI  assessment  cycles  proved  interconnectors  with  Energy  Community 
countries may not always fulfil the Union benefits criterion. While there is a dedicated process for Projects of Energy 
Community Interest (PECIs), it does not cover projects with the EU. 

10 

 
 
 
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 solutions62 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 MW65 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 

62 For example, grid enhancing technologies, digitalisation or flexibility. 
63 See  Annex 7 for more details on limited uptake of these solutions by TSOs. In the last  two PCI/PMI selection 
procedures, only one project involving a TSO was submitted to support the digitalisation of existing grids. 
64 Similar to NOVA principle in Germany: German TSOs and DSOs are obliged to firstly consider grid optimisation 
measures, such as use of non-wired alternative solutions, before further grid build-out. Glossar | Netzentwicklungsplan 
65 Analysis of maximum physical energy flows between respective EU borders for year 2024 (ENTSO-E data). 

11 

 
 
 
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 purpose68 citing its complexity, lack of transparency, and failure to incentivise cooperation 
among non-hosting countries as key issues. 

66 CBCA is a precondition for submitting applications for CEF grants for works related to regulated projects. 
67 ACER (2023): Overview of Cross-Border Cost Allocation Decisions; ACER CBCA Report 
6820% of respondents remained neutral and 35% expressed no opinion 

12 

 
 
 
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  income70  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 

69 See ENTSO-E's results on the sea-basin cross-border cost-sharing assessment under TEN-E Article 15. 
70 Congestion income is the revenue generated when electricity prices differ between two bidding zones due to limited 
transmission capacity between them. It is defined by ACER as the revenue resulting from the capacity allocation in 
the single day-ahead and intraday market coupling. 
71 ACER (2024): Electricity infrastructure development to support a competitive and sustainable energy system, p. 18 
72 ACER (2025): Monitoring of projects of common interest and of mutual interest - 2025 
73 ACER, Consolidated Report on the progress of electricity and gas Projects of Common Interest (2020). 

13 

 
 
 
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 months74.. 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 202380 
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  adopted81,  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 

74 Please note that the data collected does not allow to have a more granular view of permitting procedures taking 
longer than 24 months, as the figure of “over 24months” encompasses   all durations above  24 months  which may 
in certain cases amount to several additional years. 
75 Final report to be found here: Technical support for RES policy development and implementation – simplification 
of permission and administrative procedures for RES installations (RES Simplify) - Publications Office of the EU 
76 Fraunhofer Institute for Systems and Innovation Research ISI, et al., Study on energy storage, 2023,  
77 Information collected by EV charging organisations, notably ChargeUp Europe, Ionity and Milence 
78  Technical  support  for  RES  policy  development  and  implementation  –  simplification  of  permission  and 
administrative procedures for RES installations (RES Simplify) 
79 Council Regulation (EU) 2022/2577 laying down a framework to accelerate the deployment of renewable energy 
80 Council Regulation (EU) 2024/223 amending Regulation (EU) 2022/2577 (RED) 
81 The transposition deadline for most of the permitting provisions of the revised RED was 1 July 2024 and for some 
21 May 2025. 

14 

 
 
 
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 implementation83 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 months86, 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 

82 European Committee of region, “The state of regions and cities EU annual report 2025” (October 2025): The State 
of Regions and Cities in the European Union | European Committee of the Regions   
83 Solar Power Europe, EU Renewable Energy Permitting: State of Play (2025) page 15 
84 https://webgate.ec.europa.eu/fpfis/wikis/spaces/respqa/overview  
85 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 (2025)  
86 Based on data reported by Member States until November 2023. 
87 Collection of information and data on the implementation of the revised Environmental Impact Assessment (EIA) 
Directive (2011/92/EU) as amended by 2014/52/EU), final report, page 25. 

15 

 
 
 
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). 

judicial  challenges  continue 

Further, inefficient and ineffective public participation processes, leading to opposition in the 
form  of  administrative  and 
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  stakeholders89  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. 

to  contribute 

to 

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 

88 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 (2025) 
89 Ibid. 
90 CAN Europe (2025); Fast & Fair Renewables & Grid (2025); Eurelectric (2025)    
91 The EPBD includes provisions simplifying permitting procedures for recharging points in buildings. 

16 

 
 
 
recently  adopted  in  other  sectors92  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  campaigns93  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 cybersecurity95 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  

92  Past  legislation  with  a  permitting  dimension:  Renewable  Energy  Directive;  TEN-E  Regulation;  Hydrogen  and 
decarbonised Gas Directive; Net Zero Industry Act; Critical Raw Materials Act; Gigabit Infrastructure Act. 
Planned proposals with a permitting dimension: Industrial Accelerator Act, part of the Clean Industrial Deal; Cloud 
and AI development Act, part of the ‘AI Continent’ initiative, Environmental Omnibus following the Communication 
“Competitiveness Compass for the EU”; Strategy for Housing Construction, part of the Affordable Housing Plan 
93 Hybrid campaigns are designed in a way that makes detecting and defending against them difficult. They are devised 
to remain below the threshold which could constitute or be perceived as an act of war. Countering hybrid threats is 
therefore a complex and constantly evolving challenge that the European Union, its member states and its partners 
are facing. Source: Hybrid threats - Consilium 
94 https://www.eurelectric.org/in-detail/cybersecurity-in-the-power-sector/  
95  The  EU  Critical  Entities  Resilience  (CER)  Directive  2022/2557  provides  a  framework  for  strengthening  the 
resilience of critical entities operating critical infrastructure against all hazards. The NIS 2 Directive (EU) 2022/2555) 
establishes a unified legal framework to uphold cybersecurity in 18 critical sectors across the EU. It also calls on 
Member States to define national cybersecurity strategies and collaborate with the EU for cross-border reaction and 
enforcement. The Network Code on sector-specific rules for cybersecurity aspects of cross-border electricity flows. 
96 The  Commission has proposed additional tools  as part of the upcoming MFF  under which financing of critical 
infrastructure protection would in the future be eligible, notably as part of the Union Civil Protection Mechanism, the 
Competitiveness Fund and National and Regional Partnership Plans. 

17 

 
 
 
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.  

Regulated interconnectors are typically owned and operated by TSOs, who must be certified under 
the Electricity Regulation. If a TSO controlled by third-country interests requests certification, the 
NRA must notify the European Commission. While most regulated interconnector promoters are 
TSOs, certification only occurs at the stage of entry into operation. Therefore, TSOs may not be 
certified during the PCI/PMI application stage, and hence no assessment is possible. As a result, 
there  is  limited  transparency  regarding  the  ultimate  beneficial  owners  of  candidate  PCI/PMI 
projects. Under the Foreign Direct Investment Screening Regulation,97 the Commission can give 
an opinion to the Member State where a foreign investment is planned or completed for PCIs/PMIs 
if it believes the investment might affect these projects for reasons of security or public order. 
However, such information is not necessarily shared in the context of the TEN-E framework and 
cannot  be taken into consideration in  the  PCI/PMI selection, which prevents  this process  from 
fully addressing potential security risks. Limitations in the current framework in this respect were 
to some extent also evident in the public consultation, in which only 14% of respondents indicated 
that  the  framework  addresses  the  exclusion  of  non-trusted  actors  from  participating  in  critical 
infrastructure projects, and 45% being uncertain. 

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, 

97  Regulation  (EU)  2019/452  of  19  March  2019  establishing  a  framework  for  the  screening  of  foreign  direct 
investments into the Union. The Commission has proposed to revise this Regulation inter alia to ensure all Member 
States have a screening mechanism in place, see COM(2024)23 final. 

18 

 
 
 
inefficiencies under the current permitting system98 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 

98 Milieu Law and Policy Consultancy, 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 (2025) 

19 

 
 
 
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 system99, 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.   

99 Communication from the Commission (2023): Grids, the missing link - An EU Action Plan for Grids 

20 

 
 
 
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.  

21 

 
 
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.  

22 

 
 
 
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, 

100 The draft electricity network code contains provisions on coordination between electricity TSO-DSO and DSOs, 
methodology for planning and scenarios, link to flexibility needs assessment, use of local services as alternatives to 
grid development, monitoring of DNDPs and more transparency related to public consultation of electricity DNDPs. 

23 

 
 
 
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  Act101,  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 

101 Regulation (EU) 2024/1735 on establishing a framework of measures for strengthening Europe’s net-zero 
technology manufacturing ecosystem and amending Regulation (EU) 2018/1724  
102 Union of skills - European Commission 

24 

 
 
 
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 

25 

 
 
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.   

26 

 
 
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. 

27 

 
 
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 

103 M. Draghi, “The future of European competitiveness – Part A | A competitiveness strategy for Europe”, p. 50-51  

28 

 
 
 
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 

Specific objective 

Policy measures 

PO1 

PO2 

PO3 

A)  Infrastructure planning and project implementation  

Ensure 

SO1: 
that 
in 
projects 
network  plans  address 

included 

A.1 
A.2 
A.3 

Strengthening the existing framework 
Increased EU level steering / coordination 
Fully centralised approach 

X 

X 

X 

29 

 
 
 
 
 
 
 
 
 
 
 
appropriately 
needs 

identified 

A.4 

A.5 

B)  Cost and benefit sharing  

Alignment  of  scope  (smart  gas  grids/ 
blending, electrolysers, PMIs) 
Broadening  scope  of  PCI  categories 
(modernisation and digitalisation)104 

X 

X 

X 

X 

X 

tools 

SO2: Facilitate the use of 
cost-sharing 
for 
faster  deployment  cross-
border 
infrastructure 
projects 

C)  Permitting  

Shorten 

and 
SO3: 
simplify 
permitting 
procedures  for  energy 
infrastructure, renewable 
storage 
and 
energy 
projects,  as  well  as 
recharging stations 

D)  Security  

SO4:  Enhance  physical 
and  cyber  security  and 
resilience of cross-border 
energy infrastructure 

B.1 

B.2 

B.3  

B.4 

C.1 

C.2 

C.3 

D.1 

D.2 

D.3 

transparency 

and 
Enhancing 
strengthening  EU  principles  for  cross-
border  energy  infrastructure  costs  and 
benefits sharing 
Use of congestion income for financing of 
cross-border  electricity  infrastructure  as 
an incentive to cost-sharing 
Enabling 
bundling of projects   
Mandatory offshore regional planning and 
cost-sharing 

for  voluntary 

framework 

X 

Supporting the implementation of existing 
legislation and issuing guidance 
Targeted legislative changes to accelerate 
permitting 
permitting 
EU-wide 
Centralised 
coordination  regime  for  certain  large-
scale energy infrastructure projects (“28th 
Regime”) 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

cyber-risk 
the 
in 

physical 
and 
considerations 

Including 
resilience 
monitoring of PCIs and PMIs 
Additional 
requirements 
transparency 
regarding  the  ultimate  beneficial  owners 
of candidate PCIs/PMIs  
Including  security  and  resilience-related 
equipment  for  the  upgrade  of  existing 
electricity 
infrastructure 
under TEN-E scope 

cross-border 

X 

X 

X 

X 

X 

X 

X 

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.  

104 On the broadened scope to better reflect security/resilience within the PCI scope see policy measure D.3 

30 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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 

105 20% of respondents were neutral and 35% expressed no opinion (see Annex 2). 
106 25% of respondents were neutral and 32% uncertain (see Annex 2). 

31 

 
 
 
 
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 option111. 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. 

107 18% of respondents were neutral and 31% uncertain (see Annex 2). 
108 18% of respondents were neutral and 32% uncertain (see Annex 2). 
109 14% of respondents were neutral and 27% uncertain (see Annex 2). 
110 ,Almost a majority (45%; companies 41%, business associations 48%, NGOs 86%, public authorities 40%) being 
uncertain. 
111  
The analysis in this section is based on an on-going support study, the analysis of stakeholders’ feedback as well as 
JRC modelling as further explained in Annex 4. 

32 

 
 
 
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 capacity113 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 

112 ENTSO-E (2025), TYNDP 2024. Figures for the National Trends + 2030 and 2040 scenarios 
113  ENTSO-E  (2025),  TYNDP  2024.  Opportunities  for  a  more  efficient  European  power  system  by  2050.  
Infrastructure Gaps Report. 

33 

 
 
  
 
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  billion118  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 

114 Calculations based on ENTSO-E (2025), TYNDP 2024.  
115  Excluding  the  possible  non-mature  interconnectors  through  the  Mediterranean  and  long  HVDC  connections 
spanning multiple countries which are included in the TYNDP2024. 
116 European Commission, Joint Research Centre, Thomassen, G., Fuhrmanek, A., Cadenovic, R., Pozo Camara, D. 
and Vitiello, Redispatch and Congestion Management (2024)  
117 See for instance CurrENT study: Prospects for innovative power grid technologies, 2024, PowerPoint Presentation 
118 Commission analysis of benefits of DLR deployment on 143 most congested CNECs (critical network elements 
used for capacity calculation in CORE region) based on ACER data (see Annex IV for details)  
119 Total benefits per 20 years: 2,819,948,354 EUR, total costs: 146,783,715 EUR. 
120 Commission Notice on a guidance on anticipatory investments for developing forward-looking electricity networks 

34 

 
 
 
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 2030-2050124, 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 

121 The economic value of electricity distribution grids on the path towards climate neutrality in Austria (translated) 
122 https://www.ssen-transmission.co.uk/news/news--views/2022/11/the-real-cost-of-having-insufficient-grid/ 
123  Bundesministerium  für  Klimaschutz,  Umwelt,  Energie,  Mobilität,  Innovation  und  Technologie  (BMK)  (2024) 
Integrierter österreichischer Netzinfrastrukturplan  
124 Based on preliminary findings on Agora Energiewende Integrated Infrastructure planning PyPSA-Eur model, as 
presented in 2025 Copenhagen forum 
125 Ibid 

35 

 
 
 
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’s126  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). 

126 ENTSO-E, Sea Basin Cost Benefit and Cost Sharing: final results, 4 July 2025.  
127 TEN-E requires EU Member States to agree on non-binding targets for offshore renewable energy they plan to 
deploy  within  each  sea  basin  by  2050.  These  serve  as  the  foundation  for  Offshore  Network  Development  Plans 
(ONDPs),  which  outline  the  infrastructure  needed  to  achieve  Member  States  goals.  ENTSO-E,  based  on  a 
Commission Guidance published in June 2023, shall carry out cross-border cost-benefit assessments of those ONDPs 
to inform Member States  and  support upcoming planning and cost-sharing discussions at regional level. The first 
assessment final results were presented to the TEN-E offshore grids corridors members on 4 July 2025.  
128 This includes 21.5 GW in the North Sea, 3 GW in the Baltic Sea and 700 MW in the Atlantic Ocean by 2040. For 
2050, it would concern 8.5 GW in the North Sea, 10.6 GW in the Baltic Sea and 700 MW in the Atlantic Ocean. 
129  Socio-economic  welfare  consists  of  consumer  surplus,  producer  surplus,  congestion  income  and  cross-sectoral 
rent. Importing countries would tend to see their consumer surplus increase and their producer surplus would decrease, 
and vice versa for exporting countries; from the prices changes between market zones and across the electricity and 
the hydrogen system, congestion rents and cross sectoral rents might go up or down. 

36 

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

Year  Offshore 

hybrid 
capacity 
needed (GW)  
25 

44 

2040 

2050 

Investment 
costs 
(bn 
EUR) 

Assumed  % 
not realised or 
delayed  

Capacity 
delayed  or  not 
realised (GW) 

Cumulative loss of SEW if 
projects  are  not  realised 
(bn EUR) 

23 

19 

30-50% 

30-50% 

7.5 -12.5 

13.2 - 22 

20.85- 34.75 

10.05- 16.75  

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  

130 E.g. 2004 TSO Nordel Infrastructure Package with the bundling of five prioritised Nordic grid reinforcements: 1. 
Fennoskan  II  (Decided)  2.  Great  Belt  (Decided)  3.  Nea  -  Järpströmmen  (Decided)  4.  South  Link  (Decided)  5. 
Skagerrak IV (Letter of Intent, concessions applied), see Annex 9 for further details.   
131 TSOs’ proposal for Use of Congestion Income Methodology in accordance with Article 19(4) of Regulation (EU) 
2019/943 of the European Parliament and of the Council of 5 June 2019 on the internal market for electricity 
132 European Commission, Joint Research Centre, Finck, J. R., Miletic, M., Terça, G. The interconnection needs of 
the European electricity system: Investigations for 2030 and 2040 using METIS, European Commission, Petten, 2025, 
JRC143965 
133 ENTSO-E  and Renewable Grids Initiative, Value of timely implementation of “better projects (2019) 

37 

 
 
 
 
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 PO3134, 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  capacity135,  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 plant136 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 

134 The reduction in lead times are expected to be delayed for PO3 due to the time needed to create a new EU-level 
entity and make it operational.  
135 Status of onshore wind energy expansion in Germany (translated)  
136 Fraunhofer study for T&E, Batteries on wheels: the untapped potential of EVs, October 2024 
137 European Commission Joint Research Centre, Finck, J. R., Miletic, M., Terça, G. The infrastructure needs of the 
European electricity system: Investigations for 2030 and 2040 using METIS, European Commission, Petten, 2025, 
JRC143965 

38 

 
 
 
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 suppliers138, 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 

138 See Communication from the Commission providing updated information to determine the shares of the European 
Union supply of final products and their main specific components 
139 ENTSO-E (2025), TYNDP 2024 
140 Ember (2025): Grids for data centres 
141 For instance, for dynamic line rating, this would mean installing physical sensors in the grid, but also a digital 
smart system which automatically evaluates the data and assesses impact on available capacities). 
142 PT: national energy and geology laboratory repository centralising georeferenced information in the energy and 
geology areas: Laboratório Nacional de Energia e Geologia, GEOPORTAL  
DK: Danish Environmental Portal owned by the national government, regions, and municipalities: ARTER 

39 

 
 
 
 
 
 
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 

40 

 
 
 
 
 
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 category143, 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.  

143 Data allowing to quantify the expected increase in projects is not available. National network development plans 
do not quantify cross-border impacts of all internal infrastructure. Hence, it is difficult to assess which of existing 
internal projects could apply for a PCI status. 

41 

 
 
 
 
 
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 

144 Assuming 220 PCIs and PMIs per Union list and additional cross-border renewable and storage projects. 
145 Under the national law of most Member States (e.g. CZ, MT), different authorisations at the local level will be 
required despite any coordination at the European level such as: approval of impact on cultural heritage areas, military 
areas and other urban planning areas; authorisation from the authority responsible for geological and environmental 
assessments; road and air traffic permits; safety permits; decision on land rights; and construction permits. 
146 Bruegel Heussaff, C., Zachmann, G.  (2025): Upgrading Europe's electricity grid is about more than just money  

42 

 
 
 
 
 
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; 

43 

 
 
 
 
 
 
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 study149 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  

147 Ibid 
148 IRENA and ILO (2024), Renewable energy and jobs: Annual review 2024 
149 European Commission JRC (2024): Redispatch and Congestion Management 
150 ENTSO-E TYNDP 2024 Infrastructure gaps report. 

44 

 
 
 
 
 
 
Positive  environmental  impacts  are  also  illustrated  by  a  recent  IEA  study151,  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 

Scenario 

ΔNOx 
tonnes / year 

ΔNH3 
tonnes / year 

ΔSO2 
tonnes / year 

ΔPM5 
tonnes / year 

ΔPM10 
tonnes / year 

ΔNMVOC 
tonnes / year 

National 
Trends+ 
Distributed 
energy 
Source: ENTSO-E 

-149.0 

-156.1 

-27.7 

-24.9 

-51.9 

-77.9 

-3.8 

-3.7 

-4.6 

-5.9 

-9.8 

-9.1 

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 

Year 

2040 

2050 

Offshore 
hybrid 
capacity 
needed 
(GW)  
25 

44 

RES 
integration 
capacity  

40 

80-90 

CO2 
emission 
reduction 
(ktonnes  of 
CO2)  
4,000  

1,200  

Assumed  % 
not  realized  or 
delayed 

30-50% 

30-50% 

emission 
CO2 
not 
reduction 
or 
realized 
delayed  (ktonnes 
of CO2) 
1,200 – 2,000 

360 - 600 

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 

151 IEA report on Electricity Grids and Secure Energy Transitions, November 2023 

45 

 
 
 
 
 
 
 
 
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 impacts154 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 

152 https://climate.ec.europa.eu/document/download/d0671350-37f2-4bc4-88e8-088d0508fb03_en  
153 IEA (2024) World Energy Outlook, p. 97 

154 Collision risks, electrocution risks, soil contamination, disturbance of specific habitats and species or deforestation 

46 

 
 
 
 
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. 

155  Study  on  the  potential  for  renewable  and  low-carbon  gas  deployment  and  impact  on  enabling  infrastructure 
development for the Baltic Sea Region (2025, to be published) 

47 

 
 
 
 
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. 

48 

 
 
 
 
 
General objectives 
More rapid and targeted 
development and 
interoperability of 
resilient trans-European 
energy networks, 
renewable energy and 
flexibility, including 
storage and recharging 
stations, necessary for 
leading to lower energy 
system costs, higher 
security and lower 
emissions 

Table 5: Links between objectives and assessment criteria 

Specific objective 
Ensure that projects included in 
network plans and selected as 
PCI/PMIs address appropriately 
identified infrastructure needs 

Facilitate the use of cost-sharing tools 
for faster deployment cross-border 
infrastructure projects 
Shorten and simplify permitting 
procedures for energy infrastructure, 
renewable energy and storage projects 
as well as recharging stations 
Enhance physical and cyber security 
and resilience of cross-border energy 
infrastructure 

Assessment criteria 
More robust identification of 
infrastructure needs 
Clearer link between planned 
projects/their impacts with the identified 
needs 
PCIs and PMIs effectively addressing 
identified needs 
Expected increase in the use of cost-
sharing tools 
Acceleration of project implementation 
Shorter time to obtain necessary permits  
Fewer permit requirements 

Expected reduction in vulnerability risks 
Expected increase in the uptake of 
security related investments 

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 

49 

 
 
 
 
 
  
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 

50 

 
 
 
 
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 

156 See the example of other harmonised Union policies where overarching powers have been introduced, e.g. in the 
case of mergers, the first merger regulation took over 10 years to be negotiated. 

51 

 
 
  
 
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 

52 

 
 
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  limited157,  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.  

157 Around 8% or 15 project promoters based on the first PCI/PMI list 

53 

 
 
 
 
 
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. 

54 

 
 
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  

Impacts 

Effectiveness 
Efficiency 
Coherence 
Subsidiarity and proportionality 
Summary comparison of options (contribution to general objective)  

PO1 
+ 
+ 
+ 
++ 
+ 

PO2 
++ 
 ++/+++ 
++ 
+/++ 
++ 

PO3 
++ 
+/++  
+ 
- 
+ 

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 

55 

 
 
 
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 
infrastructure  planning  process  and  an  updated  CBCA 

benefits  early 
Recommendation from ACER will facilitate processes for TSOs and NRAs.  

the 

in 

•  Shortening  permitting  deadlines  simplifies  the  process  and  clarifies  the  existing 

framework, reduces the administrative burden on promoters. 

56 

 
 
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  stakeholders158 
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. 

158 Platform of National Competent Authorities in charge of the permitting of PCIs and PMIs, permitting expert group, 
CA-RES, bilateral meetings. 

57 

 
 
 
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. 

58 

 
 
 
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.   

the  Call  for  Evidence  and  Public 

Table 7: Timeline  
Milestones  
Publication  of 
Consultation  
Target stakeholder consultation 
Upstream meeting with Regulatory Scrutiny Board 
Submission to Regulatory Scrutiny Board 
Regulatory Scrutiny Board 
ISC 

Dates 
13 May – 5 August 2025 

May - July 2025 
14 July 2025 
27 August 2025 
24 September 2025 
27  November 
December 2025 

– 

1 

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.  

RSB requested improvements 

Changes in the revised report: 

(1)  The  report  should  clearly  present  and 
analyse  the  problem  drivers  and  clarify  to 
what  extent the identified problems  are due 
to  implementation  flaws  in  Member  States 
(considering also the lack of data) or due to 
gaps in the legal framework. It should better 
explain  to  what  extent  this  initiative  can 

The text has been revised (section 2) to further 
clarify the problem drivers and root causes and 
their  links  to  the  proposed  measures.  It  was 
further  explained  to  what  extent  the  problem 
implementation  of 
relates 
shortcomings in the current legal framework. 

issues  of 

to 

59 

 
 
 
address the identified problems and how this 
is  linked  to  other  legislation  such  as  the 
Renewable Energy Directive and the TEN-E 
Regulation. 

(2) The report should analyse the root causes of 
insufficient  investment  in  grid  integration  in 
the EU. It should explain better to what extent 
the  proposed  measures  can  be  effective  in 
addressing  the  need  to  invest  in  cross-border 
grids  to  respond  to  new  challenges  while 
considering Member State national interests in 
securing energy supply and providing energy at 
affordable prices.  
(3)  The  report  should  in  more  detail  assess 
subsidiarity  considerations  related 
to  a 
further centralisation of the processes beyond 
the already existing coordination mechanism 
under  the  TEN-E  Regulation  and  explain 
how  this  relates  to  national  prerogatives  on 
energy security. 

in 

terms  of  progress 

(4)  The  report  should  clearly  define  the 
success 
towards 
“optimal grid”. The link between the general 
objective  and  specific  objectives  should  be 
better  explained.  The  specific  objectives 
should  be  defined  in  S.M.A.R.T.  terms  to 
allow 
success  and 
monitoring the progress towards meeting the 
desired  objectives.  The  report  should  better 
for 
describe  what  data  will  be  used 
monitoring  and  how  comparability  of  data  
from Member States on permitting procedures 
including its duration will be ensured.  

for  assessing 

the 

The text has been revised (section 2) to better 
explain the root causes of insufficient 
investments in grids. In addition, it has been 
elaborated how the proposed measures and 
options can help addressing the identified root 
causes (section 5.3 and Annex 9). 

Following the observations from the Board, 
aspects of subsidiarity have been further 
assessed in particular in relation to the 
description of measures under Policy Option 3 
(section 5.3) and their comparison against the 
subsidiarity principle (section 7.4) 

The general and specific objectives have been 
revised to make them more specific (section 4) 
to facilitate their monitoring and assessment 
based on clear indicators and providing 
relevant data sources to track progress over 
time (section 9 and Annex 8) 

(5) The report should clearly present and justify 
how the different options compare in terms of 
costs and benefits. The “optimal grid” could be 
also  used  for  comparison  of  the  effectiveness 
of options.  

(6)  The  report  should  better  describe  the 
content  of  the  measures  regarding  permitting 
and demonstrate the specific aspects of energy 
grids  also  by  comparing  to  initiatives  with  a 

In the revised version the “optimal grid” and 
the underlying assumptions were explained in 
more detail (section 6.1). More detailed 
assessment has been added with additional data 
on costs and benefits to the extent available in 
order to allow for a more granular comparison 
of the different policy options. 
Following the Board’s observations, the 
proposed measures on permitting have been 
expanded to provided additional details on the 
content and how they compare to other 

60 

 
 
 
 
 
permitting related initiatives (section 5.3 and 
Annex 9). Furthermore, the expected impacts 
of the proposed measures compared to the 
baseline have been assessed in more detail 
(section 6). 

The revised text expands on possible trade-offs 
with other EU objectives, in particular as 
regards environmental impacts as well as 
possible safeguards (sections 5.3 and  6.3). 

view  to  accelerating  permitting  procedures  in 
other sectors. The impacts of measures related 
to  simplifying  and  shortening  permitting 
procedures 
thoroughly 
should  be  more 
assessed, including an analysis of factors such 
as  national  permitting  legislation  and  the 
duration of court proceedings. For example, it 
should  be  explained  how  imposing  shorter 
deadlines  at  the  EU  level  may  improve  the 
situation given the different circumstances.  
(7) The report should highlight possible trade-
offs  with  other  EU  objectives,  in  particular 
linked  to  the  protection  of  the  environment. 
The environmental impacts beyond greenhouse 
gas reductions should be thoroughly analysed 
to allow an assessment of trade-offs stemming 
from  accelerated  permitting  procedures.  The 
report should describe better any safeguards to 
address these trade-offs.  

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 

61 

 
 
 
 
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 
2025, 

2024 
https://eepublicdownloads.blob.core.windows.net/public-cdn-container/tyndp-
documents/TYNDP2024/foropinion/Infrastructure_Gaps_Report.pdf  

Infrastructure 

Report, 

Gaps 

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 
installations 

permission 
https://op.europa.eu/en/publication-detail/-/publication/949ddae8-0674-11ee-b12e-
01aa75ed71a1 

administrative 

procedures 

RES 

and 

for 

62 

 
 
 
 
 
 
 
 
 
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 

63 

 
 
 
 
 
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 

Type of Stakeholder 

Main Role and Relevance 

Company/business 

Business association 

Key  stakeholders  affected  by  the  TEN-E  Regulation, 
especially  in  energy  production,  distribution,  and 
infrastructure. 

Represent  interests  of  industries  impacted  by  TEN-E 
and provide collective feedback on policy implications. 

Non-governmental 
organisation (NGO) 

Provide  perspectives  on  environmental  and  social 
impacts of energy infrastructure projects. 

Number  Percentage 

90 

45.7% 

54 

14 

12 

27.4% 

7.1% 

6.1% 

EU citizen 

Public authority 

Other 

Consumer organisation 

Environmental 
organisation 

Academic/research 
institution 

Non-EU citizen 

Trade union 

Grand total 

Direct  beneficiaries  and  contributors  to  the  energy 
inclusive  energy 
transition;  essential  for  shaping 
policies. 

Responsible  for  implementing  and  enforcing  TEN-E 
Regulation at various administrative levels. 

10 

5.1% 

Miscellaneous  entities  with  indirect  relevance  to  the 
TEN-E Regulation. 

Advocate  for  fair  energy  prices  and  transparency  in 
infrastructure projects. 

Focus on ecological impacts of energy infrastructure and 
promote sustainable practices. 

Contribute  expert  knowledge  and  analysis  to  evaluate 
policy scenarios and infrastructure impacts. 

May  be  indirectly  affected  by  cross-border  energy 
infrastructure and policies. 

Represent  workers  in  the  energy  sector  and  provide 
input on labour implications of TEN-E Regulation. 

8 

3 

3 

1 

1 

1 

4.1% 

1.5% 

1.5% 

0.5% 

0.5% 

0.5% 

197 

100% 

64 

 
 
 
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 

159 Whereas TSOs and DSOs can relatively easily be identified the other categories leave more room for interpretation. 
The project promoter category, for instance, includes organisations that develop infrastructure or non-infrastructure 
(grid)  solutions,  energy  suppliers  include  organisations  that  are  interpreted  to  predominantly  produce  energy  and 
energy  offtakers  include  organisations  that  are  interpreted  to  predominantly  consume  energy,  such  as  industrial 
companies. 

65 

 
 
 
 
 
 
 
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 

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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. 

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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.  

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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.  

69 

 
 
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 

70 

 
 
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.  

160 Importantly, 21% of respondents were neutral and 31% uncertain on this. 

71 

 
 
 
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%). 

72 

 
 
 
 
 
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 

Type of stakeholder per 
target group 

European  citizens  and 
consumers  

Practical implications 

Ensuring  more  fit  for  purpose  energy  infrastructure  planning 
will  benefit  citizens  in  several  ways.  Optimal  and  efficient 
deployment of infrastructure and renewable energy assets will 
support  phase-out  of  fossil  fuels  and  lower  greenhouse  gas 
emissions. 

Considering that grid expansion is a prerequisite for the energy 
transition  and  for  further  electrification  of  the  economy,  high 
investment  costs  in  energy  infrastructure  are  unavoidable. 
These will also affect the tariffs covering the increased costs of 
infrastructure. The Grids Package will help reduce the costs of 
investments,  by  improving  planning  and  identification  of  key 
infrastructure  priorities  and  supporting  deployment  of  less 
costly non-wired solutions. 

73 

 
 
 
Project 
promoters, 
including  Transmission 
System Operators 

Accelerated  permitting  process  will  also  allow  for  a  faster 
implementation  of  key  project,  bringing  forward  the  benefits 
identified in cost-benefit analyses at national and regional level 
and avoiding high dispatch costs for consumers associated with 
delays. 

By  addressing  the  security  concerns  and  improving  climate 
resilience of infrastructure, the Grids  Package  will reduce the 
risk of black-outs and potential crisis situations caused by power 
shortage, e.g. transport disruptions. 

More top-down steering of infrastructure planning will further 
increase transparency in scenarios and needs identification used 
for the selection and implementation of PCIs and PMIs, which 
will  help  citizens  and  consumers  understand  the  benefits  and 
necessity  for  priority  projects  and  hence  improve  public 
acceptance.  

More  visibility  and  predictability  of  planned  infrastructure  as 
well as expansion of investments will have a positive impact on 
energy sector employment. 

The overall effect on TSOs should be neutral. TSOs will have 
some additional responsibilities, including to propose solutions 
to  possible  unaddressed  infrastructure  gaps  and  assess  and 
report  security  vulnerability  for 
the  proposed  projects. 
However,  stronger  support  and  push  towards  non-wired 
solutions  will  reduce  the  pressure  on  TSOs  to  pursue  all 
infrastructure projects. 

Improved  coordination  with  national  plans  and  less  stringent 
requirements for internal lines to qualify for the PCI status will 
help  TSOs  deliver  key  national  infrastructure.  Also,  the 
European  Commission  taking  over  responsibility  for  scenario 
building  should free personal  capacity on  TSO side, as  TSOs 
are closely involved in the TYNDP currently next to ENTSOs. 

Moreover, thanks to reduced reporting and streamlining of the 
PCI/PMI process fewer resources will be needed to propose and 
keep projects in the Union list.  

More  robust  and  predictable  long-term  planning  will  create 
more  certainty  for  investors,  allowing  project  promoters  to 
obtain  financing  from  the  market.  The  streamlining  and 
acceleration of permitting will also lead to reduced costs, faster 
project deployment, and improved certainty. 

74 

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

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

National 
Authorities 

Regulatory 

European 
Regulators (ACER) 

Union 

The main impact on European TSOs will come from the lower 
frequency of scenarios and needs assessment which up to now 
are  under  their  responsibility.  The  lower  frequency  will  help 
reduce  resource  needs  and  ensure  timely  completion  of  other 
TYNDP  deliverables.  Taking  over  scenario  developments  by 
the European Commission will also bring additional savings to 
these organisations. 

They will continue to be key actors in infrastructure planning 
but with less power and discretion on the approach to be taken 
given the more prescriptive framework and ex ante steering. The 
more  defined  rules  will  reduce  the  efforts  needed  to  reach 
agreement between the three organisations on various aspects of 
the planning which under the current framework was often both 
time and resource consuming. 

The initiative will increase the involvement of Member States 
in  the  infrastructure  needs  identification  process  as  well  as 
identification  of  possible  solutions.  Consequently,  additional 
resources might need to be mobilised in the national authorities 
to actively contribute to the process. However, this would also 
give Ministries more influence on the outcomes on the process 
and  should  ultimately  lead  to  greater  political  and  public 
acceptance of grid planning and respective projects.  

National  Competent  Authorities (NCAs) would be faced with 
tighter  permitting  deadlines  but  also  streamlined  and  more 
simplified  requirements  for  grids.  They  would  also  need  to 
dedicate resources to the digitalisation of permitting procedures, 
which are expected to lead to efficiency gains in a longer-term 
perspective.  

The role of the NRAs will increase as they will be more involved 
in the validation of the identified infrastructure gaps as well as 
the  solutions  to  fill  the  unaddressed  needs.  NRAs  would  also 
need  to  better  verify  the  application  of  the  central  scenario 
developed by the Commission meaning that some more thorough 
scrutiny  of  the  NDPs  will  be  needed,  but  it  is  not  expected  to 
create much additional work.  

As  regards  CBCA,  NRAs  would  have  a  new  responsibility  to 
prepare coordinated CBCAs for the bundle of projects,  but  the 
number of such project bundles is not expected to be very high. 

ACER  will  have  a  strengthened  role  in  setting  a  framework 
methodology  for  the  identification  of  infrastructure  needs.  It 
will also validate the application of the methodology to ensure 
that the needs are well captured. Monitoring exercise should be 
merged with  the processes under PCI/PMI assessment, which 

75 

 
 
 
 
 
Distribution 
operators 

system 

Energy 
Industry 

producers 

/ 

would  positively 
impact  ACER  from  an  administrative 
perspective, but also bring ACER and NRA views earlier in the 
assessment process. On the other hand, the formal role of ACER 
will  be  more  prominent  in  scenario  development,  as  this  task 
will  be  taken  over  by  the  Commission.  In  addition,  ACER 
would  have  to  update  the  CBCA  Recommendation  based  on 
principles include in the TEN-E framework. 

There are no legal changes directly impacting the role of DSOs 
or  bringing  further  responsibilities.  However,  continuation  of 
ongoing initiatives and their strengthening (on smart and digital 
technologies, use of common scenarios and better coordination 
with TSOs as required by applicable legal framework) will lead 
to increased role of DSOs.  

The initiative would bring significant positive benefits for energy 
producers  as  well  as  energy  consuming  industry,  as  it  aims  to 
improve  alignment  of  grid  planning  with  the  expected  pace  of 
energy  generation  deployment  and  consumption.  This  would 
allow  for  earlier  grid  connection  both  on  the  consumption  and 
generation side, and hence positive micro and macro-economic 
benefits  stemming  from  higher  SEW  coming  from  electricity 
generation  (or  avoided  cost  when  waiting  for  delayed  grid 
connection). 

investment  certainty, 

Better  incorporation  of  the  non-wired  solutions  and  grid 
enhancing  technologies  would  further  support  the  market 
expansion  of  these  technologies.  Streamlined  and  accelerated 
permitting  procedures  for  renewable  energy  projects  would 
improve 
facilitate  quicker  project 
realisation  and  return  on  investment  for  renewable  energy 
producers.  The  initiative  aims  to  significantly  lower  energy 
system costs with positive implications for consumers, including 
industry. While higher electricity grid investments could lead to 
higher tariffs for all consumers, the overall lower energy system 
costs  would  also  be  transferred  on  to  consumers,  including 
industry, via lower wholesale electricity prices.  

improving  climate 
By  addressing  security  concerns  and 
resilience  of  infrastructure,  the  Grids  Package  will  also 
contribute to ensure more reliable energy supply, which is crucial 
also for industrial consumers. 

2.  SUMMARY OF COSTS AND BENEFITS 

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

76 

 
 
 
 
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. 

I. Overview of Benefits (total for all provisions) – Preferred Option 

Description 

Economic impacts 

Amount 

Direct benefits 

Comments 

14 billion  n EUR /year of reduction of system 
costs  (composed  of  total  network  investment 
(including  costs  of  related  necessary  internal 
reinforcements and generation costs) until 2040 

Benefits coming from with the optimal grid 
the  TYNDP  projects  and 
meaning 
addressing  all 
identified  needs 
the 
associated with yearly investment of EUR 
6  bn/year  between  2025  and  2040.  The 
preferred  option  would  help  to  achieve 
those benefits, but the exact share is hard to 
quantify. 

As  above,  benefits  coming  from 
optimal grid. 

the 

Benefits  of  avoided  redispatching  in  case 
of relevant grid buildout 

As  above,  benefits  coming  from 
the 
optimal  grid  as  well  as  accelerated 
permitting procedures for grids, renewable 
energy  generation  and  storage  projects  as 
well as recharging stations. 

Non-wired solutions and planning based on 
credible  demand  projections  would  lower 
CAPEX needed to be recovered in tariffs. 
Better  planning  allows  better  and  faster 
RES integration bringing lower prices. 

Removing  grid  congestion  hampering 
electrification  or  investment  in  industries 
requiring high electricity e.g. data centers. 
Completing 2024 TYNDP project portfolio 
would lead to mobilisation of huge amount 
of  investment,  as  well  as  to  some  4.1 
million jobs in the EU 

Reduced CO2 emissions  

27 Mton per year in the EU 

Reduced  redispatching  of 
RES 

37 billion EUR/year in 2040 

RES integration 

Avoiding curtailment of 143 TWh in 2040  

Electricity prices 

Reduced tariff increases and retail prices 

Indirect benefits 

Increased competitiveness 

Support  for  electrification  of  energy  intensive 
industries 

EUR 603 billion in mobilised investments into 
grid technologies by 2040 

77 

 
 
 
 
 
 
 
 
Electrification  of  different 
sectors  through  better  grid 
access   

Greater grid security 

Not possible to monetise benefit. 

More grid capacity based on optimised grid 
planning and use will enable electrification 
of transport and industry as well as better 
grid access for data centres. 

Avoided  costs  of  repairs  -  EUR  50-60  million 
for an undersea cable and of additional loss of 
economic welfare due to price increases. 

Addressing  security  vulnerabilities  would 
lower the costs of outage, more expensive 
power 
of 
sabotaged/damaged infrastructure 

repairs 

supply 

and 

(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. 

II. Overview of costs – Preferred option 

Citizens/Consumers 

Businesses 

Administrations 

One-off  Recurrent 

One-off 

Recurrent 

One-off 

Recurrent 

Direct adjustment 
costs 

N/A 

N/A 

N/A 

PO2    

TSO:  Ensure 
data collection 
for 
the 
scenario 
development 
and  follow-up 
of 
identified 
infrastructure 
needs 
filling 
mechanism). 

(gap 

EC:  Building 
capacity  to  take 
over 
some 
planning 
activities.  

NCA:  Set  up  a 
digitalised 
permitting 
system and data 
collection. 

NRAs:  
Regulation of 
projects 
outside their 
territory and to 
cooperate in 
groups with 
NRAs and 
TSOs from 
different 
Member States 
under the cost-
sharing 
framework. 

Direct 
administrative 
costs 

N/A 

N/A 

N/A 

ACER: 
framework 
methodology 
for 

the 

EC:  18  FTEs 
&  EUR  0.5 
mln 
in 
external  costs 

TSOs/Project 
promoters: New 

78 

 
 
 
 
 
security 
reporting 
and 
risk  mitigation 
requirements 
which  would 
affect  a  small 
of 
share 
TSOs/project 
promoters. 

identification  of 
infrastructure 
needs  (grouped 
together  with  2 
FTEs  for  data 
verification  for 
scenario 
development) 

ACER: 
implementation 
costs  to  update 
CBCA 
its 
recommendatio
n (and develop a 
template 
(estimated 
FTE). 

1 

for 
implementing 
new  planning 
tasks.  

as 

& 
NRAs 
to 
ACER: 
ensure 
data 
verification  for 
the 
scenario 
development 
as  well 
verification, 
approval,  and 
follow-up 
of 
identified 
needs 
filling 
mechanism).  2 
for 
FTEs 
ACER.  

(gap 

NCA:  Increase 
resources 
to 
deal 
with 
tighter 
permitting 
deadlines. 

Direct regulatory 
fees and charges 

Direct 
enforcement costs 

Indirect costs 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

for 

NRAs: 
Additional 
resources 
better 
enforcement of 
the  regulatory 
framework. 

N/A 

N/A 

N/A 

in 

Higher 
electricity 
prices 
some 
countries 
due  to  price 
convergence 
impacts. 

Possible 
higher 
network 
tariffs  

N/A 

Higher 
electricity 
prices in some 
countries  due 
to 
price 
convergence 
impacts. 

Possible  higher 
network tariffs 

79 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(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;).  

III. Application of the ‘one in, one out’ approach – Preferred option(s) 

One-off 

Recurrent 

Total 

[M€] 

(annualised total net present 
value over the relevant period) 

(nominal values per year) 

Businesses 

New administrative 
burdens (INs) 

N/A 

Removed administrative 
burdens (OUTs) 

N/A 

A slight increase in 
administrative burden for 
TSOs and project 
promoters. 

A significant reduction of 
the administrative burden 
for ENTSOs, TSOs and 
project promoters. 

TSOs/Project promoters: New 
security reporting and risk 
mitigation requirements. Cannot 
be quantified at this time but 
expected to be limited. 

ENTSOs  &  TSOs:  Reduced 
frequency of TYNDP process and 
Commission  taking  over  central 
scenario development = savings of 
between EUR 2 and 4 million per 
year. 

application 

promoters: 
TSOs/project 
and 
simplified 
evaluation process for mature PCIs 
and  PMIs.  Expected  savings  per 
PCI/PMI  list  between  EUR  0.25 
and 0.5 million.  

Streamline  permitting  procedures 
will 
reduce  costs,  accelerate 
project  deployment,  and  improve 
certainty.  Cannot  be  quantified  at 
this time. 

Net administrative 
burdens* 

N/A 

Savings of at least between EUR 
2.5 and 4.5 million. 

Adjustment costs** 

N/A 

Citizens 

TSO: Ensure data collection for the 
scenario development as well as 
follow-up of identified needs (gap 
filling mechanism). Cannot be 
quantified at this time. 

80 

 
 
 
 
 
 
 
 
 
New administrative 
burdens (INs) 

Removed administrative 
burdens (OUTs) 

Net administrative 
burdens* 

Adjustment costs** 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

Total administrative 
burdens*** 

No administrative burden is 
expected for citizens. 

The total recurrent administrative 
burden would be significantly 
lowered (negative), due to 
simplified infrastructure 
planning, cost-sharing and 
permitting procedures 

The total administrative 
burden would be 
significantly lowered 
(negative), as the 
increase in 
administrative costs 
related to new security 
and reporting 
requirements would be 
offset by simplified 
planning and permitting 
processes. 

(*) 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 

IV. Overview of relevant Sustainable Development Goals – Preferred Option(s) 
Relevant SDG 

Expected progress towards the Goal 

Comments 

SDG no. 7 - affordable and 
clean energy  

SDG 9 Industry, Innovation 
and Infrastructure 

option  will 

This targeted revision will support the impacts of 
the  TEN-E.  By  achieving  an  expanded  and 
modernised  grid,  electricity  will  become  more 
easily  available  throughout  the  EU.  Thus,  the 
preferred 
strengthen  market 
integration, increase electricity supply and enable 
access to affordable and clean energy. This is vital 
to counter growing energy poverty in the EU. All 
above will benefit both households and industry. 
More affordable electricity prices due to positive 
effects  of  greater  market  convergence  will 
especially improve the competitiveness of energy 
intensive industries and encourage investments in 
decarbonisation  and  clean  energy  business 
models. 

Aim of the initiative is to achieve better planning 
catering for future developments of demand and 
supply, including in the industrial sector, as well 
as achieve resilient and sustainable infrastructure 
development.  Hence  it  is  fully  aligned  with 
resilient 
SDG9,  which 
build 
inclusive  and 
infrastructure  and  promote 
sustainable 
innovation. 
industrialization  and 
Regarding  the  latter,  preferred  option  aims  to 

aims 

to 

81 

 
 
 
 
 
12 

SDG 
consumption 
production 

Responsible 
and 

SDG no. 13 Climate 

more  strongly  support  digital  and  smart  grid 
technologies,  contributing  to further  innovation 
efforts in the grid manufacturing industry. 

By  fostering  modernised  and  expanded  grid  the 
preferred  option  will  enable  the  build  out  of 
renewable energies and hence a quicker phase out 
of fossil fuels. The digitalisation and optimisation 
of the grid will enable more cost-optimal dispatch 
and  lower  curtailment  of  renewable  energy. 
Improved  availability  of  renewables  based  on 
sufficient  grid  capacity  will  incentivise  energy 
intensive industries to favour decarbonised energy 
including  both  production  and 
consumption 
consumption  of 
low  carbon  hydrogen.  The 
changes  in  consumption  trend/pattern  above  can 
be monitored.  

As above, the preferred option will support more 
optimal, modernized and expanded grid, which in 
turn  will  enable  the  integration  of  renewable 
energies and a quicker phase out of fossil fuels. 
Reduced  fossil  fuels  consumption  will  reduce 
greenhouse  gas  emissions.  As  time  is  of  the 
essence  for  avoiding  irreversible  damage  to  the 
climate and repercussions on biodiversity, adding 
renewable  energy  capacity  is  expected  to  be  a 
tangible result to be measured in both time and 
size (installed capacity). 
Because  the  initiative  prioritizes  cross-border 
projects, efficiencies among Member States will 
  Through  better  planning, 
be  obtained. 
overinvestments 
avoided,  hence 
can  be 
improving  the  overall  environmental  footprint. 
Moreover, 
can 
stimulate innovative solutions, including the use 
tools  can 
of  digital 
improve 
terms  of  operations  and 
efficiencies, 
maintenance,  increased  electricity  output  and 
reducing network losses.   

co-operations 

tools.  Such 

cross-border 

in 

ANNEX 4: ANALYTICAL METHODS 

Analysis of the needs for infrastructure and the benefits of the optimal grid 

82 

 
 
 
 
 
 
The analysis builds on the 2024 TYNDP Infrastructure Gaps Report (IGR)161 which screens the 
entire  European  perimeter  to  identify  potential  needs  in  terms  of  increase  of  interconnection 
capacities at ENTSO-E perimeter by 2030, 2040 and 2050 time horizons. 

The methodology for identifying infrastructure gaps and benefits of matching the infrastructure 
needs, as outlined involves several key steps: 

1.  Scenarios  Development:  The  process  begins  with  defining  a  range  of  possible  future 
scenarios that test infrastructure needs. This includes assessing different possible futures 
and understanding infrastructure requirements at various timelines such as 2030, 2040, and 
2050. The infrastructure needs assessment is based on the TYNDP 2024 National Trends+ 
scenarios for 2030 and 2040 and Distributed Energy scenarios for 2050. 

2.  System  needs  identification:  This  part  of  the  study  considers  the  European  electrical 
system as a whole to identify where new system assets would bring benefits. It involves 
analysing the combination of potential network capacity increases between countries and 
storage that minimize total system costs. The costs include network investment, internal 
reinforcements, and generation costs, while maximising socio-economic welfare. 

The  process  involves  collecting  input  data  from  different  sources.  This  includes  data 
related to transmission, storage projects, and potential hybrid projects focused on cross-
border capacity increases. Then a general market modelling approach is undertaken where 
scenarios  are  evaluated  to  determine  potential  future  energy  systems.  This  involves 
simulations to check reference case congestions and identify the flows within the system.  

The simulations  use different  approach depending on the time horizon. For 2030, NTC 
Model  (Net  Transfer  Capacity  model)  is  used  for  assessing  transfer  capacities  between 
bidding zones or countries. A zonal market simulation is performed for 2040. It includes 
defining clusters for generation and load data to optimize data processing and validation 
based on PECD Zone Clustering Model.  

In order to define clusters, first internal inter-zone connections are given infinite capacity 
to  focus  on  cross-border  bottlenecks,  while  maintaining  technical  constraints  like 
impedance. HVDC links are then added, requiring special constraints due to their unique 
behaviour. Corrections for Phase Shifting Transformers (PSTs) are also implemented to 
reflect their effect on power flow, modifying mesh rules accordingly. Once the model is 
set,  a  zonal  simulation  is  run  to  detect  existing  congestions  (this  represents  the  first 
modelling run). Based on this run, candidate interconnection projects are collected with 
standard  cost  data  from  TSOs  and  project  promoters.  These  are  then  implemented  in  a 
capacity  expansion  model  using  Antares  Xpansion,  which  solves  for  the  most  cost-
effective set of cross-border upgrades. The optimisation relies on Benders Decomposition, 
which  breaks  the  problem  into  manageable  steps:  proposing  investments,  simulating 
dispatch,  calculating  total  costs,  and  refining  until  the  cost  no  longer  significantly 
improves. This iterative process intends to allow for the identification of strategic upgrades 
that  minimise  long-term  system  costs  while  ensuring  security  of  supply  and  efficient 
integration of renewables.  For 2050, Simplified Zonal Market Model is used.162 

161 ENTSO-E (2025), TYNDP 2024. Opportunities for…op. cit. 
162 ENTSO-E (2025), TYNDP 2024. Identification of the System Needs Study Methodology 

83 

 
 
 
 
Figure 6: Step-by-step Identification of System Needs process diagram (TYNDP 2024 for 2040-time horizon) 

Source: ENTSO-E Identification of the System Needs Study Methodology 

The optimization of the grid where it would minimise the total system costs is performed in two 
phases:  

•  The first phase considers only existing projects, collected from project promoters, on top 
of the ones already included in the reference network and based on TSO submission (Third 
party and TSOs). For battery and flexibility candidates, the only capacities considered in 
this phase are the ones removed from starting point.   

•  The  second  phase  considers  conceptual  candidates  added  to  candidates  that  were  not 
selected from  the first  loop  of optimization. These include conceptual interconnections, 
collected  from  TSOs,  hybrid  projects,  collected  from  regional  groups,  and  normative 
flexibilities.  

In the 2024 System Needs assessment, the H2 system is also modelled, adding complexity to the 
data  collection  (performed  in  the  Scenario  Building  process)  and  the  computation.  The  results 
allowed for a following process that intends to capture the hydrogen infrastructure gaps in Europe. 

3.  Infrastructure  gaps  identification:  This  part  of  the  study  identifies  where  there  is  a 
potential difference between cross-border capacity needs and the expected increases from 
transmission  projects  to  be  developed  in  the  future.  Thes  projects  represent  investment 
candidates submitted by project promoters and are largely in line with the TYNDP 2024 
projects portfolio. This analysis helps map where there are opportunities for new solutions 
to increase capacity. 

The benefits of an optimal grid are assessed by looking among others at: 

84 

 
 
 
 
 
 
1.1.  Socio-Economic  Welfare  (SEW)  which  reflects  the  sum  of  economic  surpluses  for 
electricity consumers, producers, and transmission owners. It measures how much more 
efficient  and  beneficial  the  grid  becomes  by  enhancing  cross-border  transmission  and 
reducing congestion. 

1.2.  Reduction  in  system  costs  estimating  reductions  in  total  system  costs,  like  network 
investment,  internal  reinforcement,  and  generation  costs,  achieved  by  optimizing  grid 
capacity and eliminating constraints. 

1.3.  Integration of renewable energy sources which is based on the ability of the optimal 
grid to integrate and utilize renewable energy, thereby reducing reliance on fossil fuels, 
decreasing carbon emissions, and supporting sustainable energy goals. 

1.4.  Avoided  curtailment  where  the  assessment  considers  the  reduction  in  curtailment 
(unused renewable power due to grid constraints) as a significant grid optimization benefit 
by maximizing the use of generated renewable energy. 

1.5.  Reduction  in  CO2  emissions  which  includes  evaluating  how  better  cross-border 
integration and increased capacity for renewable energy contribute to decreases in CO2 
emissions, aligning with environmental targets. 

1.6.  Economic and market benefits looking at how an optimal grid enables more competitive 
electricity  pricing  by  facilitating  market  integration  and  reducing  regional  price 
disparities. It leads to lower electricity bills and broader economic benefits. 

Infrastructure needs assessment by JRC 

The JRC assessment applies the same logic to the infrastructure needs assessment as the ENTSO-
E  IGR,  but  uses  a  different  model  (METIS  3)  and  introduces  some  adjustments  to  make  the 
assessment more in line with the latest policy developments. The analysis is based on the National 
Trends + scenario 2030 and 2040, while the investment candidates and their costs used for grid 
optimisation come from: 

•  Explicit TYNDP candidates and their costs cost,  

•  Generic expansion candidates, 

•  Complete bidirectional line setup (LU),  

•  Candidates from scenario results.  

The reference grid and the expansion candidates for the expansion study provide a modelling setup 
for METIS. The nodes are divided into those at which installed generation capacities or demand 
is located and nodes which have neither. The METIS scenario is parametrised to closely resemble 
the TYNDP National Trends+ scenario, but some differences remain. The model produces some 
additional outputs such as average electricity prices after the line expansion. 

Analysis of the delays in infrastructure deployment 

The analysis has been performed by the JRC based on the 2024 TYNDP National Trends + data 
and METIS model optimisation, and based on data on delays coming from 2020 to 2026 TYNDP 
project collections.  

85 

 
 
 
 
 
The quantification of costs of delays looks at 2030 comparing a situation with projects expected 
initially  to  be  completed  by  2030  (No  delays  case)  to  a  situation  without  the  projects  whose 
commissioning dates were moved to 2030 and beyond (delayed scenario). The expected grid in 
2030 contains: 

•  ENTSO reference grid (aggregated per border) for 2030 
• 

any additional project candidates with initial commissioning dates by 2030 (data coming 
from previous TYNDPs) 

This forms the “No delays case” with additional MW and annualised CAPEX and OPEX of each 
candidate.  

In the delayed scenario, the projects with delays leading to commissioning dates beyond 2030 
have been removed from METIS optimisation (the latest data comes from information provided 
by project promoters in the context of the 2nd PCI/PMI list and project submissions to the TYNDP 
2026). 

The  analysis  covers  only  transmission  projects,  meaning  that  the  effects  of  delayed  storage 
projects are not included in the METIS contexts.  

The impact of the delays was estimated in terms of:  

•  Average  price  per  zone  and  scenario  and  delta  of  delay  scenario  compared  to  the  No 

Delays case;  

•  Delta in Social Economic Welfare to the No Delays case;  
•  Total cost of generation (fuel cost, emission certificates, variable O&M) and delta to No 

Delays case;  
Investment costs compared to the delayed projects.  

• 

Analysis of the benefits of dynamic line rating deployment 

Commission analysis used available data from Joint Allocation Office (JAO - Leading service 
provider for TSOs), from the common grid model and results of shadow pricing in the period of 
April 2022 to June 2025. It analysed 143 most congested lines in the CORE region (i.e., their 
aggregated share in total shadow prices <99%, lines with frequent changes to Fmax were filtered 
out before the calculation), and applied dynamic line rating on these lines (assumptions: increase 
of available maximum flow Fmax by 20 % in 1/3 of the year, 70 % of such increase available for 
cross-border trade). Yearly shadow prices were discounted by 0.5 % annually due to expected 
decrease of the shadow prices, and benefits were calculated per expected life-duration of 20 years 
for dynamic line rating technology. Costs of dynamic line rating were taken from conservative 
estimate  of  Forbes 
(https://www.forbes.com/sites/annabroughel/2025/03/27/dynamic-line-
rating-grid-technology-to-reduce-your-electric-bills/).  For  comparison,  ACER  estimate  is  500 
000  EUR  for  one  line  to  be  equipped  by  the  dynamic  line  rating,  which  would  result  in 
approximately 50 % lower costs if we apply it on the identical line base. In this relation, more 
conservative (higher) Forbes values were chosen. 

Analysis of the benefits of accelerating permitting for recharging stations 

86 

 
 
 
First, the high energy efficiency of EVs must be considered. While electricity accounted for only 
7% of the total energy use in road transport in 2023, it powers 26% of the miles driven.163 

Second, the ACER Market Monitoring Report shows that the need for congestion management 
jumped  14.5%  in  2023,  driving  up  system  costs.  It  estimates  that  the  costs  of  managing 
congestion  in  the  EU  power  grid  exceeded  €4  billion.  Increasingly,  congestion  management 
results in renewable energy being curtailed. Streamlining permitting procedures for recharging 
stations, and thus accelerating EV adoption, will contribute to limit renewables curtailment and 
to reduce GHG emissions thanks to smart charging, by increasing electricity demand at the right 
times (when clean energy is abundant) and store it for later use.  

EVs can provide additional flexibility thanks to bidirectional charging, by selling energy back to 
the grid at peak times. EVs with bidirectional charging capabilities could contribute up to 4% of 
Europe’s annual power supply by 2030. Estimated at 114 TWh battery capacity, it is enough to 
power  30  million  homes  every  year.164  By  2040,  EVs  utilizing  bidirectional  charging  could 
supply up to 9% of Europe’s annual electricity demand, positioning them as the fourth-largest 
electricity  provider  in  the  region.165  During  peak  times,  EVs  could  supply  up  to  15–20%  of 
electricity demand, serving as a large virtual power plant.166 The economic benefits might raise 
up to  €22 billion per year in  savings  for EU energy systems  by 2040 through vehicle-to-grid 
(V2G) integration.167 Moving to smart and bidirectional charging could save family car owners 
an average of 20% on total cost of vehicle ownership.168 Electric bus fleets could even reduce 
their charging costs, a primary component of their operating expenditure, by more than 90% with 
V2G.169 In terms of GHG emissions, by 2035, V2G could reduce CO₂ emissions by 60 million 
tonnes per year in Europe through reduced use of fossil-fuel generation at peak.170 Cumulative 
savings (2025–2040) could reach 350 – 450 Mt CO₂. 

Additional evidence from other studies or assessments 

Economic impacts - benefits from optimised grid in 2040: 

As set out in section 6.1.1, 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). Figure 7 provides a more detailed 
overview on the expected benefits. 

163 IEA, Global EV Outlook 2023 
164 EY/Eurelectric report, Plugging into potential: unleashing the untapped flexibility of EVs, March 2025 
165Fraunhofer study for T&E, Batteries on wheels: the untapped potential of EVs, October 2024 
166 Fraunhofer study for T&E, Batteries on wheels: the untapped potential of EVs, October 2024 
167Fraunhofer study for T&E, Batteries on wheels: the untapped potential of EVs, October 2024 
168 EY/Eurelectric report, Plugging into potential: unleashing the untapped flexibility of EVs, March 2025 
169 https://www.sciencedirect.com/science/article/pii/S136655452300073X 
170Fraunhofer study for T&E, Batteries on wheels: the untapped potential of EVs, October 2024 

87 

 
 
 
 
Figure 7: Expected benefits from optimised grid in 2040 

Source: ENTSO-E, TYNDP 2024 Infrastructure Gap Report 

Economic impacts - congestion income: 

Further to the assessment in section 6.1.1, in 2021, NRAs reported to ACER on the use of EUR 
6.9 billion of overall congestion income.171 45% was used on the priority objectives172, and 49% 
was saved on internal accounts. The remainder 6%, was used partly to reduce tariffs and partly to 
cover  tax  obligations  incurred  by  the  transmission  system  operators.173  For  2024174,  the  total 
congestion income collected was around EUR 8.4 billion with around EUR 5 billion spent on the 
priority  objectives  and  more  than  EUR  1  billion  for  tariff  reduction  and  electricity  customers' 
support.175 As a result, around EUR 2.4 billion is expected to be stored. Of the EUR 5 billion spent 
on  the  priority  objectives,  around  EUR  1  billion  was  used  for  “ongoing  investment  or  capital 
expenditures  for  renewal,  replacement,  reinforcement  of  existing  assets,  or  new  assets  which 
significantly contribute to maintaining or increasing cross-zonal capacity, including the costs of 
development and construction phases of such assets”. 

Economic impacts - redispatch volumes: 

In  addition  to  the  assessment  in  section  6.1.1.,  the  below  figure  shows  the  evolution  of 
redispatched volumes in European system in three scenarios done by the JRC: business as usual 
(10 % of grid expansion by 2040), ambitious grid expansion (20% increase of grid capacity by 
2040)  and  extreme  grid  expansion  (35  %  increase  of  grid  capacity  by  2040).  Redispatching 

171 ACER. (2022). Use of Congestion Income 2021 ACER Monitoring Report. 10.1 Use of Congestion Income 2020  
172 Article 19(2) of Regulation (EU) 2019/943. Priority objectives include a) guaranteeing the actual availability of 
the  allocated  capacity  including  firmness  compensation  and  b)  maintaining  or  increasing  cross-zonal  capacities 
through  optimisation  of  the  usage  of  existing  interconnectors  by  means  of  coordinated  remedial  actions,  where 
applicable, or covering costs resulting from network investments that are relevant to reduce interconnector congestion. 
173 CERRE_Infrastructure_Final-report.pdf 
174 Congestion revenues for the years 2022 and 2023 are not considered representative due to the energy crisis and 
therefore are not included here. 
175 ACER data 

88 

 
 
 
 
 
significantly drops between BAU and AGE, and further in XGE scenario (see Figure 8).176 Of 
the total amount of electricity redispatched, between 50-120 TWh will be of renewable origin in 
2030, and between 100-310 TWh in 2040 (depending on the scenario). These numbers confirm 
that appropriate grid expansion can significantly lower environmental losses linked to curtailed 
electricity from renewables. (See estimation of ENTSO-E in the following paragraph, noting that 
optimal  grid  would  decrease  curtailed  RES  by  143  TWh  in  2040,  matching  the  middle  JRC 
scenario). 

Figure 8: Evolution of redispatch volumes in the European power system 

Figure  9  shows  the  expected  redispatching  costs  under  different  grid  development  scenarios 
(BAU, Ambitious Grid Expansion (AGE) and Extreme Grid Expansion (XGE)) as shown below 
from the JRC analysis. 

176 This JRC study does not identify optimal grid as such, which represents a shortcoming.  To this aim, we do not 
show results compared per policy option, but only for illustration of potential positive benefits from avoided RES 
curtailment perspective. 

89 

 
 
 
 
 
 
Figure 9: Evolution of redispatch costs in the European power system (JRC, 2024) 

CO2 emissions decrease for optimised grid: 

Figure 10 provides a more detailed overview on expected CO2 emission reductions for certain 
countries as set out in section 6.3 on environmental impacts. 

Figure 10: CO2 emissions decrease for optimised grid, source: ENTSO-E 2024 TYNDP 

90 

 
 
 
 
 
 
 
 
 
Administrative costs: 

Policy option 3: 

The most substantial administrative costs are expected for PO3 and the establishment of entities 
responsible for infrastructure planning and permitting. To estimate the administrative costs of 
setting  up an entity  to  cover all tasks in  relation  to  infrastructure planning (PO3), the current 
budget of ENTSO-E and ACER can serve as examples. For 2023, the budget of ENTSO-E177 
totalled  EUR  61.2  million,  mostly  funded  by  TSO  member  fees.  As  of  31  December  2023, 
ENTSO-E counted 145 employees including permanent staff and secondments from TSOs. In 
addition, ENTSO-E is relying on “numerous” TSO staff members to bring in their expertise to 
execute their tasks. While infrastructure planning  is  only  one of ENTSO-E’s  tasks, the  entity 
would  also  cover  hydrogen  infrastructure  planning  which  is  currently  with  ENTSO-G  and 
ENNOH. In comparison, ACER’s total budget for 2023 was EUR 30 million, with 152 permanent 
staff  divided  in  three  main  areas:  energy  market  and  system  needs,  REMIT  and  horizontal 
activities178. For the entity, staffing of 50  FTEs with an annual  budget  of around EUR  10-15 
million might be required to carry out all tasks. 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  entity,  all  horizontal  functions  would  have  to  be 
established for a new entity (e.g. legal, finance, HR, IT). 

Given  the  highly  specialised  tasks,  the  establishment  of  such  an  entity  and  the  time  for  it  to 
become fully operational is likely to take several years which would further delay the expected 
benefits  and  hence  increase  costs  in  terms  of  non-realised  benefits.  It  is  expected  to  be  very 
difficult to hire highly specialised staff with sufficient experience in network operation, which is 
intrinsically  linked  with  network  planning  as  well  as  responsibility  for  security  of  supply. 
Substantial costs are expected to ensure full consistency of the complex network models required 
by the entity for grid planning and the network models used for other tasks by the already existing 
entities, e.g. system operation. The split  between tasks related to  planning (newly  established 
entity)  and  operation  (ENTSOs/TSOs)  across  different  entities  entails  substantial  risks  of 
inconsistencies possibly affecting energy security and questioning liability of respective actors.  

For  cost  and  benefit  sharing,  the  administrative  costs  are  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 

177  ENTSO-E:  Annual  Report,  2023  Edition,  https://consultations.entsoe.eu/entso-e-general/have-your-say-on-the-
entso-es-annual-report-2023/supporting_documents/ENTSOE%20ANNUAL%20REPORT%202023.pdf 
178 
https://www.acer.europa.eu/sites/default/files/documents/Publications/ACER-Consolidated-Annual-Activity-
Report-2024.pdf 

Consolidated 

activity 

(2025): 

annual 

ACER 

report 

2024, 

91 

 
 
 
 
 
 
for at least 250 projects with a cross-border dimension179. To do so, it will have to liaise with 
national  and local  authorities for authorisation.  Taking  a conservative assumption, this would 
require 50 FTEs, representing a total budget, including overhead, of at minimum, EUR 10 million 
per year. Further, PO3 is unlikely to 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. 

179 Assuming 220 PCIs and PMIs per Union list and additional cross-border renewable and storage projects. 

92 

 
 
 
 
 
ANNEX 5: COMPETITIVENESS CHECK  

1.  OVERVIEW OF IMPACTS ON COMPETITIVENESS  

Dimensions of 
Competitiveness 

Impact of the 
initiative 
(++ / + / 0 / - / -- / n.a.) 

References to sub-sections of the 
main report or annexes 

Cost and price competitiveness 

International competitiveness  

Capacity to innovate 

SME competitiveness 

+ 

+ 

+ 

n.a. 

6.1.1. and Annex 3 

6.1.2. 

6.1.2. and 6.1.3. 

2.  SYNTHETIC ASSESSMENT  

Cost and price competitiveness 

Expanding and modernising EU grids will improve access to electricity and increase supply. All 
other  things  equal  this  will  reduce  the  price  of  electricity,  and  thus  the  production  costs  of 
companies  dependent  on  electricity  as  an  input  to  perform  their  activities.  Examples  of 
companies that are particularly energy intensive are Data Centres, Chemical and Petrochemical 
Industry,  Non-Metallic  Minerals  Industry,  Iron  and  Steel  Industry.  These  industries  not  only 
consume  large  amounts  of  electricity  but  also  contribute  significantly  to  the  EU's  GDP  and 
employment. For these industries, lower electricity cost imply that they can improve productivity, 
i.e. produce more with  the same input, or maintain  production levels  and save  costs. Both  of 
which supports higher margins that can benefit owners (shareholders), employers (higher wages) 
and/or the business itself if profits are fully or partly invested in business development, e.g. by 
upgrading facilities and enhancing innovation.   

For  low-carbon  hydrogen,  cost  levels  are  high  in  the  entire  value  chain,  especially  in  the 
production phase which depends on electricity (and water) for electrolysis. Reducing electricity 
prices is therefore enabling the EU to reach ambition levels for domestic hydrogen production 
and derivatives, both of which are essential to transform the hard-to-abate sector and the transport 
sector that will have to transform away from fossil fuels to low-carbon alternative fuels.   

A modernised grid with smart technologies will also entail more flexible grids allowing for active 
demand response, including electricity storage. Storage can also resolve congestion and curtail 
the need for new investments. Thus, an updated grid can both reduce capital costs and smoothen 
out price peaks.  

Eventually, accelerated permitting, will ensure a that infrastructure projects will be completed in 
a shorter timeframe, which means that the net present value of the projects will increase. This 
improves the rate of return for investors and value added for the society. 

93 

 
 
 
 
 
 
The initiative is also expected to overall significantly reduce compliance costs for companies, 
including  system  operators,  project  promoters  and  renewable  energy  generators,  through  a 
simplification and streamlining of processes (see Annex 3).  

International competitiveness 

There are many factors driving international competitiveness, including productivity and costs. 
Lower  electricity  costs  can  also  help  reducing  market  prices  without  squeezing  margins.  For 
companies  that  are  competing  on  an  international  level,  this  will  enhance  their  competitive 
position. Being competitive in export markets usually entails tougher competition than at home 
(EU)  e.g.  due  to  different  legal  requirements,  higher  transportation  costs,  more  established 
competitors etc. Hence, even marginally lower prices can be a decisive factor for international 
competitiveness and market entry in third countries and overseas markets. Furthermore, for the 
EU to  be attractive for foreign  direct  investments,  energy infrastructure  plays a key role as it 
underpins market efficiency and enables industry development. 

Capacity to innovate 

There are two ways that the Grids Package will increase the capacity to innovate. 

First, EU’s ambitions to accelerate the roll-out of renewables are based on a set of plans to guide 
these endeavours, such as the NECP, TYNDP, ONDP, Non-Binding Agreements. These plans 
also set the stage for a more predictable and transparent framework for short-term and long-term 
grid investments. Such a framework is also conducive for related R&I investments, be it among 
project developers, suppliers or research institutions. For instance, a resilient and reliable grid 
must be based on digital solutions and Artificial Intelligence.  

This  will  require  technology  development  and  competencies  to  ensure  that  state  of  the  art 
solutions will be deployed going forward. Such R&I efforts need sustained funding. Hence, by 
providing a more predictable policy framework, the grids package will provide a strong incentive 
for capacity building in both the industry and the research community.  

Second, the transparency and predictability described above will improve demand certainty for 
the various players in the grids supply chain. Demand certainty tends to spur competition and 
hence innovation, including new goods and services, as well as novel manufacturing and business 
processes. The latter includes distribution, marketing and after-sales.  

SME competitiveness 

This initiative is not expected to have specific implications on SME competitiveness in addition 
to the above considerations on competitiveness. 

3.  COMPETITIVE POSITION OF THE MOST AFFECTED SECTORS 

Apart from being an enabler for the renewable energy sector and underpinning the hard-to-abate 
and energy intensive sectors mentioned above, improved access to a modernised transmission 
and distribution grid will contribute to strengthen the competitive position of other industries. 

94 

 
 
 
 
 
 
Accelerating permitting procedures for recharging points will unlock faster infrastructure rollout, 
which improves planning certainty, lowers costs, improves reliability, and levels the playing field 
with fossil fuels, making the e-mobililty sector more competitive, sustainable, and attractive for 
investment. As e-trucks are ramping up, it’s crucial to ensure a proper roll out of infrastructure, 
in order to give visibility to companies and encourage them to make the switch. 

95 

 
 
 
 
ANNEX 6: EXISTING LEGAL EU FRAMEWORK  

A)  Infrastructure planning and use 

Existing legal requirements for planning of transmission and distribution network development 
at EU, regional and national level are included in the Regulation (EU) 2022/869 of the European 
Parliament  and  of  the  Council  of  30  May  2022  on  guidelines  for  trans-European  energy 
infrastructure (TEN- E Regulation), Directive (EU) 2019/944 of the European Parliament and of 
the Council of 5 June 2019 on common rules for the internal market for electricity (Electricity 
Directive), Regulation (EU) 2019/943 of the European Parliament and of the Council of 5 June 
2019 on the internal market for electricity (Electricity Regulation) as well as the Regulation (EU) 
2024/1789 of the European Parliament and of the Council of 13 June 2024 on the internal markets 
for renewable gas, natural gas and hydrogen (Gas Regulation) and Directive (EU) 2024/1788 of 
the European Parliament and of the Council of 13 June 2024 on common rules for the internal 
markets for renewable gas, natural gas and hydrogen (Gas Directive).  

Planning at EU level (electricity, gas and hydrogen)  

Based on the requirements of the Electricity Regulation (Article 30) and Gas Regulation ENTSO-
E and ENTSO-G (and starting with 2027 ENNOH, Articles 32, 60, 61) and the TEN-E Regulation 
(Article 12) adopt biennially the EU-wide Ten-Years Network Development Plan (TYNDP). It 
covers the period of the next 10 years with an outlook for 2040 and 2050 and comprises a system 
needs  identification  based  on  the  joint  scenarios,  as  well  as  projects,  which  are  submitted  by 
respective TSOs and project promoters.  

Pursuant to Articles 26 and 60 of the Gas Regulation, TYNDPs for natural gas and for hydrogen 
are  of  a  non-binding  character.  As  of  2026,  there  should  be  one  TYNDP  for  natural  gas  and 
hydrogen, with two interlinked chapters.  

Based on Article 12 of the TEN-E Regulation, the joint scenarios for electricity, natural gas and 
hydrogen network development may take into account the NECPs and should be developed based 
on Framework Guidelines delivered by ACER (which are however of non-binding nature). Plans 
should  also  consider  national  plans  and  regional  investment  plans,  as  well  as  offshore  non-
binding agreements pursuant to Article 14 of the TEN-E Regulation. Scenarios are approved by 
the European Commission, who can also provide a reasoned opinion to ENTSO-E, ENTSO-G 
and ENNOH in case it does not approve the joint scenarios report. 

The infrastructure gaps report follows as a second step after the scenarios’ development. Based 
on  the  results  of  the  scenarios  as  well  as  projects  submitted  by  project  promoters,  ENTSOs 
develop  infrastructure  needs  analysis,  which  should  contain  estimate  of  future  infrastructure 
needs for 2030, 2040 and 2050. Infrastructure needs are compared with the starting grid, which 
is set based on the project collection made by ENTSOs. ENTSOs and ENNOH are obliged to 
consider  with  priority  all  relevant  alternatives  to  new  infrastructure  and  consider  energy 
efficiency  first  principle  when  assessing  the  infrastructure  gaps.  With  regard  to  timing, 
infrastructure  projects’  collection,  including  data  collection  on  project  costs  and  technical 
parameters, starts approximately 2 years before the final TYNDP is published.  

TYNDP as such is then developed based on joint scenarios, considering the Energy system wide 
Cost benefit analysis (CBA) methodology pursuant to Article 11 of the TEN-E Regulation. This 
methodology is approved by the Commission. The ENTSOs (and in the future ENNOH) assess 

96 

 
 
the benefits of respective projects that are submitted for the TYNDP and may subsequently be 
submitted as candidates to the PCI/PMI selection process. Results are published in respective 
project sheets as part of the TYNDP. There is currently no comparison among the projects as part 
of the TYNDP (for instance among the projects addressing the same need). There is also no link 
between the starting grid for 2030 and 2040 and consequences for the needs assessment.  

The draft results of the TYNDP are submitted to ACER for opinion (which is of non-binding 
character), there is no role for the Commission or Member States in the process. COM provides 
opinion only on the infrastructure gaps report. ACER has a monitoring role on the consistency 
between Union-wide TYNDP and national TNDPs and right to recommend changes in case of 
inconsistencies (both for electricity and gas sectors).  

Most recent changes to the TEN-E Regulation (amendments of Article 11, 12 and 13), done by 
the Gas Regulation recast in 2024, clarified interplay with ENNOH and the hydrogen sector when 
it  comes  to  sector  methodologies  and  the  integrated  model.  Sector  methodologies  for  energy 
system wide cost-benefit analysis for the PCI and PMI selection should be harmonised across the 
sectors,  which  should  be  published  by  1  December  2025,  and  should  take  into  account 
development of common energy and market model. They should be updated at least every 5 years 
and duly consider the hydrogen sector. Progressively integrated model should be submitted by 
31  October  2025  and  should  cover  interlinkages  at  all  stages  of  infrastructure  planning, 
specifically scenarios, technologies and spatial  resolution,  infrastructure gaps identification in 
particular with respect to cross-border capacities, and projects assessment. 

Regional level planning (electricity)  

Article  34  of  the  Electricity  Regulation  (2019/943)  requires  establishing  regional  cooperation 
under the ENTSO-E and to publish biannual regional investment plans. TSOs may consequently 
take investment decisions based on the regional plan (i.e., there is no obligation to follow these). 
Pursuant  to  the  TEN-E  Regulation,  PCIs  need  to  become  an  integral  part  of  the  regional 
investment  plan.  In  2020  and  2022  editions  of  the  TYNDP,  these  investment  plans  were 
published together with the main TYNDP. For the 2024 edition, they were published separately.   

National level – transmission infrastructure (electricity)  

97 

 
 
 
 
 
Requirements for transmission network development plans (TNDP) are provided under Article 
51 of the Electricity Directive. Based on its provisions, TSOs should submit TNDP at least every 
two  years  and  publish  it  on  their  website.  It  should  fully  consider  potential  use  of  demand 
response, energy storage facilities or other resources as alternatives to system expansion, indicate 
development of main transmission infrastructure over the next ten years and detail investments 
to be done for the next three years. PCIs180 shall become integral part of the TNDP pursuant to 
the TEN-E Regulation.  

National regulatory authorities are tasked to consult all relevant or potential system users on the 
TNDP  and  are  also  responsible  for  checking  the  consistency  with  the  union-wide  TYNDP. 
Moreover,  competent  national  authorities  should  also  check  the  consistency  with  NECP 
submitted  in  accordance  with  Regulation  (EU)  2018/1999.  If  the  investments  planned  for  the 
next three years are not executed, the Electricity Directive gives the NRA right to require the 
execution of investment by the TSO or to organise a tendering procedure in this regard. NRAs 
are also required to monitor the implementation of the TNDP, however no specific deadlines or 
frequency is currently given by the legislation framework.  

National level – distribution grid (electricity) – planning, as well as incentives for smart grids 
and efficient allocation of grid capacity  

For the distribution grid level, the Article 32 of the Electricity Directive requests at least biennial 
publication  of  the  distribution  network  development  plan  (DNDP).  Plans  should  provide  an 
outlook of grid development in the next 5 to 10 years, counting in flexibility needs, use of demand 
response,  energy  efficiency,  energy  storage  facilities  or  other  resources  that  the  distribution 
system operator is to use as an alternative to system expansion. DNDPs should be duly consulted, 
including with the TSO, and submitted to the NRA. The NRA may request amendments to the 
plan. Currently, there is no monitoring role foreseen for the NRA. There are also no provisions 
in case there is an inconsistency of the DNDP with the TNDP, on scenarios or assumptions used.  

There is a possibility to exempt DSOs with less than 100,000 customers from the planning, if 
regulated on a national level. Pursuant to ACER findings9, two thirds of the DSOs in the EU are 
exempted from the preparation of the DNDP. Exempted DSOs serve between 0.7 % of customers 
in Latvia and around 25 % of customers in Germany. This still results in some 963 DNDPs in 
Europe,  which  are  to  be  published  on  respective  DSOs  websites  pursuant  to  the  Electricity 
Directive.  

When it comes to efficient grid utilisation, the Electricity Market Regulation specifies incentives 
for DSOs and TSOs in Article 18, which includes incentivising anticipatory investment, as well 
as entails that the tariff methodologies should facilitate digitalisation and solutions to optimise 
the existing grid, as well as and other measures fostering energy efficiency and integration of 
renewable energy sources. 

Further requirements on grid access, grid connections and grid hosting capacities transparency, 
as well as use of flexibility in grid operation and planning are specified in Article 6, 6a and 32 of 
the  Electricity  Market  Directive,  and  Article  50  and  57  of  the  Electricity  Market  Regulation 
(which also include notion of coordination between DSOs and TSOs). 

Article  6  of  the  Electricity  Market  Directive  stipulates  that  access  to  grids  shall  be  applied 
objectively  and without discrimination  between system  users. It  allows the option of refusing 

180 This does not apply to competing projects or projects that have not reached a sufficient degree of maturity. 

98 

 
 
 
access  if  the  grid  lacks  the  necessary  capacity  and  based  on  objective  and  technically  and 
economically justified criteria. Article 6 hence provides flexibility for Member States to adjust 
connection  procedures  based  on  specificities  of  their  respective  systems.  Article  6a  further 
requires Member States or NRAs to set up flexible connection agreements in areas where there 
is  a  lack  of  grid  capacity.  Article  31  of  Electricity  Directive  stipulates  transparency  on  grid 
hosting capacities and treatment of grid connections by grid operators, including on the rejected 
ones. Specifically for grid connection requests, it requires DSOs to provide an option of fully 
digital connection procedure. Provisions under Articles 6a and 31 were included in the Electricity 
Market Directive by 2024 reform, to tackle rising grid connection queues. 

Article  32  of  the  Electricity  Market  Directive  mentions  that  DSOs  should  consider,  when 
planning their networks, alternatives to system expansion. Article 59 tasks NRAs to monitor and 
assess the performance of system operators when it comes to the development of a smart grid, 
which promotes energy efficiency and integration of energy from renewable sources. These two 
Articles together with Recital 51 explain that smart and digital solutions should be considered as 
a way to modernise distribution networks.  

Currently,  there  is  also  ongoing  work  on  the  network  code  on  demand  response,  which  was 
submitted by ACER to the Commission on 7 March 2025. Draft provisions target coordination 
between TSO-DSO and DSOs, entail clarifications on methodology for planning and scenarios 
and  on  link  to  flexibility  needs  assessment,  use  of  local  services  as  alternatives  to  grid 
development,  monitoring  of  DNDPs,  more  transparency  on  public  consultation  as  well  as  on 
publication of DNDPs. Comitology on the network code is planned for Q1 2026.  

National level – integrated network planning for natural gas and hydrogen, transmission and 
distribution 

For  the  gases  sector,  the  new  Gas  Directive  introduced  obligations  for  integrated  network 
planning under Chapter VIII, Articles 55-57. Similarly, as in electricity, there is a requirement to 
publish biennial TNDPs for natural gas and hydrogen, either jointly or separately. In either case, 
modelling should be done separately for each energy carrier. However, this is complemented by 
a  requirement  to  have  a  joint  scenario  developed  every  two  years  between  the  relevant 
infrastructure operators, including relevant DSOs, of at least natural gas, hydrogen, electricity 
and,  where  applicable,  district  heating.  Such  scenarios  shall  take  into  account  demand-side 
solutions  not  requiring  new  infrastructure  investments.  System  operators  should  conduct  an 
extensive consultation process on scenario development at an early stage of the process. 

The  Gas  Directive  introduced  first  requirements  on  cooperation  and  coordination  between 
hydrogen, gas and electricity transmission and distribution system operators, for instance in view 
of location of electrolyser facilities. Pursuant to Article 55, Member States shall endeavour to 
ensure  coordinated  planning  steps  of  the  respective  ten-year  network  development  plans  for 
natural gas, hydrogen and electricity.  The Directive does not prescribe precise procedures for 
such coordination mechanisms though, or coordination on scenarios development. 

TNDPs  for  gases  and  hydrogen  should  cover  the  period  of  upcoming  10  years,  contain 
information  on  concrete  investments  to  be  executed  in  next  three  years,  information  on 
decommissioning of infrastructure, and be consistent with the EU-wide TYNDP for natural gas 
and hydrogen, as well as in line with the NECPs. TNDPs should take into account potential for 
alternatives  to  system  expansion  such  as  demand  response  and  follow  energy  efficiency  first 
principle. The whole TNDP should be consulted and submitted to the NRA, who has a right to 
request amendments to the plan, as well as obligation to monitor and evaluate implementation. 

99 

 
 
Mirroring  requirements  of  the  electricity  directive,  NRA  has  a  right  to  delegate  execution  of 
investment in case investment plan was not duly followed. 

On a distribution level, hydrogen distribution network development  plan should be submitted 
every  four  years  and  shall  be  developed  in  close  cooperation  with  DSOs  for  natural  gas  and 
electricity, as well as district heating and cooling operators where applicable, ensuring effective 
energy system integration. There is a possibility to develop a joint plan of hydrogen and natural 
gas networks, including decommissioning. Distribution network decommissioning plans should 
be based on heating and cooling plans based on Article 25(6) of Directive (EU) 2023/1791. Both 
plans need to be duly consulted, in line with the Union-wide TYNDP and TNDPs, as well as 
NECPs. NRAs approve the DNDPs and have right to request amendments to the plans. 

Table 10: summary of roles and requirements  

Level of planning  

Union-wide TYNDP  

Actors and Roles  

ENTSOs (biennial cycle)  

•  Developing scenarios  
•  Developing Infrastructure gaps report  
•  Developing  TYNDP,  based  on  the  CBA 

methodology  
European Commission  

•  Approval  of  scenarios  for  the  TYNDP 

(biennial)  

•  Approval of the CBA methodology s for 
the TYNDP (before the start of the cycle)  
•  Non-binding opinion on the Infrastructure 

gaps identification  

  ACER  

•  Non-binding opinion on the scenarios  
•  Non-binding  opinion  on 

the  CBA 

methodology  

•  Non-binding opinion on the Infrastructure 

gaps identification  

•  Non-binding opinion on the TYNDP  
•  Report  on  consistency  of  TNDP  and 

Union-wide TYNDP  

Regional investment plans - electricity  

TSOs  

TNDP - electricity  

•  Publishing  regional 

investment  plans 

bienially  

TSOs  

•  Submit TNDP at least bienially  

NRAs  

•  Consult all relevant and potential system 

users  

•  Right to request amendments to the plan  
•  Check  consistency  with  NECPs  and 

Union-wide TYNDP  

•  Monitoring  of  implementation  of  TNDP 

(without deadlines)  

•  Right to request investments / organise a 

tender if investment fails  

DNDP - electricity  

DSOs  

100 

 
 
•  At 

least  biennial  publication 

and 

submission of the DNDP  

•  Obligation  to  consult  all  relevant  and 

potential system users  

• 
NRAs  

•  Right to request amendments to the plan  

B)  Hydrogen blending 

The TEN-E Regulation of 2022 introduced a new infrastructure category, namely smart gas grids, 
the  aim  of  which  is  to  support  investments  which  integrate  a  plurality  of  low-carbon  and 
particularly renewable gases such as biogas, biomethane, and hydrogen, in the gas network and 
help manage a resulting more complex system, building on innovative digital technologies.  

The category covers digital systems and components integrating ICT, control systems and sensor 
technologies to enable the interactive and intelligent monitoring, metering, quality control and 
management of gas production, transmission, distribution, storage and consumption within a gas 
network. Furthermore, such projects may also include equipment to enable reverse flows from 
the distribution to the transmission level, including the related physical upgrades if indispensable 
to  the  functioning  of  the  equipment  and  installations  for  integration  of  low-carbon  and 
particularly  renewable  gases.  The  focus  is  digitalisation  to  avoid  investments  that  aim  at  the 
maintenance, upgrade or development of the gas network, for which support was discontinued 
under the 2022 TEN-E Regulation.  

At  the  same  time,  the  TEN-E  Regulation  took  a  prudent  approach  to  hydrogen  blending, 
providing in its Article 31 that hydrogen assets converted from natural gas assets falling under 
the energy infrastructure category set out in point (3) of Annex II may be used for transport or 
storage  of  a  predefined  blend  of  hydrogen  with  natural  gas  or  biomethane  only  during  a 
transitional period ending on 31 December 2029 and subject to the project promoter providing 
sufficient evidence, including through commercial contracts, how, by the end of the transitional 
period, the assets will cease to be natural gas assets and become dedicated hydrogen assets and 
how the increased use of hydrogen will be enabled during the transitional period, This Article 
does  not  refer  to  the  smart  gas  grid  category,  for  which  no  explicit  transitional  period  is 
established. 

After the entry into force of the TEN-E Regulation, the approach of the EU legislative framework 
to hydrogen blending has become more restrictive: the Gas Regulation of 2024 explains explicitly 
that the “blending of hydrogen into the natural gas system should be a last-resort solution, as it 
is  less  efficient  compared  to  using  hydrogen  in  its  pure  form  and  diminishes  the  value  of 
hydrogen. It also affects the operation of natural gas infrastructure, end-user applications and the 
interoperability of cross-border systems. The production and use of hydrogen in its pure form 
and its transportation in the dedicated hydrogen system should therefore be prioritised” (Recital 
74).  

Accordingly, Article 21 of the Gas Regulation established a cross-border cooperation mechanism 
to address differences in gas quality liable to restrict cross-border flows differences. However, 
that mechanism only applies to hydrogen blends where the hydrogen content blended into the 
natural gas system is below 2% by volume. Transmission System Operators may reject cross-
border flows of natural gas with a blended hydrogen exceeding 2%.  

101 

 
 
   
 
C)  Permitting frameworks  

Renewable energy and co-located storage projects 

The  main  vehicle  is  Directive  (EU/2018/2001)  on  the  promotion  of  the  use  of  energy  from 
renewable sources (RED). The Directive was amended by Directive (EU/2023/2413) i.a. with a 
view of setting comprehensive rules on permitting, by means of introducing Articles 15b to 16f. 
The transposition deadline for Member States to adopt Articles 16 and Articles 16b-16f was set 
for  July  2024.  The  remainder  of  the  provisions  –  mainly  referring  to  setting  the  Renewable 
Acceleration Areas – were mainly due to be transposed by May 2025. 

The importance of permitting for RES and the barriers it faces were already identified in Directive 
2001/77/EC181 of the European Parliament and of the Council, which required Member States to 
evaluate  the  permit-granting  procedures  in  order  to  reduce  the  regulatory  and  non-regulatory 
barriers  to  the  production  of  renewable  electricity.  Directive  2009/28/EC  182of  the  European 
Parliament and of the Council introduced requirements to simplify the administrative procedures 
for  renewable  energy  developers,  whereas  the  Directive  (EU)  2018/2001  of  the  European 
Parliament  and  of  the  Council  strengthened  these  requirements  and  introduces  a  permitting 
deadline for the first time. (transposition by June 2021) 

The  Directive  (EU/2023/2413)  was  the  first  to  introduce  an  integrated  permitting  procedure, 
including environmental assessments, with specific rules  simplifying processes and technology 
specific deadlines. However, it is important to note that the revised RED was predated by Council 
Regulation  (EU/2022/2577)  which  set  down  a  framework  to  accelerate  the  deployment  of 
renewable energy and grids, which entered into force in December 2022 due to the energy crisis 
(2022-2023). Its provisions were applicable for 18 months from this date. Application of its certain 
provisions, alongside minor amendments and additions, was extended until June 2025 by Council 
Regulation (EU/2024/223). As from July 2025, this Regulation ceased to apply in its entirety. 

Both  Directive  2018/2001  amended  by  Directive  2023/2413  (the  revised  RED)  and  Council 
Regulation  2022/2577  amended  by  Council  Regulation  2024/223  (the  Emergency  Regulation) 
were  introduced  to  accelerate  the  permit-granting  procedure  to  build,  repower  and  operate 
Renewable  Energy  Sources’  plants,  their  related  infrastructure  and  co-located  storage  .  Their 
scopes, albeit overlapping to substantial extent, are not identical. 

The  provisions  of  the  revised  RED  with  July  2024  transposition  deadline  constitute  the  first 
structured permanent EU legal baseline for the permit-granting procedure to build, repower and 
operate Renewable Energy Sources’ plants, their related infrastructure and co-located storage. The 
scope of each of the Article is the following: 

➢  Article 16: Organisation and main principles of the permit-granting procedure 

•  Criteria for permitting process duration and validity of applications, incl. deadlines. 

181 Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on the promotion of 
electricity produced from renewable energy sources in the internal electricity market; OJ L 283, 27.10.2001, pp. 33–
40 
182 Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on the promotion of the use 
of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC 
(Text with EEA relevance), OJ L 140, 5.6.2009, pp. 16–62 

102 

 
 
 
 
•  Streamlining of administrative processes. 
•  Designation of single contact points (OSS) and its obligations towards stakeholders. 
•  Provision of adequate resources to competent authorities and reskilling of staff. 
•  Public availability of decisions. 
•  Digitalisation of permit-granting procedures (by 21 November 2025). 
➢  Article 16b: Permit-granting outside Renewable Acceleration Areas (“RAAs”) 

•  Permitting timelines: <2 years, <3 years for offshore, <1 year for repowering, <2 years for 

offshore repowering. 

•  All relevant environmental assessments for a renewables project to be rolled into one single 

procedure. 

•  The killing or disturbance of species protected under the Birds & Habitats Directives will 
not  be  considered  ‘deliberate’  where  a  project  has  followed  all  necessary  mitigation 
measures. 

➢  Article 16c: Permit-granting for repowering 

•  Permitting timelines: <3 months for grid connections. 
•  Screening limited to extension of existing projects. 
•  Exemptions available for solar installations from screening and environmental assessments 

when no extra space is required. 

➢  Article 16d: Permit-granting for solar installations on artificial structures 

•  Permitting timelines: <3 months for solar equipment on artificial surfaces and co-located 
storage with possibility for applying exemptions, and <1 month for solar equipment with 
capacity of 100 kW or less. 

•  Positive silence for solar equipment with capacity of 100 kW or less. 
•  Exemptions available from screening and environmental assessments. 

➢  Article 16e: Permit-granting procedure for heat pumps 

•  Permitting timelines: <1 month above 50 MW, <3 months for ground source heat pumps, 

<2 weeks for connections to the grid for lower capacity MW/self-consumers). 

➢  Article 16f: Presumption of overriding public interest (OPI) 

Permitting, planning, construction and operation of RES plants, their related infrastructure and 
storage assets must be presumed to  be in  the OPI  for  the purpose of the  application of certain 
exemptions regulated in certain environmental directives.   

As already mentioned, the scope of the Emergency Regulation was to wide extent similar, with 
two main measures going beyond what has been laid down in the Revised RED: 

➢  Article 3(2): Priority to be given to renewable energy plants and the related grid infrastructure, 
when balancing legal interests in the individual case, at least for projects which are recognised 
as being of OPI  

➢  Article 3a: Binding guidance on the assessment of alternatives to the projects and possibility 

to advance with projects in parallel to introducing compensatory measures. 

Hydrogen projects 

The baseline for permitting of hydrogen infrastructure permitting, the main baseline has been 
established in Article 8 of the Gases Directive, but where assets fall under the scope of Article 15 
and Articles 15b to 17 of the revised RED that regime shall apply.  

103 

 
 
 
 
•  Article  8(5)  of  the  Gases  Directive  establishes  a  2-year  maximum  duration  for 
authorisation  procedures183  for  the  construction  or  operation  of  hydrogen  production 
facilities  and  hydrogen  infrastructure,  including  pipelines  or  associated  equipment. 
However, this does not include the time required for Environmental Impact Assessments 
required under Directive 2011/92/EU.   

•  Article  8(8)  of  the  Gases  Directive  requires  Member  States  to  establish  one  or  more 
contact  points  that  shall,  upon  request  from  an  applicant,  facilitate  and  guide  the 
applicants  through  the  authorisation  procedure,  until  a  decision  is  rendered  by  the 
responsible  authorities.  This  authority  shall  act  as  a  single  point  of  contact,  with  the 
applicant not being required to contact other contact points for the entire process.  

•  Article 8(9) of the Gases Directive, requires Member States to ensure that authorisations 
for  the  construction  and  operation  of  natural  gas  system  infrastructure  also  apply  to 
hydrogen  system  infrastructure,  to  the  extent  they  comply  with  technical  safety  rules. 
Further,  Article  8(10)  provides  that  Member  States  shall  ensure  that  existing  land-use 
rights for the construction and operation of natural gas pipelines and other network assets 
is also applied to pipelines and other network assets for the transport of hydrogen. 

Projects of common interest and projects of mutual interest 

Projects of common and mutual interest benefit from a dedicated permitting regime under chapter 
III of the TEN-E Regulation. This regime is flexible and leaves space for diverse implementation 
by Member States depending on the pre-existing organisation of the national systems  

•  Article  7  of  the  TEN-E  Regulation  requires  PCIs  and  PMIs  are  considered  as  being 
necessary from an energy and climate policy perspective and granted the status of the 
highest national significance in any decisions issued in the permitting granting process. 
In that sense project promoters and all authorities concerned are required to ensure that 
permitting files are treated in the most rapid way possible in administrative and judicial 
procedures. 

•  Article 8 of the TEN-E Regulation requires Member States to designate a single national 
competent  authority  responsible  for  facilitating  and  coordinating  the  permit  granting 
process for PCIs and PMIs in line with the competences and responsibilities afforded to 
them under the scheme selected by the Member State out of the options provided in the 
Regulation: 

o  Integrated Scheme – Comprehensive permitting decision is issued by the national 
competent authority and shall be the sole legally binding decision arising from the 
permit granting procedure. Other authorities concerned may, in accordance with 
national law, give their opinion as input to the procedure 

o  Coordinated Scheme – Comprehensive permitting decision comprised of multiple 
individuals  legally  binding  decisions  issued  by  several  authorities  concerned, 
which are coordinated by the national competent authority. National competent 
authority  may  take  decisions  on  behalf  of  other  authorities  concerned  if  it 
considers  that  has  either  not  decided  in  time  limit  or  it  considers  that  it  is  not 
sufficiently substantiated.  

o  Collaborative  scheme  –  Comprehensive  decision  comprised  of  multiple 
individual  legally  binding  decisions  issued  by  several  authorities  concerned. 

183 Be it a licence, permission, concession, consent or approval. 

104 

 
 
 
National competent authority coordinates the process, establishing time limit for 
individual decisions of concerned in line with the time limits set by TEN-E, and 
monitoring their conformity.  

•  Article 9 of the TEN-E Regulation establishes the baseline in terms of public participation 
during the permitting procedures, requiring early public consultation, before the project 
promoter  submits  the  final  and  complete  application  file  to  the  national  competent 
authority. It requires that a report summarising the results of public participation activities 
and  a  report  explaining  how  the  opinions  expressed  in  the  public  consultations  were 
considered, are submitted alongside the application file. 

•  Article 10 of the TEN-E Regulation establishes rules on the dedicated permit granting 

process and its duration, providing for: 

o  a  flexible  two  steps  approach,  characterised  by  a  pre-application  phase  and  a 
statutory permit granting phase, to be set in place for the permitting of PCIs and 
PMIs. 

o  A maximum duration of 42 months for the procedure, which may be extended by 
national  competent  authorities,  on  a  case-by-case  basis,  in  9  months  when  the 
procedure requires longer in exceptional circumstances. 

105 

 
 
 
 
ANNEX 7: IMPLEMENTATION REPORTS 

I. 

IMPLEMENTATION  REPORT  ON  THE  TRANS-EUROPEAN  NETWORKS  FOR  ENERGY 
REGULATION 

The  revised  Regulation  (EU/2022/869)  on  Trans-European  Networks  for  Energy  (TEN-E 
Regulation)184 entered into force in June 2022. This revision aimed to fully align the scope of the 
TEN-E Regulation with the European Green Deal, to make Europe a climate neutral continent 
by  2050.  Furthermore,  in  line  with  the  evolution  of  the  Union’s  infrastructure  needs  and  its 
decarbonisation goals, sustainability became one of the essential requirements employed across 
the selection of all priority infrastructure projects. The TEN-E Regulation lays down rules for the 
timely development and interoperability of trans-European energy networks in order to achieve 
the energy policy objectives of the Treaty on the Functioning of the European Union (TFEU) to 
ensure  the  functioning  of  the  internal  energy  market  and  security  of  supply  in  the  Union,  to 
promote energy efficiency and energy saving and the development of new and renewable forms 
of energy, and to promote the interconnection of energy networks.  

1. AIM OF THE REPORT AND RESEARCH METHOD 

The targeted amendment (revision) of the TEN-E Regulation under the European Grids Package, 
as announced by the Action Plan for Affordable Energy185, aims to keep the above stated general 
objectives of the TEN-E Regulation and ensure that greater efficiency is achieved when planning 
and deploying energy infrastructure (electricity and hydrogen). To this end, the package aims to 
strengthen certain elements linked to infrastructure categories and network planning, cost-benefit 
sharing,  permitting  processes  and  infrastructure  security  and  resilience.  Given  the  targeted 
character  of  this  revision  and  how  soon  it  takes  place  after  the  entry  into  force  of  the  TEN-E 
Regulation this “Implementation Report” focuses on the performance of the specific provisions 
introduced and revised as part of the 2022 TEN-E Regulation revision. The Implementation Report 
replaces  a  full  evaluation  which  would  only  be  expected  as  part  of  the  review  of  the  TEN-E 
Regulation due in 2027186. An evaluation was previously conducted between January 2019 and 
September 2020, in context of the 2022 TEN-E Regulation revision.187  

184 Regulation (EU) 2022/869 to the European Parliament and the Council of 30 May 2022 on guidelines for trans-
European energy infrastructure, amending Regulations (EC) No 715/2009, (EU) 2019/942 and (EU) 2019/943 and 
Directives 2009/73/EC and (EU) 2019/944, and repealing Regulation (EU) No 347/2013; OJ L 152, 3.6.2022, p. 45) 
June 2022. Available here: Regulation - 2022/869 - EN - EUR-Lex 
185  Communication  from  the  Commission  to  the  European  Parliament,  the  Council,  the  European  Economic  And 
Social Committee and the Committee of the Regions: Action Plan for Affordable Energy: Unlocking the true value 
of our Energy Union to secure affordable, efficient and clean energy for all Europeans. COM/2025/79 final 
186 See Article 22 of the TEN-E Regulation. 
187 European Commission: Directorate-General for Energy, ECORYS, Ramboll, REKK, Shepherd and Wedderburn, 
Akkermans, F., Le Den, X., Heidecke, L., Jansen, L., Juárez, V., Kácsor, E., Mezősi, A., Nigohosyan, D., Nguyen, 
N., Rodger, S., Selei, A., Takácsné Tóth, B., Møller Thomsen, S., Til, H. v.Yagafarova, A., Support to the evaluation 
of Regulation (EU) No 347/2013 on guidelines for trans-European energy infrastructure – Final report, Publications 
Office, 2021, https://data.europa.eu/doi/10.2833/154438 

106 

 
 
 
 
 
The  report,  to  the  extent  possible,  addresses  the  effectiveness,  efficiency  and  coherence  of  the 
TEN-E framework as in force since 2022, as well as its EU added value and relevance. The report 
provides an overview of the main outputs linked to the implementation of the new framework per 
topic. Specifically, it assesses the extent to which these elements achieved the stated objectives of 
the framework, including their contribution to the European Green Deal and to reaching climate 
neutrality by 2050.  

A  desk-based  legal  and  policy  analysis  has  been  conducted  for  the  preparation  of  this 
Implementation  Report.  The  Commission  carried  out  this  analysis  using  different  information 
channels. In addition to the relevant legislative documents, the primary source of information was 
the  Commission’s  experience  in  the  implementation  of  the  TEN-E  Regulation,  including  the 
assessment process for the selection of projects of common interest (PCI) and projects of mutual 
interest (PMI), as  well as the assessment  and inclusion of energy infrastructure projects  in the 
relevant Ten-Year Network Development Plan (TYNDP). It also considers Member States’ and 
stakeholders experiences of implementing the provisions related to permitting introduced by the 
TEN-E Regulation, collected through a dedicated study as well as information collected in a draft 
interim report for the support study for the assessment of the framework on European Grids. 

2.  ANALYSIS  

Update and Introduction of New Infrastructure Categories 

The 2022 revision of the TEN-E Regulation introduced a number of important policy changes, 
primarily reflected in the introduction of I) new and updated energy infrastructure categories 
and II) a reconfiguration of priority corridors and areas. Projects with third countries, or PMIs, 
were included in the scope of the TEN-E Regulation. The eligibility for the status of PCI and PMI 
was  brought  in  line  with  the  European  Green  Deal.  The  2022  TEN-E  Regulation  revision 
presented a paradigm shift away from fossil fuels, with natural gas infrastructure and oil pipelines 
removed  as  infrastructure  categories  eligible  for  priority  status.  New  categories  including 
hydrogen infrastructure, electrolysers and smart gas grids were added to the scope of the TEN-E 
Regulation, as per revised Article 4(3) and Annex II. 

The  2022  revision  also  saw  an  update  of  the  existing  categories.  The  electricity  infrastructure 
category  was  extended  to  offshore  projects,  both  hybrids  and  radials.  The  carbon  dioxide 
infrastructure category was expanded to allow for surface and injection facilities associated with 
permanent storage. The scope of the smart electricity grids infrastructure category was expanded 
(and criteria streamlined) to encourage development of more projects. Among the more substantial 
changes, its scope was expanded to investments in islands and island systems aimed to decrease 
their energy isolation, as well as to the projects which do not involve a physical common border. 
Moreover, it created further possibilities for grid operators to propose projects188.  

The  revised  TEN-E  Regulation  strengthened  sustainability,  in  terms  of  the  integration  of 
renewable energy sources into the energy networks and the reduction of greenhouse gas emissions, 
as an overarching specific criterion to be used in the selection of priority infrastructure projects in 

188 Under the TEN-E Regulation, this includes TSOs, TSOs and DSOs, or DSOs from at least two Member States 
under certain conditions. Under the previous Regulation (EU/347/2013), these needed to be TSOs and DSOs from at 
least two Member States. 

107 

 
 
 
 
 
all categories. This made the implementation of the sustainability criterion much stricter compared 
to the previous Regulation (EU/347/2013), where sustainability was not a mandatory criterion. 

The first list of PCIs and PMIs, fully in line with the European Green Deal, entered into force in 
April  2024.  This  was  also  the  first  list  in  which  all  the  selected  projects  were  required  to 
demonstrate  fulfilment  of  the  criteria  of  significant  contribution  to  sustainability.  Out  of  301 
candidate projects, 166 were selected as PCIs and PMIs. Over half (85) were electricity, offshore 
and smart electricity grid projects. For the first time, hydrogen and electrolyser projects (65) were 
included. The first PCI/PMI list also included 14 CO2 network projects, with the goal to create a 
market for carbon capture and storage. No smart gas grid projects were included on the list.  A 
call for application to project promoters to submit their projects was again opened in September 
2024, initiating the second PCI/PMI process under the revised Regulation. In total, 340 candidate 
projects  were  submitted.  Following  the  meeting  in  June  2025  of  the  decision-making  body 
composed  of  Member  States  representatives  at  technical  level,  in  July  2025,  a  draft  second 
PCI/PMI list was sent to Agency for the Cooperation of Energy Regulators (ACER) for its opinion. 
In line with the TEN-E Regulation, the adoption of the final list is planned for November 2025. 
Additional  information  pertaining  to  the  number  of  candidate  and  selected  projects,  per 
infrastructure category is presented in dedicated sections from 1.1 – 1.3. 

Table 11: Number of selected projects per infrastructure category on the Union lists  

Infrastructure 
category 

Fifth PCI list 

First PCI/PMI list 

Per  repealed  Regulation 
(EU) 347/2013 

Per TEN-E Regulation 

Draft 
PCI/PMI list 

Second 

Electricity 

67 

Smart electricity 
grid 

6 

Gas 

Hydrogen 

Electrolysers 

Smart gas grids 

Oil 

Carbon dioxide 

20 

/ 

/ 

/ 

0 

6 

80 
12 
(including 
energy storage and 12 
offshore projects) 

94 
22 
(including 
energy storage and 19 
offshore projects) 

5 

/ 

6 

/ 

(including 
48 
reception 
and 
storage facilities) 

10 
7 

(including 
85 
reception 
and 
storage facilities) 

9 
19 

17 

0 

/ 

14 

25 

3 

/ 

17 

Note:  Number  of  projects  was  influenced  by  the  changes  and  updates  to  infrastructure  categories  in  the  TEN-E 
Regulation, as well as the introduction of PMIs in addition to PCIs.  
Source: European Commission 

108 

 
 
The TEN-E Regulation identifies energy infrastructure priorities, based on strategic geographical 
priority corridors (11) and Union-wide priority areas (3). These were reconfigured as part of the 
2022 TEN-E Regulation revision and are further discussed in section 5.  

2.2 Electricity and Smart Electricity Grids Infrastructure Categories 

In  the  first  PCI/PMI  list  which  entered  into  force  in  April  2024,  80  electricity189  and  5  smart 
electricity  grids  projects  were  selected  as  PCI/PMIs,  following  93  and  6  project  candidate 
applications,  respectively.  The  number  of  candidate  projects  in  the  second  PCI/PMI  process 
remained the same for smart electricity grids (6), while for electricity grids it increased to 114. 
Electricity grid candidate projects  included 46 interconnection projects,  14 internal  lines190, 30 
electricity storage and 24 offshore projects.  

The number of projects included in the second draft PCI/PMI list is 94 for electricity and 6 for 
smart  electricity  grids.  The  offshore  electricity  infrastructure  related  provisions  and  their 
implementation is discussed in the dedicated chapter 4. 

2.3 Hydrogen, Electrolyser and Smart Gas Grid Infrastructure Categories 

In the first PCI/PMI list which entered into force in April 2024, 65 hydrogen and electrolyser PCI 
and  PMI  projects  were  selected,  following  180  project  candidate  applications.  The  number  of 
candidate projects increased to 199 in the second PCI/PMI process launched in September 2024. 
The  number  of  projects  included  in  the  draft  second  PCI/PMI  list  is  105.  The  distribution  of 
projects per hydrogen infrastructure category or electrolyser is presented in Figure 11.  

In  the  first  and  second  PCI/PMI  processes,  19  out  of  25  and  25  out  of  68  submitted  projects, 
respectively,  had  a  capacity  of  more  than  500  MW,  reflecting  a  trend  toward  larger-scale 
developments. However, the majority of these —43 out of 68 in the second round— were focused 
on serving local demand without a cross-border dimension. 

189 The infrastructure category includes offshore electricity projects, which covered in a dedicated section. 
190 Internal lines account for 23% of candidate electricity projects (when excluding offshore and storage electricity 
projects). 

109 

 
 
 
 
 
Figure  11:  Distribution  of  projects,  per  Hydrogen  infrastructure  and  Electrolyser 
categories, as included in the draft191 second PCI/PMI list based on infrastructure type 

Storage; 19

Electrolyser; 25

Reception facility; 9

Pipeline; 52

Electrolyser

Pipeline

Reception facility

Storage

Source: European Commission 

Smart  gas  grids  was  introduced  as  a  new  infrastructure  category  in  the  revision  of  the  TEN-E 
Regulation, with the intention to support investments smartening the gas grids so as to allow the 
integration  of  a  plurality  of  low-carbon  and  particularly  renewable  gases  such  as  biogas, 
biomethane, and hydrogen, in the gas network and help manage a resulting more complex system, 
building on innovative digital technologies. However, PCI applications were very limited. In the 
first PCI/PMI selection process, only 4 candidate projects applied, but none were able to meet the 
eligibility conditions defined in the TEN-E Regulation. In the second PCI/PMI selection process, 
3 projects applied. They were all found eligible, but a with a reduced number of investments than 
those proposed due to eligibility requirements. All three projects were included on the draft second 
PCI/PMI list that was sent to ACER.  

2.4 The Carbon Dioxide Infrastructure Category 

The revised TEN-E Regulation broadened the scope of projects for which project promoters can 
apply  to  receive  the  PCI  and  PMI  status.  As  previously  explained,  the  change  related  to 
introduction of surface and injection facilities associated with permanent storage. 

The first PCI/PMI list included 14 carbon capture and storage infrastructure projects, following 
18 applications, while the second draft PCI/PMI list includes 17 projects after 19 applications. All 
the  projects  included  in  the  draft  second  PCI/PMI  list,  aimed  at  carbon  dioxide  storage  (14), 
included also surface and injection facilities. 

Effectiveness:  

191  The  exact  list  of  infrastructure  projects  and  project  data  is  conditional  to  the  validation  of  the  second  Union 
PCI/PMI list. The statistics provided do not pre-empt the outcomes of the High-Level Decision-making Body meeting, 
nor the outcomes of the co-legislators’ scrutiny of the delegated act defining the second Union PCI/PMI list. 

110 

 
 
 
 
 
Across the first and the second PCI/PMI selection process, there has been an increasing number 
of candidate and selected infrastructure projects. This trend was observed across most of the 
categories,  including  electricity,  hydrogen,  electrolysers  and  carbon  dioxide  infrastructure. 
Comparatively a lower number of candidate applications was received for the smart electricity 
grid category. The smart gas grid category has seen very few applications and has encountered 
significant issues as regards eligibility either of the applications in their entirety or of the assets 
included in the proposals. Still, taken together, these trends suggests that the TEN-E Regulation 
offers  an  attractive  tool to  identify  and  accelerate  energy  infrastructure  projects  with  cross-
border relevance.  

In the electricity infrastructure category, internal lines represented 23 % of the total number of 
candidate  projects  (excluding  offshore  and  storage  projects).  Given  the  fact  that  internal 
electricity lines are crucial for fully enabling cross-border flows, this raises some doubts on the 
effectiveness of the set threshold for cross-border impact (at 500 MW) for achieving the goals 
of the TEN-E Regulation, concretely to ensure market integration.  

In  the  smart  electricity  grids  infrastructure  category,  the  majority  of  the  projects  concerned 
distribution networks, displaying certain limitation in the current design of the categories, as 
smart grid projects are also needed at the level of transmission networks. 

Efficiency:  

The design of the electricity infrastructure categories, as well as the smart grids category are 
mostly  fit  for  purpose,  allowing  for  efficient  assessment,  as  demonstrated  by  high  rates  of 
eligibility among these projects. 

With regard to the electrolyser infrastructure category, there has been a significant increase in 
candidate projects from first to the second PCI/PMI process (from 25 to 68). However,  most 
electrolyser  projects  applying  in  the  second  PCI/PMI  process  were  aimed  to  serve  local 
demand. 

The number of applications for the smart gas grids infrastructure category remains very low.  
While  the  eligibility  rate  improved,  issues  arose  regarding  the  scope  of  some  of  the  assets 
included  for  the  candidate  projects.  Whilst  the  category  is  aimed  at  investment  in  digital 
equipment and digital installations with a view to smartening the natural gas network for the 
purpose  of  enabling  the  integration  of  renewable  and  low-carbon  gases,  candidate  projects 
included upgrades of the natural gas network. 
Coherence: 

The outcomes of the first and ongoing second PCI/PMI selection processes have proven to be 
mostly coherent with the objectives of the European Green Deal. Selected priority infrastructure 
projects comply with the sustainability requirement. 

Two out of the three smart gas grid projects which applied under the second PCI/PMI selection 
process were aimed at facilitating certain levels of hydrogen blending. This raised consistency 
issues with the latest EU policy developments and as regards their interaction with Article 31 
of  the  TEN-E  Regulation  (limited  exemption  concerning  blending  projects)  and  the  risk  or 
circumventing the conditions for allowing blending projects set in this Article. 

111 

 
 
 
 
 
 
 
 
3.  Energy Infrastructure Financing Under the Connecting Europe Facility for Energy   

Projects selected as PCIs and PMIs can automatically benefit from many advantages stemming 
from the TEN-E Regulation, including an accelerated permit granting and improved  regulatory 
treatment. Projects on the list are eligible, under certain conditions, to apply for financial support 
for  construction  works  and  studies,  under  the  Connecting  Europe  Facility  Energy  (CEF-E) 
programme, which was established in 2013 and continued under the current multiannual financial 
framework (2021-2027). CEF-E has a grant budget of EUR 5.84 billion for the period 2021-2027. 
The scope of eligible infrastructure financing under CEF was directly influenced by the updated 
and new infrastructure categories under the TEN-E Regulation. In addition, Article 18(2) of the 
revised TEN-E Regulation which determines the scope of infrastructure eligible to receive grants 
for  works,  was  expanded  to  cover  also  hydro-pumped  energy  storage  (under  the  electricity 
infrastructure category).  

The first annual CEF-E call for PCI and PMI projects selected as part of the first PCI/PMI list 
under the revised TEN-E Regulation was launched in April 2024. It resulted in awarding EUR 
1.25 billion in grants to 41 cross-border energy infrastructure projects in January 2025192. This is 
the largest amount awarded by any single CEF-E call to date. Overall, the funding was allocated 
for 5 works proposals (EUR 865 million) and for 36 studies (EUR 385 million). In April 2025, a 
new call for proposals for PCI and PMI projects under CEF-E was launched, with a budget of 
EUR 600 million.  

4. Projects of Mutual Interest 

The revised TEN-E Regulation introduced the PMI category for projects involving Member States 
and third countries. Among the 166 projects included in the first PCI/PMI list, 12 projects were 
PMIs (8 for electricity, 2 for hydrogen and 2 for carbon dioxide infrastructures). No PMIs were 
awarded grants funding following the 2024 CEF-E call. 

 The  draft  second  PCI/PMI  list  included  25  projects,  with  the  large  majority  being  electricity 
infrastructure projects (16), as seen in Figure 12. 

192 Additional information, including the list of beneficiaries is available online: EU invests over €1.2 billion in cross-
border infrastructure 

112 

 
 
 
 
 
 
Figure 12: Distribution of PMIs in the draft second PCI/PMI list, per infrastructure category 

Carbon dioxyde 
infrastructure; 5

Hydrogen; 4

Electricity; 16

Carbon dioxyde infrastructure

Hydrogen

Electricity

Source: European Commission 

In  addition  to  their  contribution  to  achieving  sustainability  and  climate  neutrality,  PMIs  are 
required to comply with a number of criteria as laid out in Article 4(2) of the TEN-E Regulation. 
Notably,  PMIs  should  demonstrate  significant  benefits  at  Union  level,  outweighing  their  cost 
within  the  Union.  Between  the  first  and  second  PCI/PMI  selection  process,  the  number  of 
candidate PMI projects increased from 42 to 46. Among the 25 electricity projects which applied 
for the PMI status, in the second PCI/PMI selection process, most candidate projects submitted 
were  with  the  UK  (9),  the  Energy  Community  Contracting  Parties  (8)  and  Northern  African 
countries  (6)  as  seen  in  Figure  13.  Most  hydrogen  PMI  applications,  were  with  the  Energy 
Community Contracting Parties (7), followed by North African countries and the UK (2 each), as 
seen in Figure 14. Regarding carbon dioxide infrastructures, five projects applied for a PMI status 
in  the  second  PCI/PMI  process,  a  majority  of  which  involved  Norway  (3),  while  one  project 
involved Switzerland and one project the UK. 

Figure 13: Distribution of electricity PMI candidate projects for the second Union list, per 
region 

Norway; 1

North Africa; 6

Energy Community 
Contracting Parties ; 
8

Israel; 1

UK ; 9

North Africa

UK

Israel

Energy Community Contracting Parties

Norway

113 

 
 
 
 
Source: European Commission 

Figure 14: Distribution of hydrogen and electrolyser, PMI candidate projects for the second 
Union list, per region 

Switzerland, 1

UK, 2

North 
Africa, 2

Energy Community 
Contracting Parties, 7

Energy Community Contracting Parties

North Africa

UK

Switzerland

Source: European Commission 

Figure  15:  Evolution  of  the  number  of  PMI  projects,  per  infrastructure  category 

19

16

5

8

2

2

25

12

5

16

5

4

First list PMI candidates

First list selected PMIs

Second list PMI candidates

Second list PMI selected

The categories of smart electricity grids and smart gas grids are not available for PMI status.  
Source: European Commission 

Note:  

Electricity

Hydrogen

CO2

Effectiveness: Increasing the number of candidate PMIs shows that the introduction of this 
category  of  projects  is  in  line  with  the  growing  interest  in  infrastructure  projects  with 
neighbouring countries, and brings environmental and market benefits for the EU.  

Efficiency:  The  high  number  of  ineligible  electricity  and,  particularly,  hydrogen  PMI 
candidates  indicates  that  the  proposed  provisions  are  not  fully  efficient  in  setting  a  clear 
framework  for  PMIs.  Concretely,  the  scope  of  the  PMI  category  would  deserve  further 
clarification  (some  ineligible  projects  related  to  insufficiently  clear  project  scope).  The 
criterion requiring demonstration of significant benefits at Union level proved to be efficient 

114 

 
 
 
 
in the project assessment, especially for projects under consideration. Projects with very low 
benefits for the Union have not passed the threshold for inclusion on the PCI/PMI list. Lastly, 
the  PMI  provisions  have  also  led  to  some  inefficiencies  in  the  selection  process  as  the 
assessment of PMI projects meeting the TEN-E Regulation objectives has proven to be resource 
intensive and burdensome for both project promoters and the Commission. 

Coherence:  The  inclusion  of  projects  with  third  countries  is  coherent  with  the  EU 
Neighbourhood Policy, and work in  energy cooperation  with third countries,  linked also  to 
their market liberalisation. Furthermore, it supports alignment with the EU policy framework 
especially  with  the  Energy  Community  Contracting  Parties,  and  countries  involved  in  the 
accession process. However, the criterion requiring demonstration of significant benefits at 
Union  level  for  PMIs,  has  led  to  non-inclusion of  several  projects  with Energy  Community 
Contracting  Parties.  Interconnections  with  the  Energy  Community  Contracting  Parties, 
despite low socio-economic benefits for the EU, are de facto directly impacting the electricity 
market of the Union (as well as EU’s security of supply) due to the inclusion of the Energy 
Community Contracting Parties in the Continental Europe Synchronous Area. Furthermore, 
practical implementation of the PMI category showed some limits in terms of coherence with 
climate and energy goals, as in some cases it was difficult to assess how projects contribute 
(or would not hinder) the possibility of a given country to phase-out fossil fuels, or how the 
country concretely ensured market convergence and contributed to climate targets. 

5. Offshore Renewable Energy  

The  revised  TEN-E  Regulation  introduced  new  provisions  to  support  the  upscale  of  offshore 
renewable energy in the EU. This includes five dedicated offshore priority corridors  around 
Europe’s sea-basins (Annex I), with the possibility for offshore projects, including hybrids and 
radials,  to  be  selected  as  PCI  or  PMI  under  the  electricity  infrastructure  category  (Annex  II). 
Furthermore, a specific chapter on offshore grids for renewable integration (Chapter 5) was 
included, with provisions to support the coordinated long-term offshore grid planning (Article 14) 
and related cross-border cost sharing (Article 15).  

5.1 Offshore Electricity Infrastructure Projects 

In  the  first  PCI/PMI  list,  out  of  80  projects  in  the  electricity  infrastructure  category,  12  were 
offshore  grid  projects,  including  9  radial  links  and  3  hybrid  projects.  Amongst  the  different 
offshore grid priority corridors, the Northern Seas offshore grids (NSOG) priority corridor had the 
highest number of selected projects (with 6 projects). For other corridors, 2 projects were selected 
each, except for the South and East offshore grids (SE offshore), which had no projects submitted. 
Between the first and second PCI/PMI selection process under the revised TEN-E Regulation, the 
number  of  candidate  projects  increased  from  13  to  24.  19  offshore  electricity  projects  were 
included in the draft second PCI/PMI list, with the majority again being radial links (14) compared 
to hybrid projects (5). Most projects were selected again in the NSOG corridor (9), followed by 
Atlantic offshore grids (5), as shown in Figure 16.  

115 

 
 
 
 
 
Figure 16: Distribution of offshore grids projects included in the draft second PCI/PMI list 
per offshore grid corridor 

Atlantic offshore; 5

NSOG; 9

SW offshore; 3

BEMIP offshore; 2

NSOG

BEMIP offshore

SW offshore

Atlantic offshore

Note: No applications in the SEE offshore corridor were received. 
Source: European Commission 

Effectiveness: The increasing number of  offshore electricity priority infrastructure projects 
indicates a positive trend and demonstrates the effectiveness of the framework for harnessing 
the potential of offshore renewable energy. 

infrastructure  category  efficiently  enables 

Efficiency:  The  offshore  electricity 
the 
identification of cross-border energy infrastructure projects. However, the number of project 
proposals involving radial links has been much higher compared to hybrid projects, indicating 
that  the  full  potential  of  the  latter  to  efficiently  unlock  offshore  energy  resources  across 
Member States and to enhance security of supply, market integration, and decarbonization by 
enabling interconnections between Member States alongside the simultaneous integration of 
offshore renewable energy has not been fully tapped, in the current framework. 

5.2 Offshore Grid Planning Provisions 

In line with Article 14(1), Member States, with the support of the Commission, were tasked to 
agree, at regional level, on goals for offshore renewable generation to be deployed within each of 
the 5 sea basins by 2050, with intermediate steps in 2030 and 2040. The respective non-binding 
agreements  were  first  adopted  in  January  2023  by  Member  States.  As  foreseen  under  Article 
14(1), Member States had to update these regional agreements by December 2024. The ambition 
included  in  the  updated  agreements  remained  relatively  stable,  resulting  in  cumulative  EU 

116 

 
 
 
 
 
 
offshore goals of the following ranges193: 86-89 GW by 2030, 259-261 GW by 2040, and 356-366 
GW by 2050. 

Map 1: Member States  updated regional  non-binding agreements for offshore renewable 
generation 

Source: European Commission 

Furthermore, in line with Article 14(2), ENTSO-E was tasked to develop an Offshore network 
development  plans  (ONDPs)  for  each  of  the  EU  sea  basins.  These  plans  provide  high-level 
information on the infrastructure that would be needed to achieve the goals of Member States. 
With  the  involvement  of  the  relevant  transmission  system  operators  (TSOs),  the  national 
regulatory authorities (NRAs), the Member States and the Commission, ENTSO-E published the 
first ONDPs in January 2024. Those plans will be updated following the update of the non-binding 
agreements by Member States. 

A  third  consecutive  offshore  related  requirement,  set  out  in  Article  15(1),  concerns  the  non-
binding  sea-basin  cross-border  cost-benefit  sharing  assessment  for  the  development  of  the 
ONDPs,  which  ENTSO-E  was  required  to  present  by  June  2025.  To  support  this  process,  the 
Commission  developed  guidance  as  foreseen  under  the  TEN-E  Regulation194.  This  included 
methodological  elements  for  ENTSO-E's  assessment  at  sea-basin  level  as  well  as  additional 
considerations to facilitate investment for cross-border offshore grid and renewable projects. The 
results of ENTSO-E's assessment were presented to the TEN-E priority offshore corridors in a 
cross-regional meeting on 4 July 2025. The objective of both this guidance and cross-border cost-

193 In some cases, the national goals are expressed as ranges, partially reflecting on-going national discussions and/or 
a  degree  of  uncertainty  associated  with  the  level  of  future  development  of  offshore  renewable  energy,  especially 
within the 2040/2050 timeframes. As a result, the cumulative EU offshore goals have been expressed in ranges. 
194  Accessible  online:  Guidance  on  collaborative  investment  frameworks  for  offshore  energy  projects  -  European 
Commission 

117 

 
 
 
 
 
benefit sharing assessment at sea-basin level was to provide non-binding information to support 
Member States NRAs and TSOs to kick-start cost-sharing discussions for offshore projects. 

Effectiveness:  The  Member  States  regional  non-binding  agreements  on  goals  for  offshore 
renewable generation provided an important political signal and increased visibility for the 
sector. They also enabled the establishment of top-down planning at the sea-basin level within 
the  context  of  the  ONDPs.  In  turn,  the  ONDPs  offered  important  information  on  sea-basin 
infrastructure needs and associated costs to achieve Member States’ goals, facilitating some 
regional planning discussions on concrete projects. For example, the Offshore Transmission 
Coalition (OTC) in the North Sea is currently exploring regional planning for a set of projects. 
Additionally,  the  first  non-binding  sea-basin  cross-border  cost-benefit  sharing  assessment, 
performed  by  ENTSO-E,  is  expected  to  support  such  discussions;  however,  the  relation 
between  the  process  carried  out  by  ENTSO-E  on  the  TEN-E  Regulation  and  the  above-
mentioned initiative of OTC remains to a certain extent unclear. 

Efficiency: The Member States’ non-binding goals and the ONDPs have been proven to be an 
important building block from which to start offshore planning. This ensures that needs are 
derived from Member States’ objectives and builds on existing scenarios and modelling tools. 
Furthermore, the upcoming integration of ONDP products into the TYNDP 2026 will promote 
a more optimized and integrated approach to both offshore and onshore planning. Ultimately, 
this supports a more efficient approach to planning overall. However, these processes so far 
have not led to the identification and realisation of concrete cooperation projects. 

Coherence: The TEN-E Regulation offshore planning provisions proved to provide a coherent 
support for offshore development in line with the EU offshore renewable energy policy, and 
notably  the  EU  Offshore  Strategy  and  the  Communication  on  delivering  on  the  offshore 
renewable energy ambitions.  

6. Reconfiguration of the priority corridors and areas 

As  previously  explained,  the  TEN-E  Regulation  revision  brought  upon  a  reconfiguration  of 
priority infrastructure corridors and areas. 

Table  12:  Distribution  of  projects  per  priority  geographical  infrastructure  corridor  and 
priority thematic area on the Union lists of PCIs and PMIs 

118 

 
 
 
 
First  PCI/PMI 
list 
Per TEN-E Regulation 

Draft 
PCI/PMI list 

second 

8 

21 

37 

23 

30 

24 

6 
2 

Priority geographical corridors 
Electricity corridor 
North-South electricity interconnections in Western 
Europe - NSI West Electricity 
North-South  electricity  interconnections  in  Central 
Eastern  and  South  Eastern  Europe  -  NSI  East 
Electricity 
Baltic  Energy  Market  Interconnection  Plan  in 
electricity - BEMIP Electricity 
Offshore grid corridors 
Northern Seas offshore grids - NSOG 
Baltic Energy Market Interconnection Plan offshore 
grids - BEMIP offshore 
South and West offshore grids - SW offshore 
South and East offshore grids - SE offshore 
Atlantic offshore grids 
Corridors for Hydrogen and Electrolysers 
Hydrogen interconnections in Western Europe - HI 
West 
Hydrogen  interconnections  in  Central  Eastern  and 
South Eastern Europe - HI East 
Baltic  Energy  Market  Interconnection  Plan  in 
hydrogen - BEMIP Hydrogen 
Priority Thematic Area 
Smart electricity grids 
Cross-border carbon dioxide network 
Smart gas grids 
Note: the two PCI/PMI lists contain, by way of exception, two gas projects that aim to connect the isolated islands 
Cyprus and Malta, in line with the Article 24 of the TEN-E Regulation. 
Source: European Commission 

6 
17 
3 

5 
14 
0 

2 
0 
2 

3 
0 
5 

9 
2 

15 

53 

21 

74 

9 

3 

Effectiveness:  The  selection  of  projects,  along  the  reconfigured,  priority  infrastructure 
corridors and thematic areas delivered broadly on the goals, as set out in Annex I of the TEN-
E  Regulation.  Multiple  projects  were  selected  across  all  the  infrastructure  corridors  and 
groups, with exception of SE offshore. 

7. Reinforced Permitting Provisions 

The revised TEN-E Regulation also reinforced permitting provisions, with the aim to accelerate 
the implementation  of PCI and PMI projects.  Still, as identified in the 2025 Study  on national 

119 

 
 
 
 
 
 
transmission 

infrastructure  projects195, 
permit  granting  processes  applicable 
to  energy 
commissioned by the European Commission, there are discrepancies across Member States in the 
adoption of certain  permitting  provisions stemming from  the TEN-E Regulation.  Moreover, in 
line  with  the  experience  of  the  Commission  in  discussions  concerning  project  implementation 
within the regional groups and the informal platform of national competent authorities in charge 
with  permitting,  a  series  of  miss-conceptions  and  unclarities  persist  regarding  the  permitting 
provisions in the TEN-E Regulation, e.g. the nature and scope of the pre-application procedure, 
the nature of the 3.5 years deadline, the scope of the comprehensive decision and that of the early 
public  consultation.  If  these  discrepancies  and  need  for  clarifications  are  addressed,  Member 
States could strengthen their respective permitting frameworks, enable timely delivery of critical 
energy infrastructure projects, and advance on the EU’s energy transition and climate targets.  

195  Accessible  online:  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 - Publications Office of the EU. The study evaluated compliance with the provisions of Chapter III of 
the  revised  TEN-E  Regulation  that  produced  legal  obligations,  including  those  introduced  and  amended  in  the 
revision. 

120 

 
 
 
Table 13: Implementation of provisions introduced in Chapter III on Permit granting and 
public participation 

Article reference 

Summary of Member State implementation 

Article  7(4)  on 
“dispute 
and 
judicial  resolution 
procedures” 

Article  7(5)  on 
“streamlining 
environmental 
assessment 
procedures” 

In terms of implementation, 7 Member States (MSs) are compliant, 
11 MSs are partially compliant, while no measures were identified in 
9 MSs. 

In  7  MSs,  PCI/PMIs  automatically  benefit  from  urgent  judicial 
procedures; 

In 7 MSs, PCI/PMIs can benefit from the procedures if certain criteria 
are met;  

In  4  MSs  the  application  of  procedures  is  determined  on  case-by-case 
basis;  

In 9 MSs, no specific urgent judicial procedures exist in general or are 
not applicable to energy infrastructure projects. 

In  23  Member  States,  relevant  measures 
to 
environmental assessment procedures were identified.  

streamline 

In 14 MSs, rules for conducting an integrated environmental assessment 
are in place. Environmental Impact Assessment (EIA) has been linked 
with  Strategic Environmental Assessment  (SEA) in  3 MSs, while in 2 
MSs, this has been done with the procedures required under the Habitats 
Directive and Birds Directive. All of these procedures are linked, in the 
case of 8 MSs. A number of additional supporting legislative measures 
have also been implemented by a number of MSs. 

Note: Additional provisions on permitting were introduced as part of the TEN-E Regulation revision in Chapter III 
but  were  not  covered  by  the  study.  These  include.  Article  8(6)  on  “designation  of  a  point  of  contact  for  project 
belonging to an offshore grid corridor” and Articles 10(3) & 10(4) on “clarification on the start of the permitting 
process” and “use of existing studies”. 
Source: European Commission (2025). 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 

Effectiveness:  The  amendments  generally  achieved  their  aim  to  increase  the  clarity  and 
flexibility of procedures. Specifically, in what concerns the new provision on dispute resolution, 
impacts  where  significantly  hampered  by  the  fact  that  9  Member  States  do  not  have  such 
procedures under national law and projects only benefit automatically from the procedure in 
7 Member States. The changes introduced to Article 10, improved clarity on the need to take 
into account pre-existing studies and assessments when evaluating permit applications but did 
not succeed in harmonising the understanding of what is the start of the permitting process 
across Member States, as confirmed by national authorities. 

121 

 
 
 
Efficiency:  The  provisions  introduced  did  not  significantly  increase  the  efficiency  of  the 
permitting  procedures  as their average duration  has even increased between 2023-2025196. 
Most  Member  States  have  complied  with  the  obligation  to  streamline  environmental 
assessments. However, these are still estimated to average at a duration of 20.6 months197. In 
what  concerns  the  accelerated  permitting  of  offshore  projects  through  the  designation  of 
offshore single points of contact, exchanges with stakeholders indicate that the uptake of this 
provision has been limited so far with the processes relying on ad hoc coordination between 
relevant Member States, which does not accelerate procedures. 

Coherence:  At  the  time  of  its  enactment,  in  2013,  the  previous  Regulation  (EU/347/2013) 
established the first accelerated permit granting framework with a binding maximum duration, 
which was applicable only to PCIs and PMIs. Thus, when the revisions were tabled in 2021, 
the changes introduced were simply aimed at improving the accelerated procedure already in 
place  (not  amend  it  significantly).  However,  since  then  (and  mainly  in  2022  following  the 
REPowerEU  plan)  new  accelerated  permitting  frameworks  for  energy  projects  were 
established  under  the:  Renewable  Energy  Directive,  the  Gases  Directive  and  the  Net  Zero 
Industry Act. Due to these changes, when compared to renewable energy projects, certain CO2 
and hydrogen projects covered by the new provisions, PCIs and PMIs no longer benefit from 
the best  and most  urgent treatment.  Since these projects  are selected as being  of  European 
interest,  this  situation  must  be  rectified  by  accelerating  their  treatment  in  permitting 
procedures.     

8. Strengthened Cross-Sectoral Infrastructure Planning Provisions 

The  revised  TEN-E  Regulation  aimed  at  strengthening  cross-sectoral  infrastructure  planning 
through several dedicated means.  

It  promoted  the  application  of  the  energy  efficiency  first  principle  as  part  of  the  process  of 
preparing the TYNDP. The ENTSOs were obliged to align their joint scenarios to be used for the 
Union-wide TYNDPs with the energy efficiency first principle and to take into account the latest 
available Commission scenarios, as well as, when relevant, the national energy and climate plans 
(Article  12(1)).  Also,  the  ENTSOs  were  mandated  to  implement  the  energy  efficiency  first 
principle  during  the  infrastructure  gaps  identification  process  (Article  13(1)),  while  regional 
groups had to consider it when establishing the regional lists of proposed PCI and PMIs. 

Requirements  for  a  more  extensive  consultation  process  with  Member  States,  stakeholders 
identified  in  the  TEN-E  Regulation,  and  the  European  Scientific  Advisory  Board  on  Climate 
Change (ESABCC) were introduced, during the preparation of single sector draft methodologies 
for a harmonised energy system-wide cost-benefit analysis (CBA) (Article 11), joint scenarios to 
be used for the Union-wide TYNDPs (Article 12) and infrastructure gaps reports (Article 13). 

The revised TEN-E Regulation mandated consistency between the single sector methodologies, 
for harmonised energy system-wide CBAs, performed respectively by the ENTSOs (Article 11(1)) 

196 Collection of information and data on the implementation of the revised Environmental Impact Assessment (EIA) 
Directive (2011/92/EU) as amended by 2014/52/EU), final report, page 25.   
197 Accessible online: Monitoring of projects of common interest and of mutual interest - 2025 | www.acer.europa.eu 

122 

 
 
 
 
 
and the Commission (Article 11(8)). Also, the Commission was given authority to approve joint 
scenarios to be used for the Union-wide TYNDPs (Article 12(6)), while the ACER was mandated 
to  provide  an  opinion  on  its  draft  12(5)198.  Provisions  on  cross-sectorial  planning  were  further 
strengthened with the Decarbonised Gases package in 2024, notably by the inclusion of hydrogen 
and ENNOH in the planning exercise. 

8.1 Energy System Wide Cost-Benefit Analysis  

As previously indicated, the Article 11 of the revised TEN-E Regulation outlined the need for the 
development of the consistent single sector methodologies and for a harmonised energy system-
wide  CBA  at  Union  level  for  projects  falling  under  different  energy  infrastructure  categories. 
Pursuant to Article 11(1), ENTSO-E was tasked to draft the methodology for harmonised energy 
system-wide  CBA  for  electricity,  while  ENTSOG,  for  gases  and  hydrogen  until  the  ENNOH 
would  be  able  to  take  over.  In  line  Article  11(8),  the  Commission  was  tasked  to  draft 
methodologies for the harmonised energy system-wide CBAs for the following new or updated 
infrastructure categories: electrolysers, smart gas grids, smart electricity grids, CO2 networks and 
energy storage.  

ENTSO-E  and  ENTSOG  published  and  submitted  for  comments  to  Member  States,  the 
Commission and ACER, their draft single sector methodologies on 23 April 2023 and 30 June 
2023, respectively. The ENTSOs performed extensive consultations envisaged by Articles 11(2) 
and  11(5),  receiving  also  ACER’s  opinions  on  the  two  methodologies.  The  ENTSOs  then 
submitted  the  revised  methodologies  to  the  Commission.  Following  its  approval,  the  ENTSOs 
published their revised methodologies. 

Pursuant  to  Article  11(8),  on  7  October  2022  and,  respectively,  on  15  November  2022,  the 
Commission  published for consultation  six  single sector methodologies for harmonised energy 
system-wide  CBAs.  The  final  versions  were  published  in  May  2023.  In  addition  to  the  five 
categories  outlined  above,  the  Commission  also  adopted  a  methodology  for  hydrogen,  as  a 
temporary instrument before ENTSOG’s methodology entered into force. 

198 The Commission’s authority to approve the single sector draft methodologies for a harmonised energy system-
wide CBA developed by the ENTSOs (Article 11(5)), as well as ACER’s authority to provide an opinion on the draft 
(Article 11(3)) were already introduced with the previous Regulation (EU/347/2013). 

123 

 
 
 
 
Table  14:  Overview  of  methodologies  for  a  harmonised  system-wide  CBA  published 
following the adoption of the revised TEN-E Regulation  

Infrastructure categories as 
set out in Annex II 

Name of the document 

Published: 

Concerning electricity, points 
(1)(a), (b), (d) and (f). 

4th  ENTSO-E  Guideline 
analysis of grid development projects199 

for  cost-benefit 

April 2024 

Concerning  smart  electricity 
grids, point (1)(e) 

Harmonised  system-wide  cost-benefit  analysis 
for candidate smart electricity projects200 

May 2023 

Concerning  energy  storage 
facilities, point (1)(c) 

Harmonised  system-wide  cost-benefit  analysis 
for candidate energy storage projects201 

May 2023 

Concerning  smart  gas  grids, 
point (2) 

Harmonised  system-wide  cost-benefit  analysis 
for candidate smart gas grids projects202 

May 2023 

Concerning  hydrogen,  point 
(3) 

ENTSO-G  Methodology 
for  Cost-Benefit 
Analyses of Hydrogen Infrastructure Project203 

February 
2025 

Concerning  hydrogen,  point 
(3) 

Harmonised  system-wide  cost-benefit  analysis 
for candidate hydrogen projects204 (replaced by 
the 2023 CBA Methodology of ENTSO-G) 

May 2023 

Concerning 
facilities, point (4) 

electrolyser 

Harmonised  system-wide  cost-benefit  analysis 
for electrolyser projects205 

May 2023 

Concerning  carbon  dioxide, 
point (5) 

Harmonised  system-wide  cost-benefit  analysis 
for  candidate  cross-border  carbon  dioxide 
network projects206 

May 2023 

Source: European Commission 

Pursuant  to  Article  11(9),  ACER  was  tasked  to  establish  and  publish  a  set  of  indicators  and 
corresponding reference values for the comparison of unit investment costs of comparable projects 
of the energy infrastructure categories covered by the TEN-E Regulation, every three years. On 
27 July 2023, ACER published the report, together with an energy infrastructure unit investment 
cost  calculator,  to  facilitate  future  estimations  of  unit  investment  costs207.  In  line  with  Article 

199 Accessible online: 4th ENTSO-E Guideline for cost-benefit analysis of grid development projects 
200 Accessible online: Harmonised system-wide cost-benefit analysis for candidate smart electricity projects 
201 Accessible online: Harmonised system-wide cost-benefit analysis for candidate energy storage projects 
202 Accessible online: Harmonised system-wide cost-benefit analysis for candidate smart gas grids projects 
203 Accessible online: Methodology for Cost-Benefit Analysis of Hydrogen Infrastructure Projects 
204 Accessible online: Harmonised system-wide cost-benefit analysis for candidate hydrogen projects 
205 Accessible online: Harmonised system-wide cost-benefit analysis for electrolyser projects 
206  Accessible  online:  Harmonised  system-wide  cost-benefit  analysis  for  candidate  cross-border  carbon  dioxide 
network projects 
207 Accessible online: ACER publishes a report on unit investment costs indicators and corresponding reference values 
of European energy infrastructure | www.acer.europa.eu 

124 

 
 
 
11(10), ENTSO-E and ENTSOG need to jointly submit to the Commission and ACER a consistent 
and  progressively  integrated  model  that  will  provide  consistency  between  single  sector 
methodologies  based  on  common  assumptions  including  electricity,  natural  gas  and  hydrogen 
transmission  infrastructure  as  well  as  storage  facilities,  liquefied  natural  gas  and  electrolysers. 
Towards its fulfilment, the ENTSOs published their Interlinked Model (ILM) 2024 progress report 
on 7 May 2024208, providing a dual assessment methodology for electricity and hydrogen. Based 
on the changes introduced by the Decarbonised Gases Package,209 the final report will be published 
in October 2025, with a delay of some 4 months from the original goal in the TEN-E Regulation, 
caused by procedural matters.  

Effectiveness: The process for developing harmonised CBA methodologies has proven to be 
effective  and  led  to  development  of  infrastructure  category  specific,  yet  fairly  consistent, 
methodologies.  

Efficiency: Based on the Commission’s experience, the technical and data  limitations  have 
been persisting obstacles to delivering robust CBA methodologies based on quantifiable and 
monetised  indicators.  The  control  mechanisms  -  ACER’s  opinion  and  the  approval  of  the 
Commission  -  of  the  CBA  methodologies  for  electricity  and  hydrogen  have  brought  some 
improvements  in  the  approach  but  have  not  been  effective  in  addressing  persisting 
shortcomings, e.g. in terms of better assessment of security of supply benefits. Also, the lengthy 
process for adopting opinions leads to efficiency losses. 

Coherence: Related to the previous criterion, the coherence of methodologies with broader 
EU objectives was ensured to a certain extent by ACER and the Commission’s opinion (with 
procedural limitations due to the applicable processes). 

8.2 Scenarios for the Ten-Year Network Development Plan 

In line with the Article 12(1), ACER developed and published on 25 January 2023 the Framework 
Guidelines with criteria for a transparent, non-discriminatory and robust development of the joint 
scenarios  to  be  developed  by  ENTSO-E  and  ENTSOG  for  their  respective  Union-wide 
TYNDPs210,  including  the  creation  of  the  Stakeholder  Reference  Group  for  the  scenarios’ 
development.  Following  ACER’s  Framework  Guidelines  (Article  12(2)),  and  in  line  with  the 
Article 12(3)), the ENTSOs developed the draft joint scenarios report211 to be used for the TYNDP 
(joint scenarios report). In line with Article 12(4), the report was submitted for the opinions of 
ACER, Member States and the Commission, on 30 May 2024, some eight months after the date 
initially planned by the ENTSO’s. The ESABCC, on its own initiative, provided an opinion on 
the draft joint scenarios report on 27 June 2024 pursuant to the second subparagraph of Article 
12(4). Among Member States, Austria submitted written comments on 1 August 2024, indicating 

208 Accessible online: ENTSOG and ENTSO-E publish their joint electricity and hydrogen Interlinked Model 2024 
progress report for public consultation 
209 Regulation (EU) 2024/1789 of the European Parliament and of the Council of 13 June 2024 on the internal markets 
for renewable gas, natural gas and hydrogen 
210  Accessible  online:  Framework  Guidelines  for  the  joint  TYNDP  scenarios  to  be  developed  by  ENTSO  for 
Electricity and ENTSO for Gas “TYNDP Scenarios Guidelines” 
211 Accessible online: ENTSO-E and ENTSOG TYNDP 2024 Draft Scenarios Report 

125 

 
 
 
 
 
some misalignments of the joint scenarios with their latest national projections. On 30 September, 
ACER delivered its opinion212  in which it underlined that the draft joint scenarios report was not 
fully  compliant  with  the  Framework  Guidelines  they  had  issued  in  January  2023.  ACER  also 
provided  recommendations  on  how  to  improve  the  report,  as  well  as  the  future  scenarios 
development processes starting with TYNDP 2026.  

The Commission approved the joint scenarios report for the 2024 TYNDP on 14 January 2025. 
As highlighted in the decision, the joint scenarios could not comply fully with ACER’s Framework 
Guidelines, because they were published only after the ENTSOs had already launched the scenario 
development  process.  Full  compliance  should  be  ensured  for  the  following  TYNDPs.  The 
Commission’s  decision  noted  general  alignment  with  the  requirements  introduced  in  the  2022 
revision  of  the  TEN-E  Regulation.  The  draft  joint  scenarios  have  been  widely  consulted  with 
stakeholders (including through Scenarios Stakeholder Reference Group, which met several times 
each month)213 and broadly aligned with the Union’s 2030 targets for energy and climate and its 
2050  climate  neutrality  objectives.  Furthermore,  the  energy  efficiency  first  principle  was 
considered  through  alignment  with  the  energy  efficiency  targets,  as  well  as  latest  available 
Commission scenarios (Fit-for-55 and REPowerEU scenarios) to the extent possible. 

Following the Commission’s approval, the report on joint scenarios was finalised by the ENTSOs. 
The update performed took into account updates to the carbon budget calculations, as per feedback 
provided by the ESABCC. The report was published on 29 January 2025. 

Effectiveness:  Assessing  the  effectiveness  of  the  implementation  of  TEN-E  Regulation 
provisions on the scenarios in terms of reaching the TEN-E Regulation objectives has certain 
limitations.  Scenarios fully compliant with all the requirements of the TEN-E Regulation have 
not yet fully materialised due to the timeline of the scenarios’ development. The application of 
the ACER Framework Guidelines will only have impacts in the TYNDP 2026 process, where 
one  central  scenario  and  two  economic  variants  will  be  developed.  The  creation  of  the 
Stakeholder  Reference  Group  has  led  to  better  involvement  of  stakeholders  in  the  scenario 
building  and  more  effective  exchange  of  expertise  and  information.  However,  the 
implementation of the group’s recommendations is still something to be followed up given the 
limited  scope  of  adjustment  to  the  scenario  building  process  within  the  first  two-year 
development  cycle.  Hence,  involvement  of  stakeholders  via  the  Scenarios  Stakeholder 
Reference Group could be assessed as efficient in terms of meeting the TEN-E Regulation goals 
on stakeholder transparency. 

When it comes to consideration of the NECPs in the scenarios, the existing approach showed 
several shortcomings. The new TEN-E Regulation provisions have not proven, so far, to be 
effective in  ensuring alignment with the NECPs while ensuring a timely development of the 
scenarios. Data collection for the scenarios remains a bottleneck and a timely, burdensome 
process, where ENTSOs struggle to get good quality data on time. The alignment with NECPs 
is also challenging because of the late delivery and quality of the plans. Concretely, NECPs 
are  not  always  sufficiently  detailed  and  do  not  encompass  all  the  sectors  (for  instance  the 

212  Accessible  online:  ACER  Opinion  05-2024  on  ENTSO-E  and  ENTSOG  Scenarios  for  TYNDP  2024  and 
Guidelines 
213 Accessible online: ENTSOs TYNDP Scenarios: Stakeholder Reference Group (SRG) 

126 

 
 
 
heating  and  cooling  sector  or  electromobility).  All  these  put  a  strain  on  the  already  tight 
development timeline of the scenarios. 

The  late  delivery  of  the  scenarios  in  the  TYNDP  cycle  leads  to  delays  of  other  TYNDP 
deliverables  (needs  assessment  and  projects’  CBA).  Furthermore,  the  ex-post  control 
mechanisms (the ACER opinion and the Commission’s approval) are not effective in ensuring 
any  changes  in  the  ongoing  process  because  they  come  too  late.  Any  adjustments  to  the 
scenarios could only be made in the following scenario development cycle. In particular, the 
Commission’s decision has been an inadequate tool since a potential rejection of the scenarios 
would basically derail the completion of the TYNDP and the PCI/PMI process.  The decision 
can  only  act  as  an  emergency  instrument  to  stop  significantly  incorrect  scenarios  without 
giving the Commission  the right means to  affect  the scenario development.  The formal and 
heavy Commission decision adoption process is also disproportionate for what can be achieved 
via this decision. In summary, the scenario building process seems not to be effective in meeting 
the TEN-E Regulation goals as it currently stands. 

Efficiency: While the objective of the 2022 TEN-E Regulation revision was, among others, to 
accelerate  and  streamline  the  scenario  development  process,  this  does  not  seem  to  have 
materialised.  The  2024  scenarios  were  significantly  delayed,  as  illustrated  above.  For  the 
TYNDP 2026, based on the current timeline214, the scenarios are expected to be delayed by 4-
6 months, which, inter alia, leads to issues not only for the PCI/PMI assessment process, but 
also for the Projects of Energy Community Interest process steered by the Energy Community 
Secretariat. As illustrated in the previous section, opinions come late in the process, which is 
not efficient from an administrative and cost perspective (FTEs spent on opinion drafting, even 
if they cannot substantially influence the process anymore). 

Coherence: While the existing process of scenario building proved to be more coherent with 
EU climate and energy targets as under the previous Regulation (EU/347/2013) (inter alia by 
requiring    stakeholder  transparency  and  early  involvement  in  the  process,  as  well  as  the 
mandatory  link  with  NECPs),  there  are  still  significant  gaps  due  to  data  quality  and 
availability, as well as the granularity of information available from NECPs. 

8.3 Infrastructure Gaps Identification and TYNDP Project Collection 

Pursuant to the requirement of the Article 13(1), ENTSO-E and ENTSOG are mandated to publish 
the  infrastructure  gap  reports  under  the  TYNDP  framework  within  six  months  following  the 
publication of the joint scenarios reports (Article 12), and every two years thereafter. ENTSOG 
published for public consultation its draft Infrastructure Gaps Report215 on 18 December 2024, 
while ENTSO-E published its own draft report216 on 31 January 2025, some six months later than 
the targeted date set in ENTSO-E’s work programme. Pursuant to Article 13(3), ACER published 
its opinions on the gaps reports on 27 May 2025 for ENTSOG’s draft report and 26 May 2025 for 

214 State of play as of 28 July 2025. 
215 Accessible online: Hydrogen Infrastructure Gaps Identification Report | TYNDP 2024 
216 Accessible online: Opinion No 05/2025 of ACER of 27 May 2025 on ENTSOG Draft Hydrogen Infrastructure 
Gaps Identification Report 

127 

 
 
 
 
 
ENTSO-E’s draft report217. The assessment on the draft reports by the Commission, pursuant to 
Article 13(4) is currently ongoing and will result in opinions addressed to the ENTSOs, towards 
drafting their final Infrastructure Gap Reports. 

For the electricity sector there seem to be some discrepancies in terms of timeline, the interlink of 
the TYNDP project collection for the PCI/PMI assessment process and the Infrastructure Gaps 
Report.  

Project collection for the 2026 TYNDP started in mid-April 2025 and lasted for one month, until 
mid-May  2025.  During  autumn  2025,  there  will  be  an  opportunity  to  submit  additional,  non-
mature projects (with project status “under consideration”).218 

Based on the 2026 TYNDP FAQ219,  the provisional list of projects admitted to the TYNDP 2026 
is to be published in January 2026. The updated list is to be released for public consultation only 
in October 2026. CBA results as well as the draft infrastructure gaps identification (system needs 
study) are expected to be published for public consultation in Q4 2026.220  At the same time, the 
3rd PCI/PMI assessment process is set to start earlier, in early autumn 2026. There is thus a risk 
that projects which would not be accepted for the final TYNDP 2026 would apply for PCI/PMI 
process.  At the time, such projects  may still need to  be assessed by the regional groups in  the 
PCI/PMI selection process to ensure a non-discriminatory approach. This leads to inefficiencies 
and administrative burden. Also, the timeline as presented earlier raises questions on alignment of 
candidate projects with the needs identified, especially in light of the January 2026 provisional 
list. 

Effectiveness:  Throughout  the  past  two  TYNDP  processes  (2024  and  expected  timeline  for 
2026 TYNDP), it has become evident that the Commission’s opinion comes too late to affect 
the Infrastructure Gap Report. What is more, some of the elements of the opinion would come 
too  late  to  be  addressed  even  in  the  following  TYNDP  cycle  e.g.  the  reference  grid 
configuration.  Hence, this  ex-post  control  mechanism does not  seem very effective, and the 
formal adoption procedure could be deemed as disproportionate to the impacts the opinion 
could bring. Furthermore, it has become evident that ACER and the Commission have little 
means  to  steer  the  gaps  identification  process  in  the  desired  direction  and  make  it  more 
relevant  for  the  identification  of  the  key  projects  for  the  Union.  There  is  currently  no 
mechanism  to  be  applied  in  case  projects  do  not  fully  meet  addressed  needs  (this  was  also 
raised  by  ACER  in  their  2024  Infrastructure  Market  Monitoring  Report).221  Moreover,  the 
timeline raises questions on whether the projects, if collected 1.5 year earlier than the results 
of the Infrastructure Gaps Report, are effectively addressing the needs, and if their alignment 
with the needs can be ensured. The publication of the final report a mere half a year before the 
collection for the next cycle starts also questions its effectiveness in terms of steering the project 
development for the next cycle (as half a year is not long enough to agree on new cross-border 
or even internal projects, not to mention inclusion in national network development plans, if 

217 Accessible online: Opinion No 04/2025 of ACER of 26 May 2025 on ENTSO-E’s Draft TYNDP 2024 and on 
ENTSO-E’s draft Infrastructure Gaps Report 2024 
218 Accessible online: Promoters corner | ENTSO-E TYNDP 
219 Accessible online: 250207_TYNDP2026_FAQ_ProjectPromoters_Final.pdf 
220 Accessible online: Entso-e | Explore the TYNDP 
221 Accessible online: Electricity infrastructure development to support a competitive and sustainable energy system 
| www.acer.europa.eu 

128 

 
 
 
necessary). As a consequence, under the current approach, the gaps identification report is 
more  a  self-standing  deliverable  than  a  sufficiently  strong  steer  toward  concrete  project 
development.   

Efficiency:  The  process  and  its  timeline,  as  it  stands  currently,  cannot  ensure  an  efficient 
TYNDP  and  PCI/PMI  selection  process,  as  the  TYNDP  process  selection  results,  the  CBA 
results and the Infrastructure Gaps Report are not published early enough to directly feed into 
the PCI/PMI process (in terms of filtering project applications). This leads to inefficiencies in 
the process, resulting in the assessment of projects which consequently may not be matching 
the infrastructure needs identified.  

Coherence: The existing process proved not to be fully coherent with the climate and energy 
goals,  due  to  timeline  issues,  but  also  due  to  the  impossibility  to  take  into  account  the 
Commission’s opinion due to its very late delivery in the process (de facto after the decision of 
the Technical decision-making body on the draft PCI/PMI list). 

9. Cross-Border Cost Allocation  

The TEN-E Regulation revision in 2022 has not materially changed the rules governing the cross-
border cost-allocation framework compared to previous Regulation (EU/347/2013). However, in 
June  2023,  ACER  updated  its  recommendation  on  good  practices  for  the  treatment  of  the 
investment  requests  including  Cross  Border  Cost  Allocation  (CBCA)  requests,  for  PCIs,  as 
foreseen under Article 16(11) of the Regulation. This updated recommendation provides further 
indications,  for  instance,  regarding  the  recommended  threshold  when  allocating  costs  and  the 
treatment of uncertainty. 

According to ACER’s report on cross-border cost allocation decisions222, the number of CBCA 
decisions for electricity PCI and PMI projects has decreased over time, while hydrogen projects 
have  not  received  any  CBCA  decisions  yet  as  projects  are  not  mature  enough  to  initiate  an 
investment  request  including  a  CBCA  or  are  not  yet  captured  by  the  regulated  regime.  For 
electricity PCI and PMIs, 14 CBCA decisions were granted over the period 2014-2019 (June), 
while only 5 CBCA decisions were issued between (June) 2019 and 2024.   

In recent  years, there have been very few new CBCA decisions. Because of this, only  a small 
number of projects on the latest PCI/PMI list have received a CBCA decision (either a new CBCA 
or a CBCA carried over from previous lists). Out of the 80 projects on the first PCI/PMI Union 
list, only 19 are covered by CBCA decisions, and just 2 of those are new projects. 

Additionally, only a limited number of CBCA decisions include a transfer of costs across borders/ 
to non-hosting countries (3 out of 50 CBCA decisions for the period 2014-2024), all of which 
were in the gas sector so not relevant any more under the revised TEN-E Regulation. 

222 Accessible online: ACER CBCA Report 

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Lastly, there is a strong link between the establishment of a CBCA and the CEF application. The 
project promoter(s) of all 50 investment requests expressed an intention to apply for CEF funding 
for works. 

Effectiveness: The current CBCA provisions have facilitated the allocation of investment costs 
for  PCI/PMIs  in  the  gas  and  electricity  sectors,  primarily  to  support  CEF  applications  for 
works.  Within  this  framework,  the  TEN-E  Regulation  has  effectively  ensured  that  projects 
submitting  CEF  funding  applications  are  based  on  well-founded  investment  requests  and 
demonstrate sufficient maturity. However, there have been very few instances of involvement 
by non-hosting countries in CBCA decisions, and none in the electricity sector. Provisions have 
therefore  had  limited  effectiveness  in  triggering  additional  investments  from  non-hosting 
countries that may benefit from the projects.  

Efficiency: The existing CBCA framework has enabled the allocation of CEF grants, helping 
to  close  the  financing  gap  for  some  PCI/PMI  projects,  and  has  been  relatively  efficient 
compared to the resources required to establish such CBCAs. However, its efficiency has been 
relatively limited when considering its ability to trigger contributions from across borders and, 
thus, truly unlocking financing opportunities outside of Union grants. 

Coherence: These provisions proved to be coherent with broader EU energy policy objectives, 
as they aim to facilitate the implementation of regulated cross-border energy infrastructure 
projects,  thereby  increasing  interconnectivity  between  Member  States  and  promoting 
electrification, for example, by unlocking the offshore renewable energy potential. 

10. Conclusions  

In terms of coherence, the revision of the TEN-E Regulation in 2022 brought its scope in line with 
the  objectives  of  the  European  Green  Deal  and  with  achieving  climate  neutrality  by  2050.  Its 
implementation provided evidence of the need for further improvements, namely when it comes 
to  scenario  development,  infrastructure  needs  identification  and  consequent  TYNDP,  PCI/PMI 
project selection and assessment, as well as CBCA and permitting frameworks. 

The first and the second PCI/PMI lists reflected the substantial policy changes made as part of 
2022 TEN-E Regulation revision. Fossil fuel infrastructure stopped being eligible to benefit from 
the TEN-E policy framework. However, there is a risk associated with the smart gas grids project 
category with  regard to  possible indirect  support of natural  gas infrastructure, as shown in  the 
second PCI/PMI selection process. The introduction of hydrogen and electrolyser infrastructure 
categories  was  very  effective,  in  the  sense  that  it  led  to  a  significant  number  of  (successful) 
candidate projects, which also substantially increased from first to second PCI and PMI selection 
process.  It  remains  to  be  seen  how  many  of  these  projects  will  reach  implementation  stage. 
Moreover, many of the applied electrolyser projects were rather limited in size, raising questions 
about their added value, in terms of cross-border impact. In the electricity infrastructure category, 
there  were  also  a  significant  number  of  candidate  projects.  The  scope  of  the  category  was 
expanded to accommodate offshore infrastructure needs of Member States. However, the number 
of the proposed radial links compared to hybrid projects was noticeably larger, despite the latter’s 
higher potential to, inter alia, efficiently unlock offshore energy resources across Member States. 
It is also visible that the number of internal electricity (onshore) lines remains limited compared 
to  interconnections.  On  the  other  hand,  the  revision  in  the  scope  of  smart  electricity  grids 

130 

 
 
 
 
infrastructure category, and the introduction of new category for smart gas grids projects, did not 
bring about the intended uptake of projects falling under their scope. 

In  the  two  PCI/PMI  selections  processes,  a  growing  interest  in  the  infrastructure  projects  with 
third-country networks was observed. While it supports the alignment of the EU policy framework 
with the Energy Community (and especially EU accession) countries, and despite the impact these 
countries  have  on  the  internal  EU  energy  market  and  security  of  supply  due  to  existing 
interconnections,  the  current  framework  only  considers  benefits  for  the  EU,  resulting  in  some 
candidate PMIs with the Energy Community Contracting Parties not succeeding in the selection 
procedure, although they might contribute significantly to the EU’s policy objectives.  

The  offshore  grid  planning  provisions  resulted  in  the  adoption  of  non-binding  goals  and  the 
ONDPs, which are important building blocks from which to start offshore planning. The upcoming 
integration of the ONDPs into the TYNDP 2026 will promote an even more efficient approach to 
planning overall. However, these processes so far have not led to the identification and realisation 
of concrete cooperation projects. 

The  permitting  amendments  introduced  by  the  TEN-E  Regulation  revision  in  2022  generally 
achieved  their  intended  goal  to  increase  the  clarity  and  flexibility  of  procedures.  Still,  further 
improvements  could  be  made  to  support  the  acceleration  of  procedures,  contributing  to  the 
process’s overall efficiency.  

The provisions on cross-sectoral infrastructure planning were also subject to substantial revisions. 
While the harmonised CBA methodologies were delivered, and proven effective, technical and 
data  limitations  in  their  development  influenced  their  robustness.  The  scenario  development 
process, as it stands now, is faced with multiple drawbacks driven largely by delays and, hence, 
not  fully  effective  in  meeting  the  TEN-E  Regulation  goals.  Similar  issues  hamper  the  gaps 
identification  process.  In  addition,  the  Commission  and  ACER  have  little  means  to  steer  the 
process towards identification of the key projects for the Union.  Moreover, there is no mechanism 
to be used in case the projects proposed do not fully meet the addressed needs. 

With regard to the cross-border cost allocation, the TEN-E Regulation provisions have efficiently 
and effectively facilitated the allocation of investment costs for PCI/PMIs in the electricity (and 
in the past in the gas) sector, primarily to support CEF applications for works. However, there 
have been very few instances of involvement of non-hosting countries in CBCA decisions, and 
none  in  the  electricity  sector.  Provisions  have  therefore  had  limited  effectiveness  in  triggering 
additional investments from non-hosting countries that may otherwise significantly benefit from 
the projects. 

II. 

IMPLEMENTATION  REPORT  ON  THE  RENEWABLE  ENERGY  DIRECTIVE  LEGAL 
FRAMEWORK REGULATING PERMIT-GRANTING 

The report focuses on the implementation to date of the legal framework regulating the permit-
granting  procedure  to  build,  repower  and  operate  renewable  energy’  plants  and  their  related 
infrastructure (hereinafter: “permitting”), as set out in Directive (EU) 2018/2001 on the promotion 

131 

 
 
 
of  the  use  of  energy  from  renewable  sources223  (hereinafter:  “RED”).  The  importance  of 
permitting for RES and the barriers it faces were already identified in Directive 2001/77/EC224 of 
the European Parliament and of the Council, which required Member States to evaluate the permit-
granting procedures in order to reduce the regulatory and non-regulatory barriers to the production 
of renewable electricity. Directive 2009/28/EC225 of the European Parliament and of the Council 
introduced  requirements  to  simplify  the  administrative  procedures  for  renewable  energy 
developers, whereas Directive (EU) 2018/2001 of the European Parliament and of the Council 
strengthens  these  requirements  and  introduces  a  permitting  deadline  for  the  first  time 
(transposition by June 2021). 

Following  the  Russian  aggression  against  Ukraine  and  the  adoption  of  REPowerEU,  which 
highlighted  the  need  for  more  and  faster  RES  deployment  in  order  to  reduce  dependency  on 
Russian gas, Council Regulation (EU) 2022/2577 (the ‘Emergency Regulation’) laying down a 
framework  to  accelerate  the  deployment  of  renewable  energy226  and  entered  into  force  in 
December  2022.  Its  provisions  were  applicable  for  18  months  from  this  date.  Application  of 
certain of its provisions, alongside minor amendments, was extended until June 2025 by Council 
Regulation  (EU)  2024/223227  The  extension  was  effectuated  based  on  the  findings  of  the 
Commission’s Report of 28 November 2023 on the review of Council Regulation (EU) 2022/2577 
of 22 December 2022 laying down a framework to accelerate the deployment of renewable energy. 
In the Report, the Commission found that the conditions for the prolongation of the validity of 
Regulation  (EU) 2022/2577  were  met  and  proposed  to  prolong  selected  measures  that  had  the 
greatest potential for the acceleration of the deployment of renewables, which were not included 
in Directive (EU) 2018/2001, and which appear to bring about an important acceleration in the 
permit-granting process of renewable energy and for related grid infrastructure projects or which 
have the significant potential to do so. 

In parallel, RED was amended by Directive (EU) 2023/2413 (hereinafter: ‘the revised RED’),228 
which  introduced  an  enabling  framework  to  accelerate  the  deployment  of  renewable  energy 
projects  by  simplifying  and  streamlining  their  permit-granting  procedures,  introducing  new 

223 Directive (EU) 2018/2001 of the European Parliament and of the Council of 11 December 2018 on the promotion 
of the use of energy from renewable sources (recast); OJ L 328 21.12.2018, p. 82. 
224 Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on the promotion of 
electricity produced from renewable energy sources in the internal electricity market; OJ L 283, 27.10.2001, pp. 33–
40. 
225 Directive 2009/28/EC of the European Parliament and of the Council of 23 April 2009 on the promotion of the use 
of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC 
(Text with EEA relevance), OJ L 140, 5.6.2009, pp. 16–62. 
226 Council Regulation (EU) 2022/2577 of 22 December 2022 laying down a framework to accelerate the deployment 
of renewable energy; OJ L 335 29.12.2022, p. 36. 
227 Council Regulation (EU) 2024/223 of 22 December 2023 amending Regulation (EU) 2022/2577 laying down a 
framework to accelerate the deployment of renewable energy; OJ L, 2024/223, 10.1.2024. 
228 Directive (EU) 2023/2413 of the European Parliament and of the Council of 18 October 2023 amending Directive 
(EU)  2018/2001,  Regulation  (EU)  2018/1999  and  Directive  98/70/EC  as  regards  the  promotion  of  energy  from 
renewable sources, and repealing Council Directive (EU) 2015/65; OJ L, 2023/2413, 31.10.2023. 

132 

 
 
 
elements related to spatial planning and made permanent some important elements introduced by 
the  Emergency  Regulation.  The  deadline  for  Member  States  to  transpose  the  planning  and 
permitting-related provisions of this Directive was set mostly by July 2024, but also by May 2025 
(Articles  15b  and  15c).  Directive  2018/2001  as  amended  by  the  revised  RED  and  Council 
Regulation 2022/2577 amended by Council Regulation 2024/223 were introduced to accelerate 
the permit-granting procedure to build, repower and operate renewable energy’ plants and their 
related infrastructure. 

The targeted amendment (revision) of the RED under the European Grids Package, as announced 
by the Action Plan for Affordable Energy, aims to ensure that greater and faster deployment for 
RES is achieved as well as setting permitting rules for storage and recharging station assets that 
facilitate the integration of renewables. 

In  view  of  the  recent  last  revision  of  the  RED  and  its  recent  transposition  deadlines,  the 
Commission opted for an “Implementation Report”, focused on the performance of the specific 
provisions under the permitting-related provision of the revised RED to address the effectiveness 
of the existing permitting rules as well as their EU added value and relevance. The report provides 
an overview of the main outputs, linked to the implementation of the new framework, per topic. 
Specifically,  it  assesses  in  a  retrospective  manner  the  extent  to  which  these  elements  have 
performed so far in achieving its stated objective of contribution to the European Green Deal and 
reaching climate neutrality by 2050. 

1. METHODOLOGY AND DATA AVAILABILITY 

1.2. General remarks 

In general, it is substantiated that a comprehensive application of the EU framework for permitting 
brings an acceleration in terms of renewable energy deployment. However, the following elements 
should be considered: 

- 

- 

- 

the permitting procedures of renewable energy plants and their related infrastructure vary 
significantly from one Member State to another, with country-specific national solutions 
coupled  or  intertwined  with  the  obligations  stemming  from  other  EU  or  national  legal 
bases.  It  is  relevant,  in  this  respect,  to  point  out  that,  as  the  main  EU  permitting 
requirements  are  set  in  a  Directive  (the  revised  RED),  Member  States  have  a  certain 
flexibility as to how they transpose its provisions into their national legal order. 
factors other than permitting  can delay or halt RES projects,  including  the lack of grid 
capacity, cost and investment issues, demand, supply chain issues, etc.  
as per the ongoing study “Monitoring progress of measures to streamline permit-granting 
procedures under revised RED and Emergency Regulation and development of permitting-
related KPIs”, and its First Interim Report received by the Commission in July 2025, many 
Member States do not collect the data on renewable energy permitting procedures (average 
duration, reasons for delays etc.) being initiated and/or concluded, and there is no common 

133 

 
 
European format of such data or principles of their collection229. While progress has been 
made  in  some  Member  States  on  specific  aspects,  the  monitoring  of  data  remains 
fragmented, Thus, it is not always possible to directly link an increase of RES installed 
capacity in a Member States with the implementation of the EU rules on permitting.230  

The  Emergency  Regulation  has  ceased  to  be  applicable  in  its  entirety  since  30  June  2025. 
Nevertheless, a mock-up matrix linking the overarching topics with the specific provisions of both 
the revised RED and the Emergency Regulation is presented in this Report. A high-level summary 
of the revised RED permitting provisions is also set out. 

To  facilitate  the  assessment  of  their  implementation,  this  Report  groups  the  renewable  energy 
permitting  provisions in  3 overarching  clusters,  which reflect  the major  changes  in  the current 
permitting-granting  framework.  These  are  the  Overriding  Public  Interest  (“OPI”),  the  Single 
Contact Point231 and the technology-related rules. 

co 

2. ANALYSIS 

2.1 Overview of the legal basis 

The provisions of the revised RED with a July 2024 transposition deadline constitute a structured 
EU legal basis for the permit-granting procedures to build, repower and operate Renewable Energy 
Sources’ plants and their related infrastructure. The scope of each of the Article is the following: 

➢  Article 16: Organisation and main principles of the permit-granting procedure 

•  Criteria for permitting process duration and validity of applications. 
•  Streamlining of administrative processes. 
•  Designation of single contact points. 
•  Provision of adequate resources to competent authorities and reskilling of staff. 
•  Digitalisation of permit-granting procedures (by 21 November 2025). 
•  Public availability of decisions 

➢  Article 16b: Permit-granting outside renewable acceleration areas (“RAAs”) 

•  Permitting timelines: <2 years, but <3 years for offshore, and <1 year for repowering, <2 

years for offshore repowering. 

229 The overview of the state of play of the RES permitting data collection in individual Member States is provided in 
the following section. 
230 Especially given that a successfully concluded permitting process of the renewable energy plant would be reflected 
only in the future statistics on e.g. installed RES capacity, which, moreover, are  not always available at the same 
breakdown of details across all Member States. 
231 Which existed already in the Directive (EU)2018/2001 but in simpler form. 

134 

 
 
 
•  All relevant environmental assessments for a renewables project to be rolled into one single 

procedure. 

•  The killing or disturbance of species protected under the Birds & Habitats Directives must 
not  be  considered  ‘deliberate’  where  a  project  has  followed  all  necessary  mitigation 
measures. 

➢  Article 16c: Permit-granting for repowering 

•  Permitting timelines: <3 months for grid connections. 
•  Screening limited to extension of existing projects. 
•  Exemptions available for solar installations from screening and environmental assessments 

when no additional space is required compared to the original project. 

➢  Article 16d: Permit-granting for solar installations on artificial structures 

•  Permitting  timelines:  <3  months  for  solar  equipment  and  co-located  storage  with 
possibility for applying exemptions, and <1 month for solar equipment with capacity of 
100 kW or less. 

•  Positive silence for solar equipment with capacity of 100 kW or less. 
•  Exemptions available from screening and environmental assessments. 

➢  Article 16e: Permit-granting procedure for heat pumps 

•  Permitting  timelines:  <1  month  above  50  MW,  but  <3  months  for  ground  source  heat 
pumps, <2 weeks for connections to the grid for lower capacity MW/self-consumers). 

➢  Article 16f: Presumption of overriding public interest (OPI) 

•  Permitting, planning, construction and operation of renewable plants must be presumed to 
be in the OPI for the purpose of the application of certain exemptions regulated in certain 
environmental directives. 

As  mentioned  already,  some  RES  permitting  provisions  were  already  introduced  by  the 
Emergency Regulation, which was amended one time and ceased to apply in its entirety  on 30 
June 2025. The matrix  of the  revised RED  and the Emergency Regulation provisions with  the 
overarching topics’ clusters could be visualised as follows: 

Table 15: Permitting overarching topics EU legal basis:232 

Overarching 
topic 

Detailed description 

Art.
ER 

Prolongation ER 

Art. RED 

Overriding 
public interest 
(OPI) 

Several  aspects  of  renewable  energy  projects  are  OPI, 
namely with respect to conservation of natural habitats 
and wild fauna, water policy, conservation of wild birds 

3(1) 

Prolonged until 
June 2025 

16f with adjustments, namely, 
to duly justify in case this 
article is not applied  

232 First Interim Report “Monitoring progress of measures  to streamline  permit-granting procedures under revised 
RED and Emergency Regulation and development of permitting-related KPIs”, July 2025. 

135 

 
 
 
Overarching 
topic 

Detailed description 

Construction  and  operation  of  plants  and  related 
infrastructure  which  are  OPI  are  given  priority  when 
balancing legal interests beyond environmental matters 

Simplification of compensatory measures 

One Stop Shop 
(OSS) 

One-stop-shop (Single Contact Point) and digitalisation 

Art.
ER 

3(2) 

Art. 
3a 

- 

Small  Solar  up  to  50  kW,  sometimes  lowered  to  10.8 
kW; permits to be granted within maximum 3 months 

4 

Prolongation ER 

Art. RED 

Prolonged until 
June 2025 with 
small changes 

 Introduced in 
2023and in force 
until June 2025) 

- 

- 

- 

- 

16(3) 

16d with adjustments, namely 
an increase of the limit to 100 
kW 

Repower existing  RES  facilities, permits  to be  granted 
within 6 months 

5(1) 

Prolonged until 
June 2025, with 
small changes 

- 

Technology-
specific 
provisions, 
including 
repowering 

Repower existing RES facilities, with capacity increase 
below 15% permits to be granted within 3 months 

5(2-
5) 

Prolonged until 
June 2025 

16c with small adjustments 

Exemption from environmental impact assessment 

Permit-granting process for heat pumps 

Timeline exclusions 

Specific deadlines for RE projects outside RAAs 

6 

7 

8 

- 

Prolonged until 
June 2025 

- 

16e with small adjustments 

Prolonged until 
June 2025 

- 

- 

16b 

This Report replicates the breakdown into overarching topics presented above. 

A targeted consultation of the selected stakeholders incl. business associations under the ongoing 
study “Monitoring progress of measures to streamline permit-granting procedures under revised 
RED and Emergency Regulation and development of permitting-related KPIs” revealed that when 
asked ‘if the current regulatory framework decreased the duration of the permitting process’ 39% 
of the respondents disagreed, while 37% agreed that that timelines are shorter. This suggests that 
statutory deadline provisions are beginning to take effect in some jurisdictions, yet implementation 
remains patchy and highly context dependent.  

The same split views were given to the question ‘Has the current regulatory framework increased 
the  approval  rate  of  permit  applications?’,  with  35%  of  respondents  reporting  higher  approval 
rates, 38% seeing no improvement, and 10% being neutral. Follow-up comments highlight initial 
improvements related to simplified environmental screenings are already in place, but little change 
to other parts of the permitting process. Lastly, the question ‘Has the current regulatory framework 
enabled  the  faster  deployment  of  renewable  energy  while  reducing  the  workload  for  public 
authorities?’ provoked the most scepticism, with only 25% of respondents answering ‘yes’ and 

136 

 
 
 
 
52%  disagreeing.  Both  respondents  and  interviewed  stakeholders  cited  staffing  shortages  and 
underdeveloped digital workflows as the main reasons why the expected reduction in workload 
has yet to materialise. 

Stakeholders’  input  was  also  gathered  in  the  Implementation  Dialogue  with  Commissioner 
Jørgensen on permitting for renewable energy projects and related infrastructures, held on 11 June 
2025.  The  discussions  therein  highlighted  a  consensus  on  the  necessity  to  intensify  efforts  to 
implement current EU legislation, in particular the revised RED, and to further simplify permitting 
by  reducing  the  regulatory  burden,  including  by  introducing  exemptions  to  environmental 
legislation and for small-scale projects. There was a call on the Commission to further foster the 
exchange  of  best  practices  among  Member  States.  Participants  underlined  the  need  to  support 
permitting authorities with more resources and better skills, particularly at local level. The need 
for further simplifying procedures (especially for small-scale projects, storage and repowering), 
extending  the  overriding  public  interest  principle,  targeted  exemptions  from  specific  EU 
legislation, accelerating the digitalisation of permitting processes and improving data availability 
was also brought to the attention of the Commission. 

2.2 Overriding Public Interest (OPI) 

Article  16f  of  the  revised  RED  requires  Member  States  to  set  a  rebuttable  presumption  that 
renewable energy installations, their related infrastructure and storage assets are in the overriding 
public interest and serving public health and safety when balancing legal interests in individual 
cases vis-à-vis certain EU environmental legislation, namely the Habitats Directive,233 the Water 
Framework Directive234 and the Birds Directive.235 Member States may restrict the application of 
the OPI provisions to certain parts of their territory, to certain types of technology or to projects 
with  certain  technical  characteristics.  The  Emergency  Regulation,  which  expired  in  July  2025, 
also allowed Member States to “give priority” to RES installations that were recognised as being 
of OPI when balancing legal interests in the individual case beyond environmental matters. 

As of June 2025, 9 Member States have provided information and declared full transposition with 
regards Article 16f, 5 Member States have declared partial transposition, and the remaining 10 
Member States have not transposed and/or have not provided relevant information. Regarding 3 
Member States, the transposition of Article 16f was not analysed due to the late submission of the 
required measures 

A Member State which took advantage of the OPI concept enshrined in the Emergency Regulation 
already  from  December  2022  is  Germany.  It  has  achieved  substantial  integration  of  the  OPI 

233 Council Directive 92/43/EEC of 21 May 1992 on the conservation of natural habitats and of wild fauna and flora; 
OJ L 206, 22.7.1992, pp. 7–50. 
234 Directive 2000/60/EC of the European Parliament and of the Council of 23 October 2000 establishing a framework 
for Community action in the field of water policy; OJ L 327, 22.12.2000, pp. 1–73. 
235 Directive 2009/147/EC of the European Parliament and of the Council of 30 November 2009 on the conservation 
of wild birds (Codified version); OJ L 20, 26.1.2010, pp. 7–25. 

137 

 
 
 
principle,  not  only  limited  to  permitting  for  renewable  energy  installations  but  also  enhancing 
permitting  efficiency  by  recalibrating  how  environmental  and  other  concerns  are  weighed  in 
decision-making  processes.  The  Federal  Ministry  for  Economic  Affairs  and  Climate  Action 
(BMWK) has provided clear guidance to align regional permitting authorities with national and 
EU legislation, addressing uncertainties and questions from  federal authorities. This  consistent 
support  has  empowered  authorities  to  implement  relevant  provisions  with  greater  confidence. 
Judicial reinforcement has been equally important, with multiple court decisions upholding the 
precedence of OPI for renewable energy projects.236 

This  approach  constituted  a  substantial  pillar  in  accelerating  the  RES  permitting  process  in 
Germany  together  with  strong  political  commitment.  In  2024,  renewable  energy  generation 
capacity  installed  in  Germany  increased  by  19.6  GW.  This  is  double  compared  to  2022  and 
confirms  the  positive  trend  of  2023  (+18.6  GW).  This  is  mainly  thanks  to  additional  solar 
capacity.237 Depending on the source, granted permits for onshore wind reached 14 GW238 or 15 
GW239  in  2024,  meaning  that  permitted  onshore  wind  capacity  per  year  more  than  tripled 
compared to 2022. This positive trend was confirmed in the first half of 2025, which set a new 
record with 7.8 GW of wind energy capacity permitted.240 

For  many  Member  States,  the  OPI  concept  has  been  comprehensively  implemented  only  in 
relation  to  the  revised  RED  transposition  (not  in  relation  to  the  Emergency  Regulation),  as  it 
required amendments to sectoral pieces of legislation. Given the transposition deadline expired 
only in July 2024, it is still too early to establish a correlation of its application with the annual 
RES deployment rates. However, certain positive trends seem to be emerging in some Member 
States.241  

At  the  same  time  however,  research  and  stakeholders’  feedback  have  revealed  issues  and 
confusion in many cases with regards to the implementation of this provision. In some Member 
States, implementation is hindered due to the stringent conditions under which it applies or due to 
persistent veto powers, especially from cultural heritage authorities. There are also cases where 
Member States continue to treat renewable energy projects as ordinary infrastructure, despite the 
Regulation’s direct applicability and the Directive’s expired transposition deadline, an approach 
that significantly weakens the intended effect of OPI. 

236  Notable  examples  include  the  Federal  Constitutional  Court's  recognition  of  EEG  §2  in balancing  wind  energy 
development with forest protection (BVerfG, 27.09.2022  - 1 BvR 2661/21) and the application of this principle in 
heritage protection contexts by regional courts (OVG Greifswald, 07.02.2023 - 5 K 171/22). 
237 Data retrieved from: Bundesnetzagentur - Erneuerbare Energien 
238 Status des Windenergieausbaus an Land im Jahr 2024 
239 Bundesnetzagentur - Erneuerbare Energien 
240 Marburg-Biedenkopf: Boom bei neuen Windrädern? 
241 First Interim Report “Monitoring progress of measures to streamline permit-granting procedures under revised 
RED and Emergency Regulation and development of permitting-related KPIs”, July 2025. 

138 

 
 
 
2.3  Single Contact Point 

According to Article 16(3) of the revised RED, Member States are required to set up one or more 
contact  points  which  shall  guide  and  facilitate  the  applicant  during  the  entire  administrative 
permit-application and permit-granting procedure. The applicant shall not be required to contact 
more  than  one  contact  point  during  the  entire  procedure,  hence  the  concept  of  “the  One  Stop 
Shop”. It shall provide the applicant with all necessary information and involve other authorities, 
were appropriate. It also has to keep track of the deadlines set out in the revised RED. According 
to Article 16(4), the contact point shall make available a manual of procedures for developers of 
renewable energy plants and shall provide that information online. This requirement for a manual 
of procedures builds on an obligation that already existed in the RED. 

While it is difficult to quantify the impact of the Single contact point on duration of the permitting 
procedure or even more, on Member States deployment rate of renewable energy, its facilitating 
role shall not be underestimated, especially towards market participants with less expertise such 
as self-consumers, renewable energy communities or SMEs.  

As  of  June  2025,  Article  16(3)  is  declared  as  fully  transposed  by  4  Member  States  but  only 
partially transposed by 13 MS. The remaining 7 have not transposed the provision or have not 
provided relevant information. This will be assessed by the Commission. Moreover, 7 Member 
States have declared full transposition of Article 16(4), while 7 declared partial transposition and 
10  MS  have  either  failed  to  transpose  it  so  far  or  have  not  provided  any  relevant  document. 
Regarding the latter, 3 Member States were not analysed due to the late submission of the required 
measures. 

The state-of-art example in this respect is Denmark, which has a well-established concept of a 
Single Contact Point for offshore wind projects, where the Danish Energy Agency has been the 
single  focal  point  throughout  the  whole  development  process,  liaising  with  different  involved 
stakeholders.242 The Agency has  been expanding  its services in  this respect, assuming  also the 
revised RED-compliant role of the single contact point from Article 16(3). The solution has been 
widely regarded as contributing to a streamlined permitting process, including a single licensing 
process, and mitigating costly delays during the construction phase.  

The Danish Energy Agency (“ENS”) is to be used as single point of access to assistance on issues 
related to all offshore wind permitting. ENS will grant the required permits and will coordinate 
these with other relevant authorities. Therefore, it is the ENS which serves the project developer 
in relation to the many, often opposing, interests connected to the establishment of offshore wind 
power projects, with its scope now further expanded. This means that the permits granted by ENS 
also contain terms and conditions from other authorities, such as the Danish Nature Agency, the 

242 Concept visualised: https://initiatives.weforum.org/clean-power-and-electrification/casestudy1 

139 

 
 
 
Danish  Maritime Authority, the Danish  Coastal Authority, the Danish  Agency for Culture, the 
Ministry of Defence, etc.243 

Even though very good implementation such as the above exists, the establishment of centralised 
Single contact point for permitting coordination shows varied progress across Member States, with 
most exhibiting partial implementation or systems under development rather than fully operational 
solutions.  

While  all  Member  States  have  established  some  forms  of  contact  points,  the  process  is  rarely 
unified. In quite a few cases single contact points have limited role and provide, for example, only 
information or ‘guide’ the developers without more active engagement (e.g. Ireland, Poland). 

While  there  has  been  an  effort  to  streamline  information  around  Member  States’  permitting 
processes, in quite few cases the role of the contact point is merely informative.244 

2.4 Technology-specific provisions 

The reason these provisions are grouped together for the purpose of this Report stems from another 
layer  of  difficulty  in  quantitively  measuring  their  dedicated  impact  on  the  actual  length  of  the 
permitting process or the deployment rate of specific RES technologies. This is because with the 
lack of general  data on the length of permitting  procedure, the availability of their subsequent 
breakdown into specific subsets is even more challenging. 

Technology-specific  provisions,  as  introduced  in  Section  1  of  the  analysis,  encompass  shorter 
deadlines for all technologies. Article 16c sets rules to simplify repowering procedures. Article 
16d addresses deadlines for solar installations on artificial structures, as well as small-scale solar 
installations. Article 16e governs the permitting time for heat pumps.  

The self-declared status of Member States with regards the transposition status of these Articles 
as of June 2025 is the following: 

-  Article 16b is fully transposed in 2 Member States and partially transposed in 14 Member 
States.  Eight Member States have not  transposed these provisions.  The transposition of 
this Article in 3 Member States has not yet been analysed due to the late submission of the 
required measures. 

-  Article 16c is fully transposed in 1 Member State and partially transposed in 12 Member 
States. Eleven Member States have not transposed these provisions. The transposition of 

243 https://ens.dk/sites/default/files/media/documents/2024-11/offshore_wind_development_0.pdf 
244  European  Commission:  Directorate-General  for  Energy,  COWI,  Eclareon  and  Prognos,  Monitoring  the 
implementation of the Commission recommendation and guidance on speeding up permit-granting procedures for 
renewable energy and related infrastructure projects – Final report, Publications Office of the European Union, 2025, 
https://data.europa.eu/doi/10.2833/2257747  

140 

 
 
 
these Articles has not yet been analysed in 3 Member States due to their late submission 
of the required measures. 

-  Article 16d is fully transposed in 3 Member State and partially transposed in 13 Member 
States.  Eight Member States have not  transposed these provisions.  The transposition of 
these Articles has not yet been analysed in 3 Member States due to their late submission 
of the required measures. 

-  Article 16e is fully transposed in 3 Member State and partially transposed in 10 Member 
States. 11 Member States have not transposed these provisions. The transposition of these 
Articles has not yet been analysed in 3 Member States due to their late submission of the 
required measures. 

The analysis of implementation in practice of the permitting provisions was prepared within the 
remit of the First Interim Report “Monitoring progress of measures to streamline permit-granting 
procedures under revised RED and Emergency Regulation and development of permitting-related 
KPIs”. Important to note that this assessment does not necessarily correlate with the transposition 
checks  status  presented  above,  as  the  former  looks,  to  the  extent  possible,  into  the  effective 
functioning of permitting deadlines, while the latter encompasses legal assessments.  

To this end, permitting deadlines for renewable energy projects can be grouped into three main 
categories. The first category includes Member States that have established clear deadlines which 
had an impact on the permitting duration. Italy has incorporated the six-month permitting cap and 
introduced streamlined procedures for small-scale solar PV projects, alongside partial exemptions 
from the need to go through an EIA. Its use of tacit consent has proven instrumental in reducing 
administrative inertia. The Netherlands also benefits from pre-existing national legislation with 
sometimes shorter deadlines than those set by the Emergency Regulation, supported by a penalty 
system for late decisions, although not aimed specifically at accelerating permit-related decisions. 

The second category includes Member States  that  have established deadlines,  but  considerable 
delays  are  observed.  Germany  has  included  the  deadlines  in  federal  law  but  lack  of  legal 
consequences  for missed deadlines means that projects  may get  delayed. In  France, permitting 
timelines  have  improved  through  legislative  reform  and  digital  tools,  but  remain  inconsistent 
across  departments.  Greece  has  also  established  deadlines  and  milestones,  but  they  are  not 
realistically respected. 

The  third  category  includes  Member  States  where  deadlines  have  been  partially,  or  not 
implemented and considerable barriers remain. Poland has partially introduced shorter deadlines, 
while deadlines for repowering are not yet in place. In Sweden, permitting is handled on a case-
by-case basis without binding repowering rules concerning shorter deadlines. Romania continues 
to apply outdated time limits and treats repowering as equivalent to new construction, even though 
legislation is in place. Spain’s fragmented legal landscape lacks a unified permitting timeline, also 
due to regional authorities applying the rules differently.  

141 

 
 
To conclude, the common obstacle across most countries is that even where deadlines are legally 
prescribed,  they  are  often  undermined  due  to  lack  of  administrative  staff  and/or  complex 
procedures. 

3. CONCLUSION 

Despite  challenges  with  dispersed  data  on  permitting  processes  and  some  Member  States  not 
having transposed the permitting provisions in their entirety, it still can be observed that the most 
advanced Member States in their implementation are also the ones who demonstrated a substantial 
acceleration of renewable deployment in the corresponding period. 

In terms of effectiveness, it can be observed on the example of Germany that taking full advantage 
of the solutions laid down in the Emergency Regulation and the revised RED has accelerated the 
RES  permitting  process  substantially,  resulting  in  an  exponential  increase  of  RES  deployment 
rates.  Some  granular  positive  developments  may  also  be  observed  in  both  these  areas  in  the 
Netherlands or Portugal. For the majority of the remainder of Member States, the effectiveness is 
to be confirmed only once more comprehensive national framework is put in place and subject to 
availability  of  the  comprehensive  data  pertaining  to  the  permitting  processes.  It  needs  to  be 
highlighted that stakeholders are not yet reporting many changes on the ground, indicating that 
despite the ambitious framework, targeted amendments may be needed. 

Similar  conclusions  can  be  drawn  in  relation  to  efficiency  of  the  measures.  An  adequate 
implementation of the provisions of the Emergency Regulation and revised RED results in setting 
up binding deadlines for the duration of the process, hence inherently contributing to the efficiency 
of the permitting of renewables and related infrastructure. 

The coherence with broader EU energy and climate policy objectives is thoroughly ensured, as 
renewables constitute a cornerstone for both the EU green transition and its energy independence, 
which reinforces security. Any policy intervention aiming at deployment of more renewables into 
the EU energy system contribute to these overarching objectives. 

Thus, the current framework has resulted in improvements in terms of effectiveness, efficiency 
and coherence of the renewable energy permitting in the EU, as well as it demonstrated the EU 
added value and relevance. However, more comprehensive datasets would be required to measure 
the impact of the permitting provisions in a structured manner. 

Lastly,  it  is  also  to  be  noted  that  even  though  the  current  provisions,  for  renewable  energy 
permitting has showed some promising results, the level of renewable energy capacity that it is 
needed for reaching our 2030 targets and even beyond require much faster and more renewable 
energy development and therefore additional measures may contribute to their further fine-tuning. 

142 

 
 
 
 
143 

 
 
 
 
 
 
ANNEX 8: MONITORING 

The  success  of  the  preferred  policy  option  can  be  measured  against  the  following  operational 
objectives and set of indicators, 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 and increased use of cost-sharing tools;  
the simplification of permitting procedures 

• 
• 
•  shortening of permitting lead times and meeting current deadlines; 
• 

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

1)  Projects  included  in  network  development  plans  and  selected  as  PCI/PMIs  address 
appropriately and effectively identified infrastructure needs. The achievement of this objective 
will be assessed through matchmaking projects included in network development plans with the 
identified needs and ensuring that selected PCI/PMIs projects are assessed and validated based 
on  clearly  defined  criteria,  demonstrating  that  they  effectively  address  infrastructure  needs 
identified. The preferred policy option should reduce the gap between the identified needs and 
TYNDP  and  PCI/PMIs  should  decrease  by  most  cost-effective  solutions.  The  following 
indicators will be used: 

• 

• 

• 

of 

and 

new 

total 

number 

capacity 

cross-border 

the 
approved/implemented; 
the extent to which identified infrastructure needs are addressed by infrastructure projects 
(capacity)  included  in  the  TYNDP  (planned,  under  construction  or  commissioned)  or 
other non-wired solutions (presence of the gap between needs and projects, and decrease 
of the gap);  
the uptake of non-wired solutions in terms of number of projects and respective increase 
in grid capacity; 

interconnectors 

2)  The  more  effective  use  of  cost-sharing  tools  for  faster  deployment  of  cross-border 
infrastructure projects. By facilitating and supporting the adoption of cost-sharing tools among 
cross-border  infrastructure  project  stakeholders,  project  deployment  time  should  reduce 
compared to the status quo, as tracked by deployment timelines and stakeholder feedback. It will 
be monitored through: 

• 

• 
• 
• 

the number of binding cost-sharing agreements enabling the implementation cross-border 
projects;  
the average duration for reaching a cost-allocation agreement; 
the number of non-hosting countries contributing to cost-sharing agreements; 
the number of projects being as part of bundles being submitted for PCI/PMI status. 

3)  Shorter  and  simpler  permitting  procedures  for  energy  infrastructure,  renewable  energy 
assets, storage projects, and recharging stations. This is expected to lead to shorter lead time 
to obtain the necessary permits, making it possible to meet the existing deadlines fewer permit 
requirements, a reduction in documentation  to be assessed in the permitting procedure, and 
reducing duplication of data recorded through digitalisation and centralised recording.. As 

144 

 
 
the preferred option includes a measure on centralisation and digitalisation of the permitting 
procedure in the Member States. This is specifically designed to facilitate data collection and 
allow to identify the remaining bottlenecks. Together with information from stakeholders it 
will be the base for a coherent monitoring using the following indicators:  

• 
• 

• 

the average and maximum total duration of permitting procedures in years; 
the yearly rate and average delays in the permitting procedure of projects of common and 
mutual interest (in years); 
the rate of digitalisation of permitting procedures - in percentage and number of Member 
States  deploying  digital  procedures,  permitting  management  platforms  and  centralised 
archives  for  the  relevant  data  (in  a  format  that  is  easily  accessible  to  the  relevant 
stakeholders); 
the  level  of  opposition  faced  by  projects  of  common  interest  (number  of  written 
objections during the public consultation, number of legal recourse actions). 

4)  Enhanced  physical  and  cyber  security  and  resilience  of  cross-border  energy  infrastructure 
(PCIs/PMIs)  which  should  achieved  by  increasing  the  number  of  protection  and  resilience 
equipment and installations on critical network elements. The success will be monitored through 
the risk assessments and resilience testing outcomes for specific infrastructure done at national 
level. Following indicators will be used for monitoring: 

• 

the number of PCIs and PMIs improving physical and cyber security of existing and new 
grid infrastructure; 

•  number  of  critical  cross-border 

infrastructure  assets  covered  by  updated 

resilience/security measures; 

Ultimately, the proposed policy option should lead to timely implementation  of the necessary 
infrastructure  projects  reducing  the  overall  energy  system  costs  and  bringing  sustainability, 
market integration and security of supply benefits. This will be measured by looking at:  

the integration of renewable energy sources and reduced greenhouse gas emissions; 
increase in grid hosting capacity; 
the interconnection level between Member States; 

• 
• 
• 
•  change in energy system adequacy; 
•  number of reported major incidents or disruptions affecting critical energy infrastructure; 
•  assessment of evolution of energy system costs. 

The  achievement  of  the  specific  and  operational  objectives  will  be  tracked  based  on  existing 
monitoring requirements of ACER to avoid duplication. Concretely, monitoring of the following 
data will be conducted using ACER deliverables and sources of data:  

•  Annual monitoring report on congestion management and capacity allocation, which will 
assess how efficiently existing capacity is used and what the improvements have been as 
a result of the initiative. 

•  Biennial  monitoring  of  consistency  between  the  Union-wide  TYNDP  and  national 

network development plans 

145 

 
 
•  Annual  monitoring  of  progress  of  PCI  and  PMI  projects  and  permitting  processes  by 

ACER as well as national authorities.  

•  Monitoring of the  application of non-wired and  grid enhancing  technologies  based on 
data  publicly  available  by  the  Joint  Allocation  Office  (and  used  by  ACER  in  their 
monitoring reports) 

•  Annual monitoring of the achievement of the interconnection target, done as part of the 

European Semester assessment 

146 

 
 
 
 
ANNEX 9: DESCRIPTION OF POLICY MEASURES 

Annex 9 provides a detailed description of the policy measures referred to in Section 5.2.1 of the 
Impact Assessment Report. 

Specific objective 

Policy measures 

E)  Infrastructure planning and project implementation  

Ensure 

included 

that 
SO1: 
projects 
in 
network  plans  address 
appropriately 
identified 
needs 

A.1 
A.2 
A.3 
A.4 

A.5 

Strengthening the existing framework 
Increased EU level steering and coordination 
Fully centralised approach 
Alignment  of  scope  (smart  gas  grids/ 
blending, electrolysers, PMIs) 
Broadening 
(modernisation and digitalisation)245 

scope  of  PCI  categories 

F)  Cost and benefit sharing  

tools 

SO2: Facilitate the use of 
cost-sharing 
for 
faster  deployment  cross-
infrastructure 
border 
projects 

G)  Permitting  

Shorten 

and 
SO3: 
simplify 
permitting 
procedures  for  energy 
infrastructure, renewable 
storage 
and, 
energy 
projects 
as 
as  well 
recharging stations 

H)  Security  

SO4:  Enhance  physical 
and  cyber  security  and 
resilience of cross-border 
energy infrastructure 

B.1 

B.2 

B.3  

Enhancing  transparency  and  strengthening 
EU  principles  for  cross-border  energy 
infrastructure costs and benefits sharing 
Use  of  congestion  income  for  financing  of 
cross-border  electricity  infrastructure  as  an 
incentive to cost-sharing 
Enabling framework for voluntary bundling 
of projects   

B.4  Mandatory  offshore  regional  planning  and 

cost-sharing 

C.1 

C.2 

C.3 

D.1 

D.2 

D.3 

Supporting  the  implementation  of  existing 
legislation and issuing guidance 
Targeted  legislative  changes  to  accelerate 
permitting 
Centralised 
permitting 
coordination  regime  for  certain  large-scale 
energy 
(“28th 
Regime”) 

infrastructure 

projects 

wide 

EU 

Including physical and cyber-risk resilience 
considerations in the monitoring of PCIs and 
PMIs 
Additional 
requirements 
transparency 
regarding  the  ultimate  beneficial  owners  of 
candidate PCIs/PMIs  
Including  security  and  resilience-related 
equipment  for  the  upgrade  of  existing 
electricity  cross-border  infrastructure  under 
TEN-E scope 

PO
1 

X 

X 

PO
2 

PO
3 

X 

X 

X 

X 
X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

X 

245 On the broadened scope to better reflect security/resilience within the PCI scope see policy measure D.3 

147 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
A.  Infrastructure planning and project implementation  

A.1 Strengthening the existing framework  

Measure  A.1  proposes  limited  changes  to  strengthen  the  existing  infrastructure  planning 
framework. To simplify and streamline the PCI/PMI selection process and contribute to reaching 
specific objective 1, the ACER opinion on the draft PCI/PMI list would be removed as it comes 
late in the process and hence has a limited impact on the final outcome. The aim is to ensure more 
effective ACER involvement that would come in earlier stages of the process This implies 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 towards ex ante steering. For this purpose, this 
measure  would  require  the  development  of  a  framework  methodology  for  scenario  and  needs 
identification by ACER and would strengthen ACER’s and NRAs’ role in the verification of the 
TYNDP  inputs  to  the  PCI/PMI  process  and  monitoring  of  the  implementation.  It  would  also 
include a simplified application and evaluation process for mature PCIs and PMIs. PCIs and PMIs 
which have already reached final investment decision or have received a CEF grant for works and 
which show continued progress in their implementation should retain their PCI/PMI status without 
the need for resubmission and reassessment. 

In electricity, the scope of the planning would be expanded to better consider non-wired solutions 
and internal grid reinforcements. Timing of the TYNDP including its scenarios and infrastructure 
need identification would remain the same as under the existing legal framework, with the TYNDP 
being delivered every two years. Regarding the national level, there would be limited changes to 
the provisions on the electricity transmission network development planning to mirror the Gases 
Directive provisions in the electricity legislation (notably the Electricity Markets Directive) and 
ensure  alignment  of  obligations  applying  on  all  electricity  TSOs.  These  requirements  demand 
national  coordination  on  scenarios  between  electricity,  hydrogen  and  gas  sectors  as  well  as 
consideration of local heating and cooling plans, where applicable, as well as the deployment of 
alternative fuels infrastructure under the Alternative Fuels Infrastructure Regulation (AFIR), and 
projects for industrial facilities and industrial hubs.246 

A.2 Increased EU level steering and coordination  

Building  on Measure A.1, measure A.2 would move from  a “bottom  up” towards a more “top 
down” cross-border infrastructure planning approach ensuring greater transparency, scrutiny and 
coherence of inputs used in network planning both at European and national level. It involves the 
Commission, ACER and NRAs earlier in the planning process and simplifies the application and 
evaluation process for mature PCIs and PMIs. 

The Commission would be responsible for the development of a comprehensive central scenario, 
which would be developed at least every 4 years (instead of existing two-year cycles). Targeted 
updates would still be possible more frequently and might be needed in case of significant market 
developments (or external geopolitical circumstances). Updates may be particularly relevant for 
hydrogen  infrastructure  planning,  given  the  high  level  of  uncertainty  in  market  developments, 

246 The creation of low-carbon industrial clusters, as assessed in the context of the IDAA, can contribute to industrial 
demand projections for grid planning purposes. 

148 

 
 
 
 
changing assumptions on hydrogen uptake. The ENTSOs and ENNOH would be responsible for 
scenarios/sensitivities  data  collection,  based  on  Commission  guidelines  ensuring  more 
consistency and transparency. Stakeholders, NRAs and Member States would be involved in the 
development  of  scenarios  and  use  of  newest  data  on  assumptions  on  future  development  of 
generation and demand. 

A strengthened infrastructure needs identification would be also done every 4 years, and when 
relevant  every  2  years,  based  on  the  central  scenario  and  the  sensitivities  developed  by  the 
Commission.  Responsibility  for  the  needs  assessment  would  remain  with  the  ENTSOs  and 
ENNOH as in Measure A.1 but be based on framework guidance developed by ACER in line with 
the principles defined in the TEN-E Regulation. The ENTSOs would present the results of their 
needs assessment at least until 2050. As part of the process and before the publication of the final 
results, ACER/NRAs would validate the correct application of the framework guidance followed 
by  approval  of  the  results  by  the  Commission  and  Member  States.  Stakeholder  involvement, 
including in particular the ENTSOs, ENNOH and the EU DSO Entity, would be ensured by their 
consultation when developing and approving the guidance for the needs assessment by ACER, as 
well as during the needs identification process itself (conducted by ENTSOs). 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 ensure higher credibility and comparability of projects 
and their costs and benefits. It would be less driven by (national) TSOs, represented by ENTSOs, 
but 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  

This measure would entail  a requirement to  fully consider non-wired alternative solutions  as a 
priority when addressing the identified needs (based on the accompanying cost-benefit analysis). 
Also, it would entail an additional planning element for electricity to ensure all identified needs 
are addressed. A gap filling mechanism would be introduced to ensure that all remaining needs 
that cannot be addressed by non-wired solutions and for which no TYNDP projects have been 
submitted  are  addressed.  First,  relevant  TSOs  would  be  required  to  propose  possible  solutions 
under the scrutiny of NRAs and Member States steered by the Commission with the support of 
ACER. Second, in case no projects are proposed by the TSOs, the Commission in cooperation 
with hosting Member States may launch a call for project proposals, which may be delivered by 
TSOs or other project promoters.  

This  measure  also  assumes  closer  involvement  of  regional  cooperation  fora  (such  as  Regional 
Groups) in the process to facilitate the identification of priorities and appropriate follow-up. On a 
national level, besides fully mirroring requirements of the Gas Directive on scenario coordination, 
for the electricity sector  this measure would introduce requirements to  better link national  and 
European planning by requiring use of the central scenario as one of the scenarios.  This which 
would be a prerequisite for NRA approval of NDPs. This measure would also suggest prolonging 
the period of network planning on a national transmission grid level for electricity from existing 
5-10 to 15 years, to allow catering for anticipatory investment. 

A.3 Fully centralised approach  

149 

 
 
Measure  A.3  entails  a  full  shift  from  the  current  primarily  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 (for 
cross-border infrastructure projects under the TYNDP) would be done by an entity at EU level 
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 EU-level entity would have legally defined links with European Commission, 
ENTSOs/TSOs,  ENNOH/HTNOs,  ACER/NRAs,  Member  States,  and  other  relevant  national 
authorities to ensure data sharing and verification by all concerned parties. 

This entity would be responsible of the entire planning process, including scenario development 
and the associated data, run market and network studies to identify infrastructure gaps, assess the 
benefits of projects and draft and publish the planning reports. The role of ENTSOs/TSOs and 
ENNOH/HTNOs would be limited to providing information for which their unique expertise in 
networks  is  required.  The  scope  and  granularity  of  the  scenario  development  and  needs 
identification would be the same as in measure A.2. Addressing the identified needs (gap filling 
mechanism) would build on measure A.2 and be steered by the new entity. In electricity, there 
would  also  be  an  obligation  to  compare  non-wired  alternative  solutions  and  infrastructure 
solutions and cover the needs identified. However, Member States would have to approve projects 
in their territory and have the right to veto any PCI/PMI candidate projects to be located in their 
territory, in line with the TFEU. 

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. Among existing EU 
entities ACER or CINEA might appear as possible candidates. However, there are considerable 
limits to the possible transfer of the envisaged tasks to these agencies. The mandate of CINEA, 
as an executive agency of the Commission, is limited to implementing Union programmes (2021-
2027 MFF) on its  behalf. Entrusting it with  infrastructure planning would entail  a significant 
extension of its mandate going beyond the scope and remit of executive agencies. ACER as a 
decentralised  regulatory  agency  has  been  set  up  as  separate  legal  entity  distinct  from  the  EU 
institutions, to perform specific technical tasks that help the EU institutions and Member States 
to implement policies and take decisions. ACER taking up tasks in relation to the selection of 
specific  infrastructure  projects  would  raise  concerns  over  conflict  of  interest  with  possibly 
overlapping  planning  and  scrutiny  powers.  This  could  also  question  the  independence  of 
regulatory  authorities  themselves  which  are  represented  in  the  Agency’s  Board,  and  trigger 
backlash from Member States and stakeholders.  

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

To  ensure  that  the  electrolysers  are  recognised  under  the  TEN-E  have  significant  cross-border 
relevance,  measure  A.4  suggests  raising  the  minimum  installed  capacity  threshold  for 
electrolyser projects from the current 50MW to at least 500MW (or 1000MW), along with 
introducing new criteria to confirm network impact—such as network-related function for both 
the electricity and the hydrogen networks with a view to overall system flexibility. These changes 
would cater for a better alignment of this category with the objectives of the TEN-E framework 
and  would  reflect  the  trends  observed  throughout  two  cycles  of  implementation  of  the  TEN-E 
Regulation on electrolysers (see section 2.2.3 of IA Report and Annex 7). EU policy and financial 

150 

 
 
support247 to electrolysers will remain very important to scale up the hydrogen segment and the 
changes in the TEN-E will complement the policy landscape by better targeting of cross-border 
impact.  

With  a  view  to  clarifying  and  strengthening  the  objectives  of  the  Regulation  in  promoting 
infrastructure  dedicated  to  the  exclusive  use  of  hydrogen,  this  policy  measure  would  include 
removing any incentives for projects for blending hydrogen with natural gas via three main groups 
of amendments. Firstly, it would remove the smart gas grid category from the scope of the 
TEN-E Regulation in line with recent legal and policy updates with a view to ensuring that no 
support is given to projects involving hydrogen blending which pose risks of circumventing the 
discontinuation of support to natural gas grids under the TEN-E Regulation, or to TSOs that aim 
at  levels  of  hydrogen  blending  that  may  raise  interoperability  issues  at  cross-border 
interconnection  points  and  fragment  the  internal  market.,    Secondly,  it  would  remove  the 
possibility  of  blending  that  currently  exists  under  Article  31  of  the  TEN-E  Regulation  for 
dedicated hydrogen assets converted from natural gas assets falling under the energy infrastructure 
category set out in point (3) of Annex II to be used for transport or storage of a predefined blend 
of hydrogen with natural gas or biomethane during a transitional period ending on 31 December 
2029.  Thirdly, it would amend the definitions of ‘dedicated hydrogen assets’ and of ‘repurposing’ 
to ensure that these target exclusively pure hydrogen. 

A.5 Broadening scope of PCI categories (modernisation and digitalisation)248  

To better include non-wired solutions in planning, policy measure A.5 would introduce a change 
to electricity grids PCI category to more prominently include non-wired solutions. Furthermore, 
to better reflect contribution of internal lines to cross-border electricity trade (and flows), the 
existing 500 MW threshold would be lowered to 200 MW.  

B.  Cost and benefit sharing  

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

Measure B.1 aims at enhancing early transparency in the assessment of project benefits and costs 
to encourage the involvement of non-hosting EU countries. It also aims to establish a streamlined 
CBCA  process  and  a  more  harmonised  EU  cost-sharing  framework  to  support  discussions 
amongst NRAs. More specifically, it would entail the following elements: 

-  ENTSO-E  and  ENNOH  would  be  required  to  publish  Cost  benefits  analysis  (CBA) 
results  showing  how  the  benefits  of  TYNDP  projects  are  distributed  across  countries, 
including  non-hosting  countries  who  significantly  benefit  from  such  projects.  This 
information would be published as part of the TYNDP. Project promoters would then be 
encouraged to submit a preliminary non-binding cost-sharing agreement as part of their 
PCI/PMI application, considering ENTSO-E’s and ENNOH’s assessment of cross-border 
benefits in the TYNDP.  

247 Horizon Europe, the Innovation Fund, the Hydrogen Bank, the Recovery and Resilience Fund and Cohesion funds, 
as well as State aid.   
248 On the broadened scope to better reflect security/resilience within the PCI scope see policy measure D.3 

151 

 
 
 
-  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 such as scenarios to be used, benefits and costs to be 
included,  cost-sharing  keys,  ex  post  conditions  etc.  Those  principles  would  ensure 
consistency  across  Member  States  and  across  CBCAs.  Updating  its  recommendation, 
ACER would also need to take into account the differences between the electricity sector 
and the emerging hydrogen sector. ACER would retain its role of last-recourse decision-
maker  for  CBCA  decisions.  It  would  also  be  tasked  with  improving  transparency  and 
facilitating CBCA processes by developing a non-binding CBCA template and hosting a 
central CBCA repository on its website to facilitate the work of project promoters and 
NRAs. 

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 would be used to create an additional tool for unlocking 
cost-sharing discussions for infrastructure projects which generate relevant benefits beyond the 
borders of their hosting Member States, where the benefits within the hosting Member States do 
not outweigh the costs. 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. This financing capacity would be spent on 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. 
This would primarily target regional flagship projects, such as a meshed offshore network in the 
North  Sea.  This  measure  is  inspired  by  past  examples  where  the  bundling  of  five  prioritised 
Nordic  grid  reinforcements249  as  part  of  the  2004  TSO  Nordel  Infrastructure  Package  and 
supported politically by the concerned Member States250, as enshrined in the Ministerial Nordel 
agreement,  led  to  the  successful  implementation  of  the  related  projects251.    In  addition,  such 
voluntary bundling approach is also already initiated by several North Sea Member States and 
TSOs,  having  been  initiated  by  the  Offshore  Transmission  Coalition  (OTC)  and  North  Seas 
Energy  Cooperation  (NSEC)252.  This  measure  entails  the  establishment  of  an  EU-level 
framework  that  facilitates  the  identification  and  voluntary  bundling  of  cross-border  projects. 
These  projects  would  be  grouped  together  to  enable  and  encourage  cost-sharing  discussions 
amongst  relevant  Member  States  (and  third  countries).  Specifically,  this  framework  would 
facilitate project promoters to jointly submit PCI applications and, TSOs and NRAs to prepare 

249 1. Fennoskan II (Decided) 2. Great Belt (Decided) 3. Nea - Järpströmmen (Decided) 4. South Link (Decided) 5. 
Skagerrak IV (Letter of Intent, concessions applied).   
250 Sweden, Norway, Denmark, Finland 
251 EMG 2008 
252 Offshore TSO Collaboration, https://www.tennet.eu/offshore-tso-collaboration  

152 

 
 
 
coordinated  CBCAs  for  the  bundle  of  projects.  This  approach  would  also  facilitate  the 
submission of subsequent funding applications under CEF for the bundle of projects. 

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. TSOs would 
be required to undertake a joint regional planning exercise, building on the non-binding sea-basin 
offshore  renewable  agreements  of  Member  States.  This  would  be  followed  by  a  mandatory 
preliminary cost-sharing agreement by NRAs for the bundle of projects at the stage of the PCI 
and PMI application, and the requirement of a final cluster-CBCA decisions for the purpose of 
CEF. This measure would replace the current Offshore Network Development Plan (ONDP) and 
Sea-Basin  cross-border  cost-sharing  (SB-CBCS)  provisions  for  relevant  sea-basins.  It  would 
therefore build on existing process and initiatives such as OTC and prepare the ground for the 
possible sue of such regional planning in other areas. 

C.  Permitting  

C1. Supporting the implementation of existing legislation and issuing guidance  

Measure C.1 entails increasing the policy efforts and adopting new non-legislative measures but 
not introducing new legislative measures. In this scenario, the Commission reinforces the support 
aiming to ensure a better implementation of current permitting acceleration measures, especially 
those  of  the  revised  RED.  It  would  support  Member  States  to  implement  best  practices  in 
planning and permitting of electricity infrastructure, renewable energy and storage projects, as 
well  as  recharging  stations.  Member  States  must  intensify  their  efforts  by  ensuring  full 
transposition  and  optimal  implementation  of  the  revised  RED,  and  the  Gas  Directive,  paying 
particular  attention  to  the  permitting  and  spatial  planning  of  RES,  co-located  storage  and 
associated infrastructure. Simultaneously, they will need to invest in digitalisation of permitting 
procedures and staffing and skilling of permitting authorities. The Commission would support 
the implementation process through Commission guidance documents and strengthened dialogue 
with  stakeholders  and  Member  States’  authorities  in  existing  expert  groups  and  cooperation 
platforms managed by the Commission. Further, it would look to address the lack of capacity in 
national  permitting  authorities,  working  to  identify  technical  assistance  and  funding 
opportunities  that  could  support  necessary  investments,  reforms  and  trainings  to  simplify 
permitting  procedures  and  build  capacity  in  permitting  authorities.  Lastly,  specifically  on  the 
matter  of  environmental  assessments,  the  Commission  would  pursue  guidance  on  the 
implementation  of  environmental  legislation  in  connection  to  the  permitting  procedures.  This 
measure  would  also  leave  the  permitting  of  storage  (other  than  co-located)  and  recharging 
stations,  and  general  electricity  distribution  and  transmission  grids  without  a  dedicated  legal 
framework at EU level. 

C.2 Targeted legislative changes to accelerate permitting  

153 

 
 
Measure  C.2  involves  legislative  amendments  targeting  the  further  acceleration  and 
simplification  of  permitting  procedures  for  cross-border,  national  transmission  and  local 
distribution grids as well as renewable energy and storage projects and recharging stations. The 
amendments considered may include the following elements which may be introduced in either 
sector-specific or horizontal legislation253:  

1)  Establishing  an  EU-level  framework  for  the  accelerated  permitting  of  electricity 
distribution,  transmission  and  storage  assets,  and  of  recharging  stations,  while 
adapting  to  the  EU-level  provisions  on  hydrogen  infrastructure  with  a  scope  that 
would extend beyond PCIs and PMIs, and  include measures such as: a single point of 
contact for permitting; strengthened cooperation requirements in the permitting of cross-
border projects; maximum durations for administrative decisions aligned with the 2 year 
deadline applicable to hydrogen; introducing further requirements for the permitting of 
electricity distribution, transmission and storage assets (introducing it also to renewable 
and low-carbon hydrogen projects) and of recharging stations, on tacit approval in case 
of delays subject to certain conditions; a cut-off date for the request of additional data by 
authorities;  digitalisation,  data-centralisation  and  increased  administrative  support  of 
permitting authorities by Member States; a presumption of overriding public interest for 
electricity building on the existing provision in the revised RED  reflecting the need to 
match RES expansion with  grid development;  exemptions  from  permitting procedures 
for small installations subject to certain conditions254, electricity distribution grids and 
modernisation,  reinforcement,  repowering  and  repurposing  of  existing  electricity  grid 
assets; 

2)  To  strengthen  the  permitting  acceleration  provisions  of  the  TEN-E  Regulation: 
aligning the permitting of PCIs and PMIs with the new acceleration provisions introduced 
for  grids  in  general  (e.g.  mandatory  digitalisation  and  overriding  public  interest  for 
electricity grids) while maintaining a higher level of urgency. In addition, the following 
measures  would  be  covered  reinforcing  the  mandatory  scoping  process  in  the  pre-
application phase that identifies the extent of assessments to be carried out by promoters 
in order to clarify upfront which assessments are to be provided by the project promoter; 
reducing  the  statutory  permitting  duration  to  one  year  and  making  it  legally  binding; 
simplifying  and  clarifying  concepts  which  have  been  raised  as  sometimes    unclear 
during  implementation  such  as  the  early  public  consultation  or  the  purpose  and  legal 
character of the pre-application phase. 

3)  To  complement  and  address  potential  shortcomings  of  the  current  permitting 
framework  for  renewable  energy  projects.  Amendments  could  be  proposed  to:  (1) 
introduce new measures on important topics not covered (or only lightly covered) by 
the RED, such as measures to minimise the arbitrary identification of “exclusion” areas 
where the development  of RES is prohibited; expand the scope of the fast  and simple 
permitting  rules  to  additional  flexibility  assets  to  support  the  integration  of  renewable 
energy  into  the  system,  such  as  stand-alone  storage  assets  and  recharging  stations; 
strengthen  the  provisions  on  public  acceptance  by  introducing  obligations  on  benefit-

253  Regarding  the  amendments  proposed,  the  Commission  is  working  towards  an  Omnibus  package  in  the 
environmental  sector  to  be  adopted  in  Q4  2025,  which  may  include  provisions  to  simplify  and  accelerate 
environmental permitting and environmental assessments provisions.  
254 This should not lead to artificially slicing of projects into the smaller projects (‘salami slicing tactic’) in the context 
of  Articles  6(3)  and  12  of  the  Habitats  Directive,  Article  5  of  the  Birds  Directive  and  the  Environmental  Impact 
Assessment Directive. 

154 

 
 
 
sharing mechanisms for renewable energy projects, and measures to improve the staffing 
of authorities and digitalisation of procedures; (2) introduce measures building on the 
Council Regulation (EU) 2022/2577255 and its extension (EU) 2024/223, like solutions 
on alternative256 and compensatory measures257 (Article 3a) where scope for further 
action  may  be  warranted,  such  as  tightening  permitting  deadlines  and  reviewing 
administrative  procedures  with  regards  tacit  approval  and  data  request  to  ensure  the 
fulfilment  of  the  deadlines,  further  simplification  of  the  administrative  procedures  for 
repowering and hybridisation of assets; exempt certain projects from having to undergo 
any permitting procedure, e.g. small scale installations258. 

4)  To  simplify  and  streamline  environmental  assessments  the  Commission  could 
introduce  targeted  amendments  to  environmental  legislation259  such  as  balance  the 
responsibility  of  project  promoters  with  a  more  active  role  for  authorities  in  what 
concerns  the  identification  and  deployment  of  compensation  and  mitigation  measures, 
where the authorities could make lists of standard measures that may be considered by 
project  developers  for  application  if  relevant;  introduce  new  measures  to  simplify 
environmental assessments, such as, introducing a scoping process with a cut-off date for 
requests for additional data by authorities, as well as requiring digitalisation and data-
centralisation and requirements for environmental data. In addition to simplification, the 
Commission could consider changes as regards the effect of the overriding public interest 
provision. 

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

Measure C3. introduces 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.  This would amount to a significant change of the permitting system shifting the 
responsibility  of  monitoring  and/or  coordinating  permitting  processes  from  Member  States’ 
contact points/one stop shops260 to the EU. These coordination tasks would be taken upon by a 
permanent European coordination authority and would entail monitoring the timely completion 

255 Council Regulation (EU) 2022/2577 of 22 December 2022 laying down a framework to accelerate the deployment 
of renewable energy, OJ L 335, 29.12.2022, p. 36–44 
256 In order for projects to receive derogations provided under Articles 6(4) and 16(1) of the Habitats Directive, Article 
4(7)  of  the  Water  Framework  Directive  and  Article  9(1)  of  the  Birds  Directive,  the  competent  authorities  must 
demonstrate among other conditions that no other feasible alternative solution exists that would not adversely affect 
the  integrity  of  the  Natura  2000  site  concerned.  The  introduction  of  this  measure,  similarly  to  the  Emergency 
Regulation, aims to specify that the scope of the assessment of alternative solutions can cover solutions that ensure 
the achievement of the same objectives as the project in question within the same or similar timeframe and without 
resulting in significantly higher costs and therefore facilitate meeting this condition. 
257  Member  States  face  additional  challenges  concerning  the  requirement  to  adopt  compensatory  measures  when 
applying  the  derogation  under  the  Habitats  Directive  (92/43/EEC)  with  regards  the  plant  or  installation  for  the 
production  of  energy  from  renewable  sources,  or  the  related  grid  infrastructure  which  is  necessary  to  integrate 
renewables  into  the  electricity  system.  The  introduction  of  this  measure,  while  preserving  a  high  level  of 
environmental protection, allows for the compensatory measures to be carried out in parallel with the implementation 
of the project under strict conditions. 
258 This should not lead to artificially slicing of projects into the smaller projects (‘salami slicing tactic’). 
259  Specifically,  the  EIA  Directive,  SEA  Directive,  Habitats  Directive,  Birds  Directive  and  Water  Framework 
Directive. 
260 See Annex 6 for further details on the one stop shops, single points of contact and national competent authorities 
established under the revised RED and Gases Directive and the TEN-E Regulation. 

155 

 
 
 
of the procedures  in  line with  the EU permitting framework and liaising with  Member States 
(national and local) authorities to ensure that the necessary approvals are issued without delays 
and that projects are granted priority treatment, without the EU Authority having decision making 
powers in national procedures. Such tasks entail low risks of conflicts of interest or of authorities' 
competences. However, to ensuring the effective handling of these tasks at the European Level 
would require a significant build-up of the necessary legal and procedural expertise and practical 
capacity. 

D.  Security  

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

Measure D.1 includes provisions similar to those related to climate-adaptation under the current 
TEN-E Regulation but is focused on addressing resilience against physical malicious acts and 
cybersecurity threats to the Union’s cross-border energy infrastructure. Project promoters would 
be  required  to  include  a  risk  assessment  as  part  of  the  implementation  plan  referred  to  under 
Article  5  of  the  TEN-E  Regulation.  Lastly,  project  promoters  would,  where  needed,  provide 
details on the envisaged physical and cybersecurity mitigation measures in their annual reports, 
also  in  the  context  of  the  requirements  under  Article  5  of  the  TEN-E  Regulation.  If  project 
promoters  are  identified  as  critical  entities  under  the  EU  Critical  Entities  Resilience  (CER) 
Directive, they should build on the required risk assessments to evaluate all relevant risks that 
could disrupt the provision of their essential services and subsequently implement appropriate 
and proportionate technical, security, and organisational measures to ensure their resilience. As 
regards the risk assessment for cyber-security, project promoters should take into relevant risk 
evaluations  and  assessments  carried  out  at  Union  level,  including  assessing  impact  on  cross-
border electricity flows, using methodologies pursuant to the Network code on  sector-specific 
rules for cybersecurity aspects of cross-border electricity flows, and the results of the coordinated 
security risk assessments of critical supply chains carried out in accordance with Article 22(1) of 
the NIS2 Directive, where applicable.261 

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

Measure D.2 introduces additional transparency requirements regarding the ultimate beneficial 
owners  of  all  candidate  PCI/PMI  projects  and  their  internal  shareholder  structure.  Project 
promoters would be required to share information about their ultimate beneficial owners as part 
of  the  documentation  submitted  to  ENTSO-E  and  ENNOH  during  the  TYNDP  application 
process. This information would be treated confidentially. ENTSO-E and ENNOH would then 
be  responsible  for  forwarding  this  information  to  the  European  Commission  whenever  third-
country involvement is identified. The Commission would review this information, which would 
be taken into account in the assessment of candidate PCI and PMI projects. This information is 
also  relevant  given  that  PCIs  and  PMIs  are  considered  projects  of  Union  interest  under  the 

261 Commission Delegated Regulation (EU) 2024/1366 of 11 March 2024 supplementing Regulation (EU) 2019/943 
of  the  European  Parliament  and  of  the  Council  by  establishing  a  network  code  on  sector-specific  rules  for 
cybersecurity aspects of cross-border electricity flows 

156 

 
 
 
 
 
Foreign Direct Investment Screening Regulation and that the Commission has the right to issue 
an opinion addressed to the Member State where the foreign direct investment is planned or has 
been  completed  where  the  Commission  considers  that  a  foreign  direct  investment  is  likely  to 
affect projects or programmes of Union interest on grounds of security or public order.    

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,  including  any  equipment  or  installation 
essential to operate safely, securely and efficiently, including protection, monitoring and control 
systems. Such upgrades may not necessarily lead to an increase in cross-border capacity, but bring 
significant  cross-border  benefits  in  terms  of  resilience  and  security.  Such  equipment  would  be 
eligible for the PCI status and could subsequently benefit from CEF funding. The procurement of 
such  equipment  could  take  into  account  relevant  guidance  stemming  from  the  non-binding 
guidelines to further specify the technical, security and organisational measures that may be taken 
pursuant to Article 13 of the CER Directive, or otherwise recommendations from EU Protective 
Security Advisory Missions.   

157 

 
 
 
 
ANNEX 10: COMPARISON OF OPTIONS 

The following table provides a detailed summary table of the comparison of the three policy 
options as discussed in section 7. 

Table 16: Detailed comparison of options in terms of effectiveness, efficiency, coherence, subsidiarity and 
proportionality relative to the baseline 

PO3 
++ 
++  

++  

++ 

++ 

PO1 
+ 
 + 

PO2 
++/+++ 
+++  

++  

+++  

++  

 + 

 + 

 + 

+ 
+ 

 ++/+++ 
+++ 

+/++  
 ++ 

++ 

+++ 

+ 

+ 

+ 
+ 

++ 

+ 

+ 

++ 
++ 

++ 

++ 

+ 

+ 
 + 

++ 

++ 

++ 
++ 

++ 

++ 

++ 

+/++ 
+ 

++ 

+ 

++ 

++ 
++  

++ 

+ 

++ 

+ 
+ 

+ 

+ 

++ 

- 
- 

- 

- 

++ 

+ 
+ 

Impacts 

Effectiveness 
SO1:  Ensure  that projects  included  in network  plans  and  selected  as  PCI/PMIs 
address appropriately identified infrastructure needs 
SO2: Facilitate the use of cost-sharing tools for faster deployment cross-border 
infrastructure projects 
SO3:  Shorten  and  simplify  permitting  procedures  for  energy  infrastructure, 
renewable energy and storage projects, as well as recharging stations 
SO4: Enhance physical and cyber security and resilience of cross-border energy 
infrastructure 
Efficiency 
SO1:  Ensure  that projects  included  in network  plans  and  selected  as  PCI/PMIs 
address appropriately identified infrastructure needs 
SO2: Facilitate the use of cost-sharing tools for faster deployment  cross-border 
infrastructure projects 
SO3:  Shorten  and  simplify  permitting  procedures  for  energy  infrastructure, 
renewable energy and storage projects, as well as recharging stations 
SO4: Enhance physical and cyber security and resilience of cross-border energy 
infrastructure 
Coherence 
SO1:  Ensure  that projects  included  in network  plans  and  selected  as  PCI/PMIs 
address appropriately identified infrastructure needs 
SO2: Facilitate the use of  cost-sharing tools for faster deployment cross-border 
infrastructure projects 
SO3:  Shorten  and  simplify  permitting  procedures  for  energy  infrastructure, 
renewable energy and storage projects, as well as recharging stations 
SO4: Enhance physical and cyber security and resilience of cross-border energy 
infrastructure 
Subsidiarity and proportionality 
SO1:  Ensure  that projects  included  in network  plans  and  selected  as  PCI/PMIs 
address appropriately identified infrastructure needs 
SO2: Facilitate the use of cost-sharing tools for faster deployment cross-border 
infrastructure projects 
SO3:  Shorten  and  simplify  permitting  procedures  for  energy  infrastructure, 
renewable energy and storage projects, as well as recharging stations 
SO4: Enhance physical and cyber security and resilience of cross-border energy 
infrastructure 
Summary comparison of options (contribution to general objective)  
GO:  Timely  and  efficient  development  and  interoperability  of  resilient  trans-
European  energy  networks,  renewable  energy,  storage  and  recharging  stations 
necessary to achieve the energy and climate policy objectives  
(GO) 

158 

 
 
 
 
Term or acronym 

ACER 

AFIR 

Birds Directive 

CAPEX 

CBA 

CBCA 

CEF 

COM 

ANNEX 11: GLOSSARY 

Meaning or definition 
The  European  Union  Agency  for  the  Cooperation  of  Energy 
Regulators 

Alternative Fuels Infrastructure Regulation  

Directive  2009/147/EC  of  the  European  Parliament  and  of  the 
Council of 30 November 2009 on the conservation of wild birds 
(Codified version) OJ L 20, 26/01/2010, p. 7–25 
Capital Expenditures 

Cost-benefit analysis 

Cross-border cost-allocation 

Connecting Europe Facility 

European Commission 

CORE CCR 

Capacity Calculation Region in the Central Europe 

DLR 

DNDP 

DSO 

EIA Directive 

Electricity Market Directive 

Market 

Electricity 
Regulation 

ENNOH 

ENTSO-E 

ENTSOG 

ENTSOs 

EPBD 

EU DSO entity 

Gases Directive 

Dynamic Line Rating 

Distribution network development plan 

Distribution system operator 
Directive  2011/92/EU  of  the  European  Parliament  and  of  the 
Council of 13 December 2011 on the assessment of the effects of 
certain public and private projects on the environment OJ L 26, 
p. 1–21 
Directive (EU) 2019/944 on common rules for the internal market 
for electricity and amending Directive 2012/27/EU (recast) 
Regulation (EU) 2019/943 of the European Parliament and of the 
Council  of  5  June  2019  on  the  internal  market  for  electricity 
(recast) 

European Network of Network Operators for Hydrogen 

The  European  Network  of  Transmission  System  Operators  for 
Electricity 
The  European  Network  of  Transmission  System  Operators  for 
Gas 
Referring to both ENTSO-E and ENTSOG 

Energy Performance of Buildings Directive 

The  European  entity  for  the  cooperation  of  distribution  system 
operators 

Directive  (EU)  2024/1788  on  common  rules  for  the  internal 
markets for renewable gas, natural gas and hydrogen  

159 

 
 
Gases Regulation 

Habitats Directive 

HTNO 

Infrastructure solutions 

Non-wired 
solutions 

alternative 

NRA 
PCI 
PMI 
RED 
RES 

SEA Directive 

TEN-E Regulation 

TNDP 
TSO 
TYNDP 

Water Framework Directive 

line 

transformer 

rating,  dynamic 

Regulation (EU) 2024/1789 on the internal markets for renewable 
gas, natural gas and hydrogen 
Council  Directive  92/43/EEC  of  21  May  1992  on 
the 
conservation of natural habitats and of wild fauna and flora OJ L 
206, p. 7–50 
Hydrogen transmission network operators 
In electricity, this means installing new hardware infrastructure 
consisting of electricity cables and lines (both alternate and direct 
current,  overhead  lines  and  underground  /  undersea  cables, 
including pylons, metering infrastructure, etc.) and other related 
infrastructure such as transformers, substations, converters. 
In electricity, this encompasses other than infrastructure solutions 
as  defined  above,  including  grid  enhancing  technologies  and 
digital technologies, which can increase available grid capacity. 
Non-wired  alternative  solutions  inter  alia  include  dynamic  and 
ambient 
rating,  static 
synchronous  compensators,  advanced  power  flow  control 
systems,  phase-shifters,  digital  twin  platforms  or  synchronous 
condensers. 
National Regulatory Authorities 
Project of Common Interest 
Project of Mutual Interest 
Renewable Energy Directive 
Renewable Energy Sources 
Directive  2001/42/EC  of  the  European  Parliament  and  of  the 
Council  of  27  June  2001  on  the  assessment  of  the  effects  of 
certain plans and programmes on the environment, OJ L 197, p. 
30–37 
Regulation  (EU)  2022/869  on  guidelines  for  trans-European 
energy infrastructure 
Transmission network development plan (on a national level) 
(National) Transmission system operator 
Union-wide ten-year network development plan 
Directive  2000/60/EC  of  the  European  Parliament  and  of  the 
Council  of  23  October  2000  establishing  a  framework  for 
Community action in the field of water policy, p. 1–73 

160