COMMISSION STAFF WORKING PAPER Impact assessment
Date: 2011-10-19
Institutions: European Commission
Subjects: energy grid, financing method, gas supply, oil pipeline, project of common interest, trans-European network

EUROPEAN COMMISSION 

Brussels, 19.10.2011 
SEC(2011) 1233 final 

COMMISSION STAFF WORKING PAPER 

Impact assessment 

Accompanying the document 

Proposal for a  

Regulation of the Europen Parliament and of the Council  

on guidelines for trans-European energy infrastructure and repealing Decision No 
1364/2006/EC 

{COM(2011) 658 final} 
{SEC(2011) 1234 final} 

 
 
 
 
  
 
 
 
TABLE OF CONTENTS 

Background and policy context............................................................................................................ 3 

1. 

2. 

3. 

4. 

5. 

6. 

7. 

8. 

9. 

10. 

11. 

Procedural issues and consultation of interested parties.................................................. 3 

Context.................................................................................................................................. 8 

Problem definition ............................................................................................................... 9 

Baseline scenario ................................................................................................................ 18 

Key players and affected population................................................................................ 22 

EU right to act .................................................................................................................... 22 

Objectives ........................................................................................................................... 23 

Policy options...................................................................................................................... 25 

Analysis of impacts ............................................................................................................ 36 

Comparison of policy options ........................................................................................... 48 

Monitoring and evaluation................................................................................................ 50 

Annex 1 Glossary................................................................................................................................. 52 

Annex 2 Input documents................................................................................................................... 53 

Annex 3 results from the public consultation on permit granting .................................................. 57 

Annex 4 Outcome of stakeholder consultation among transmission system operators ................ 65 

Annex 5 Energy infrastructures priorities ........................................................................................ 68 

Annex 6 Typical project development process for an energy infrastructure project and examples 

of projects having faced permit granting delays .............................................................................. 69 

Annex 7 Key data on permit granting procedures in selected Member States.............................. 72 

Annex 8 Main reasons for public opposition to energy infrastructure projects............................ 73 

Annex 9 National electricity and gas market statistics .................................................................... 74 

Annex 10 Elements of national regulatory frameworks for electricity and gas infrastructure ... 80 

Annex 11 Project case studies concerning regulatory and financing issues................................... 82 

Annex 12 Externalities faced by energy infrastructure projects .................................................... 86 

Annex 13 Financing context for gas and electricity infrastructure ................................................ 88 

Annex 14 The current regulatory framework for infrastructure delivery .................................... 92 

Annex 15 Past and future infrastructure development in the EU .................................................. 98 

Annex 16 Evaluation of suboptions with regard to permit granting and public consultation ... 111 

Annex 17............................................................................................................................................. 116 

Challenges and corresponding measures proposed........................................................................ 116 

for permit granting and public involvement................................................................................... 116 

Annex 18 Administrative cost assessment....................................................................................... 118 

Annex 19 Impact of a 2% equity adder on transmission tariffs ................................................... 122 

2

 
 
 
 
BACKGROUND AND POLICY CONTEXT 

(TEN-E).  The  Commission  adopted 

This  impact  assessment  is  prepared  to  support  the  forthcoming  legislative  proposal  on  energy 
transmission  infrastructure  for  the  EU,  which  will  replace  the  existing  legal  framework  for  Trans-
in  November  2010  a 
European  Energy  Networks 
“Communication  on  energy  infrastructure  priorites  for  2020  and  beyond”,  supported  by  an  impact 
assessment,  confirming  the  need  to  revise  the  existing  policy  and  financing  framework,  identifying 
nine  priority  corridors/areas  to  be  implemented  by  2020  and  proposing  a  new  method  to  identify 
projects  of  common  interest  (PCIs)  to  implement  these  priorities.  The  Commission's  approach  was 
largely endorsed by the February 2011 European Council. In June 2011, a Commission Staff Working 
Paper  for  the  Energy  Council  assessed  in  detail  the  investment  needs  and  obstacles  for  the  coming 
decade. 

This impact assessment builds on the findings and conclusions of the above-mentioned documents and 
provides  a  more  in-depth  analysis  concerning  possible  measures  for  permit  granting,  regulation  and 
financing of energy infrastructure. 
The  upcoming  legislative  proposal  will  confirm  the  identified  infrastructure  priorities  and  establish 
rules  for  selection  of  projects  of  common  interest  as  well  as  their  implementation  through  permit 
granting, regulatory and whilst financing measures will be addressed in the proposal for a Connecting 
Europe Facility. 

Out  of  the  pool  of  projects  of  common  interest,  a  limited  number  of  projects  will  be  chosen  for 
funding  under  the  proposed  Connecting  Europe  Facility  (CEF),  which  the  Commission  proposed  in 
June  2011  for  the  next  multiannual  financial  framework  (2014-2020)  and  which  covers  energy, 
transport and digital infrastructure. The CEF will be dealt with under a separate regulation and impact 
assessment. 

The general  principles for financing and the criteria for eligibility of projects of common interest to 
CEF funding will be provided for in this proposal, while the CEF regulation will specify the selection 
and  award  criteria.  It  should  be  underlined  that  for  the  purpose  of  presenting  and  assessing  the  full 
range  of  possible  measures  with  regard  to  infrastructure  development,  this  impact  assessment  also 
addresses financing options, even if their translation in policy measures will take place in the CEF. 

1. 

PROCEDURAL ISSUES AND CONSULTATION OF INTERESTED PARTIES 

Identification: Lead DG: DG ENER; Agenda planning/WP reference: 2011/ENER/XXX 

1.1. Organisation and timing 

Between March and September 2010, a first impact assessment1 ("the 2010 impact assessment") was 
prepared for the Communication "Energy infrastructure priorities for 2020 and beyond – a blueprint 
for  an  integrated  European  energy  network"2  ("the  November  2010  Communication"),  which  was 
adopted in November 2010. 

The  work  for  this  impact  assessment  started  in  November  2010.  The  various  parts  of  the  problem 
definition  were  discussed  with  the  Impact  Assessment  Steering  Group  (IASG)  in  three  meetings 
between February and May 2011. The policy options and impact analysis were presented to the IASG 
in late June 2011 and the draft final IA in early July. 
Services  involved  in  the  Impact  Assessment  Steering  Group  were:  AGRI,  DEVCO,  BEPA,  BUDG, 
CLIMA,  COMP,  ECFIN,  EEAS,  ELARG,  EMPL,  ENTR,  ENV,  ESTAT,  HOME,  INFSO,  JUST, 
JRC, MARE, MARKT, MOVE REGIO, RTD, SANCO, SJ, SG, TRADE, TAXUD 

1  
2  

SEC(2010) 1395 
COM(2010) 677 

3

 
 
 
 
 
 
                                                 
1.2. Consultations and expertise 

1.2.1. 

Public consultations 

Several  specific  consultations  have  fed  this  impact  assessment.  As  early  as  November  2008  the 
Second  Strategic  Energy  Review  launched  the  Green  Paper  "Towards  a  secure,  sustainable  and 
competitive European energy network"3 on the TEN-E revision. Among respondents from the energy 
industry consensus emerged on the need for a fundamental review of the TEN-E, for the EU to better 
align the energy network policy and the EU energy and climate policy targets, to provide for a stable 
regulatory  framework,  coordination  and  raising  public  acceptance.  The  respondents  identified 
complicated  administrative  procedures,  diverging  regulatory  regimes  across  local  authorities  and 
national borders as well as local resistance as the main barriers. The absence of a specific legal remit 
at  EU  level  to  mitigate  these  obstacles  was  acknowledged.  The  role  of  the  EU  in  facilitating 
infrastructure  projects  in  third  countries  was  welcomed,  and  the  importance  of  external  energy 
relations to infrastructure policies was reaffirmed. 

Following  the  November  2010  Communication,  a  public  consultation  on  permit  granting  took  place 
between  March  and  April  2011.  The  majority  of  the  80  respondents  favours  the  introduction  of 
binding  time  limits  (60%)  as  well  as  a  "one-stop-shop"  approach  (79%)  for  energy  infrastructure 
projects.4  To  further  increase  transparency  of  the  permit  granting  process  guidelines  for  an  earlier 
involvement  of  the  public  were  considered  helpful.  This  includes  better  communication  of  the 
economic and social benefits of projects, through promoters and authorities, as well as the early and 
full  provision  of  environmental  information.  Regarding  compensation  measures,  half  of  the 
respondents believed that here competency should remain with the MS and opposed a harmonization 
on EU level. More detailed results are presented in Annex 3. 

A public consultation led by ECFIN was also carried out during the same period concerning the EU 
2020  Project  Bonds  Initiative.  More  than  130  stakeholders  from  financial  institutions,  government 
bodies,  infrastructure  development,  manufacturing,  and  research,  the  insurance  and  legal  sector 
submitted their contributions. The initiative was considered useful by most of them. 60% considered 
that  the  bond  mechanism  is  likely  to  attract  private  sector  institutional  investors  to  the  sectors  of 
transport, energy and ICT. A further 16% expected its success to be dependent on technical features of 
the mechanism (price, structure, attracted rating, etc.). Views on the project size appropriate for bond 
funding varied widely, but it emerged that the instrument is likely to be suitable for bigger investments 
with a minimum size of EUR 50 to EUR 250 million. 

1.2.2. 

Surveys, workshops and studies 

Targeted  questionnaires  on  permit  granting  and  financing  have  been  sent  to  the  main  stakeholders: 
ENTSOs in electricity and gas, GIE, national regulators and financial institutions (notably the EIB). 
Results from this consultation can be found in Annex 4. 

A  series  of  four  workshops  took  place  with  regulators  between  February  and  June  2011  to  discuss 
investments needs, cost allocation and financing. A workshop was jointly organised with the Florence 
School of Regulation in May 2011 to discuss cost allocation issues with academics and energy experts. 
All relevant issues have also been presented to and discussed with other stakeholders such as industry 
associations  or  NGOs.  Two  workshops  were  also  held  for  Member  States  in  May  and  June  2011  to 
present and discuss options for selection of projects of common interest and permit granting measures. 
The working group meetings of the Baltic Energy Market Interconnection Plan (BEMIP – electricity 
and  gas),  the  North  Seas  Countries  Offshore  Grid  Initiative  (NSCOGI  –  electricity)  and  the  North-

3  

4  

COM(2008)782 launched the public consultation between 13/11/2008 and 31/03/2009. The Commission received 
91 written replies to the Green Paper. 13 came from Member States (2 from a regional and a local government), 1 
from  regulators,  60  from  the  industry,  2  from  academia  and  13  from  individual  citizens,  NGOs  and  other 
organisations. See http://ec.europa.eu/energy/strategies/consultations/2009_03_31_gp_energy_en.htm for details. 
Approximately 20 % did not express a clear preference. 

4

 
 
                                                 
South Interconnections High Level Group for Central Eastern Europe5 (electricity, gas and oil) offered 
platforms to discuss the regional aspects of infrastructure development. 

In addition, the Commission used external expertise provided through two consultant studies on permit 
granting and financing carried out in the period January to May 2011. 

1.2.3.  Other consultations 

A high level conference under the Hungarian Council presidency on energy infrastructures took place 
on 16th and 17th May 2011, where Member States administrations, network operators, regulators and 
other  stakeholders  were  given  the  opportunity  to  discuss  the  various  proposals  of  the  Commission. 
Discussions  also  took  place  at  the  Gas  Coordination  Group  (March  and  May  2011),  the  Madrid 
(March 2011) and Florence Fora (May 2011) and at the relevant working group meetings of the Berlin 
Fossil Fuels Forum. Consultations with individual Member States have been ongoing on a continuous 
basis. 

1.3. 

Opinion of the IAB 

IAB opinion 

Changes made 

(1) Improve overall coherence with related policies 

The report should better describe how this 
initiative relates to the overriding Connecting 
Europe Facility and other EU initiatives such as 
the Project Bonds Initiative. In particular the 
report should ensure greater coherence and 
consistency with these related initiatives in terms 
of synergies, underlying market/regulatory 
failures, evaluation of results and project selection. 
The approach to financing modalities should be 
clarified. 

The problem definition should be enhanced by a 
better description of the wider context of the need 
for investment of public funds in energy 
infrastructure in particular by highlighting 
underlying problem drivers such as the market 
failure aspects. 

The relation between this initiative and the CEF 
is now described in great detail in Section 7.3. 

The 2010 IA described in detail the overall 
investment needs and the project categories 
facing particular regulatory and market failures 
justifying the use of public funds. Annex 12 of 
this IA refines the analysis of these externalities. 
The IA accompanying the Regulation for the 
CEF discusses the need for public funds further. 

Section 2.2 of the 2010 IA made a detailed 
presentation of the current TEN-E financing 
framework in the context of major future 
investment needs and related externalities and its 
shortcomings (notably insufficient resources; 
limitation to electricity and gas infrastructure; 
lack of focus; rigid list of targeted projects 
without top-down identification of priorities; 
insufficient coordination with other EU funding 

5  

This High Level Group was set up in early 2011 to promote the implementation of energy infrastructure projects 
and improve security of supply and market development in the region. It includes representatives from Bulgaria, 
the Czech Republic, Hungary, Poland, Romania and Slovakia, and Croatia as an observer. 

5

 
 
 
 
 
 
                                                 
Greater clarity concerning the content of the 
proposed legal instrument should be provided and 
the report should better explain why this Impact 
Assessment focuses mainly on problems relating 
to permit granting, regulation and financing. 

programmes). Section 3.3.3 of this IA explains 
them again. The introduction of the problem 
definition chapter has also been strengthened in 
this regard. 
The proposed Regulation will focus on the 
identification of projects of common interest and 
measures for these projects in the fields of permit 
granting, regulation and financing, which is why 
the analysis in this IA is focused on these issues. 
Section 7.3 explains the content of this initiative 
further and establishes the link with the other 
proposals. 

(2) Strengthen the subsidiarity analysis and option design 

The report should much better explain and justify, 
in terms of the principles of subsidiarity and 
proportionality, the need for EU level measures 
relating to time limits and other process and 
structural changes (such as 'one stop shops') to 
Member States' procedures for granting permits 
for energy infrastructure. 

In relation to regulatory problems, the report 
should better explain the need for EU measures on 
cost allocation and tariff setting. 

The report should discuss and underpin with 
adequate evidence the assumption that all 
identified problems, including those of an 
environmental nature, can be solved in an 
appropriate manner by a more centralised 
approach/procedure. 

The presented options should be better explained 
and justified and more nuanced options, such as 
soft law, considered in greater depth. 

The logical flow between the identified problems 
on the one hand, and the proposed policy 
options/measures on the other, should be much 
more clearly established (such as the impact of 
changes to permitting rules on public acceptance). 

The report should integrate and fully address 
different stakeholders' views on these key points. 

The description of the policy options has been 
complemented with an analysis of the measures 
with respect to the principles of proportionality 
and subsidiarity, and the identification of the 
preferred options has been more thoroughly 
justified in light of this analysis, stakeholder 
views, and the effectiveness of measures with 
regard to the overall objective of the proposal. 

The business as usual scenario now has been 
adapted with a detailed analysis on why this is a 
not option and where the internal energy market 
rules should be complemented by new rules on 
cost allocation and incentives in the tariff 
systems and regulatory framework. 

The description of the Policy Option A.2 has 
been extended to explain how a centralised 
approach would adequately address the issues at 
stake, particularly with regard to environmental 
procedures.  

The policy options have been explained in more 
detailed where necessary, particularly policy 
option A.1. A more nuanced suboption with 
respect to the establishment of time limits has 
been created, which is, due to constraints in text 
length, assessed in detail in Annex 16. 

A table illustrating how the proposed measures 
solve the identified problems has been included 
in Annex 17. 

The report was complemented by a more detailed 
description of stakeholder views in the context of 
the proposed policy options, and explanations 
were provided how these have been taken into 
account in the selection of the policy options. A 
more detailed summary of the consultation on 
permit granting procedures has been provided in 
the Annex. 

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(3) Improve the assessment of impacts 

The report should provide a more in-depth 
assessment of the impacts of the options on 
stakeholders including Member States and citizens 
particularly in relation to existing rights regarding 
planning. 

The assessment of impacts of policy options A.1 
and A.2 on stakeholders with regard to existing 
procedures provides more details on how 
Member States' authorities and citizens would be 
affected.  

The report should include a more comprehensive 
analysis of the legal implications of the preferred 
policy options concerning permit granting, which 
should be followed-up in the discussion of 
economic implications. In particular, the report 
should clarify the legal implications (e.g. creating 
a precedent, impact on other legislation) of the 
introduction of a Lex Specialis clause for Projects 
of Common Interest. 

In terms of time limits the report should assess in 
greater depth the impact of such limits on the 
fulfilment of all legal requirements, including for 
public consultation. Furthermore the report should 
assess the impact of such time limits in countries 
where the current timeframes for awarding permits 
are significantly longer than the four years 
proposed and possible spill-overs to other 
infrastructure projects. 

Summaries of relevant findings from assessments 
of impacts in earlier, related IA reports should be 
included in the report. The report should better 
explain the reasons for choosing options judged to 
be difficult to implement (such as for example the 
ex ante cost allocation mechanism). 

The report provides highlights in more detail that 
legal implications on Member States are 
expected to be relatively limited for the 
mandatory measures foreseen. However, the 
information needed to provide an analysis on 
each of the 27 EU Member States' legal 
frameworks is not available, and can therefore 
not be included in this report. The description of 
the legal implications in terms of the Lex 
Specialis with regard to the creation of a 
precedent and impact on the Waterframework 
Directive has been extended. The compatibility 
with the EU acquis will nevertheless remain 
subject to scrutiny of the Legal Service as part of 
the interservice consultation. 

A more detailed analysis of the impacts of the 
time limits has been provided for policy option 
A.2. An illustrative overview of how the time 
limits and other measures foreseen accommodate 
existing procedures, i.a. established by 
environmental legislation, is provided for under 
policy option A.3. 

The results from stakeholder consultations have 
been added in the description of the regulatory 
options and the business as usual scenario 
provides for the justification of the choice of 
options made. 

In all regulatory options the views of 
stakeholders have been added, in particular the 
preferences and design options as well as likely 
impacts with regard to their implementation. The 
ex-ante cost allocation method will provide for a 
cost allocation principle and a framework for a 
joint decision by NRas concerned on the cost 
allocation negotiations, with the involvement of 
ACER in case of disagreement. 

(D) Procedure and presentation 

The report should provide much greater 
transparency of the extent of stakeholder 
consultation and should better reflect the 
comments of all stakeholders on all major points 

The views of stakeholders on the main issues of 
the proposal have been integrated in the text, and 
are particularly discussed in the context of the 

7

 
 
throughout the main text. It should be clearer as to 
the extent that stakeholders and Member States 
have been consulted on the specific set of options 
assessed in this report. 

policy options proposed. 

2. 

CONTEXT 

The November 2010 Communication built on an impact assessment, which covered the development 
of energy infrastructures for the period 2010-2020 with a view beyond to 2030. It assessed investment 
needs  for  new  transmission  infrastructure,  evaluated  the  current  TEN-E  framework  and  financing 
possibilities and compared various policy options for implementing sufficient infrastructure to support 
the  achievement  of  the  EU's  energy  and  climate  policy  goals  in  the  most  cost  efficient  way.  The 
impact assessment analysed the design of a new  policy instrument to replace the current framework 
and expressed preference for broad priority corridors complemented by smart and transparent criteria 
for identifying projects of common interest (PCIs) at EU level, thereby building on existing regional 
cooperation initiatives.  

It  also  quantified  the  total  investment  need  at  about  EUR  200  bn  between  2010  and  2020  and 
identified  two  major  categories  of  obstacles  related  to  permit  granting  and  regulation  and 
financing.  Based  on  a  top-down  estimation,  it  valued  the  projects  subject  to  these  obstacles  and 
therefore at risk of not being delivered to approximately EUR 100 bn (also called "investment gap"). 

The  November  2010  Communication  accordingly  proposed  nine  strategic  priority  corridors  for  the 
period  up  to  2020  and  two  longer-term  priorities  (see  Annex  5),  as  well  as  a  new  approach  to 
identifying,  selecting  and  implementing  projects  of  common  European  interest,  including  through 
measures in the field of permit granting, public consultation and regulation.. 

Both the 4 February 2011 European Council and the 28 February 2011 Energy Council endorsed the 
priorities  proposed  by  the  Commission  and  expressed  support  for  the  Commission’s  approach  to 
implement these priorities, notably concerning criteria for PCI selection. The Commission presented, 
in  a  Staff  Working  Document6  to  the  June  2011  Energy  Council,  a  refined  analysis  on  investment 
needs, investments at risk of not being delivered, and measures proposed to respond to the financing 
requirements and overcome the obstacles identified. 

On 29 June 2011, the Commission adopted the Communication "A Budget for Europe 2020" on the 
next  multiannual  financial  framework  (2014-2020)7,  which  proposes  the  creation  of  a  Connecting 
Europe Facility to promote the completion of priority energy, transport and digital infrastructures with 
a single fund of EUR 40 billion, out of which EUR 9.1 bn are dedicated to energy. 

In  July  2011,  the  European  Parliament  expressed  strong  support  for  the  Commission's  proposed 
priorities,  project  selection  method  and  specific  implementation  measures8.  Concerning  the  next 
multiannual  financial  framework,  it  came  out  in  favour  of  using  the  EU  budget  to  promote  the 
development  of  energy  infrastructures  and  optimizing  the  use  of  the  budget  to  support  the  Europe 
2020 headline targets9. The Committee of the Regions also supported in July 2011 the Commission's 
approach and suggested the preparation of a corresponding detailed financing plan10. 

Building on the 2010 impact assessment, a complementary, more detailed impact assessment is now 
being presented for the legislative proposal following up on the EIP. It analyses policy options in the 
fields of permit granting / public consultation, regulation and financing that should apply to projects of 

6 
7  
8 

9 

10  

SEC(2011) 755 
COM(2011) 500/I final and COM(2011) 500/II final (Policy Fiches) 
European  Parliament  resolution  of  5  July  2011  on  energy  infrastructure  priorities  for  2020  and  beyond 
(2011/2034(INI)) 
European Parliament resolution of 8 June 2011 on Investing in the future: a new Multiannual Financial Framework 
(MFF) for a competitive, sustainable and inclusive Europe (2010/2211(INI)) 
CoR 7/2011 rev. 2 – ENVE-V-010 

8

 
 
 
                                                 
common interest selected for implementation of the defined 2020 infrastructure priorities. For each of 
the various obstacles identified, it assesses available, effective and cost-efficient solutions. 

This impact assessment does not discuss again the identification of energy infrastructure priorities and 
the choice of criteria for PCI selection to implement these priorities as these issues have been analysed 
in the 2010 impact assessment, presented in the November 2010 Communication and further refined 
since  with  all  relevant  stakeholders.  In  line  with  the outcome  of  the  2010  impact  assessment  and  as 
already  specified  in  the  November  2010  Communication,  the  Commission  has  defined  simple  and 
transparent  criteria  to  ensure  the  selected  projects  of  common  interest  contributes  effectively  to  the 
implementation of the identified energy infrastructure priorities. 

Nor does it analyse the scope of the new policy to be developed, as this was the subject of the 2010 
impact assessment, which concluded that oil and carbon dioxide infrastructures should be included in 
addition electricity and gas infrastructures, which are already covered under the current TEN-E policy. 

As  a  result,  the  infrastructure  priorities  form  the  scope  of  this  impact  assessment  and  the  upcoming 
initiative.  The  sectors  covered  by  the  priorities  are  electricity  transmission,  storage  and  smart  grids, 
gas transmission, storage and LNG/CNG, as well as transport of carbon dioxide and oil. The projects 
covered are all those projects with European significance, i.e. projects with a significant cross-border 
impact affecting at least two Member States. 

The general options regarding financing of projects of common interest are discussed in this IA for the 
purpose of presenting and assessing the full range of possible measures with regard to infrastructure 
development.  However,  the  precise  problems  related  to  EU  financing,  notably  with  regard  to 
investment  leverage  and  project  implementation,  are  also  discussed  in  the  impact  assessment 
accompanying  the  Regulation  for  the  CEF.  This  treatment  of  financing  questions  in  both  impact 
assessments  is  justified,  as  this  initiative  will  define  the  eligbility  criteria  for  financing  of 
infrastructure projects under the CEF, while the Regulation for the CEF will provide for award criteria 
and the various types of financial assistance (grants and innovative financial instruments) available for 
selected projects. 

3. 

PROBLEM DEFINITION 

The 2010 impact assessment explained the wider context of the need for private and public investment 
in energy infrastructures and highlighted in particular the scale change in both investment volumes 
and  investment  delivery  times  necessary  to  deliver  about  EUR  140  bn  worth  of  investments  in 
onshore  and  offshore  electricity  networks,  including  smart  grids11,  and  about  EUR  70  bn  in  gas 
networks  of  European  significance,  as  well  as  EUR  2.5  bn  for  the  construction  of  CO2  transport 
infrastructure  by  202012.  Investment  volumes  for  period  up  to  2020  will,  based  on  TSO  forecasts, 
increase by 30% for gas and 70% for electricity compared to current levels13. Compared to the period 
1989-2003, the needed annual investment in electricity transmission will even have to double14. This 
investment challenge and urgency clearly distinguishes energy infrastructures from infrastructures in 
other sectors, as energy networks are a precondition for reaching the 20-20-20 targets. 

These estimations did not take account of maintenance, refurbishment or new investment expenses for 
national  transmission  networks  without  European  significance  or  for  distribution  networks,  nor  of 
investments necessary for the period after 2020. The impact assessment highlighted that the identified 
European  infrastructure  priorities  will  represent  a  significant  share  of  the  investment  needs.  These 

11  

12 
13  
14 

In Europe, over EUR 5.5 bn have been invested in about 300 Smart Grid projects during the decade 2000 to 2010. 
Only about  €300  million  has come  from  the  EU  budget,  mainly through  Framework  Programme  funding.  About 
EUR  70  million  are  foreseen  under  the  Framework  Programme  for  the  period  2012/2013  on  smart  grid  topics, 
while  another  EUR  75  million  have  been  committed  for  investments  in  R&D  for  smart  cities  and  communities. 
Nevertheless, the actual deployment of Smart Grids in Europe is still at an early stage. 
See SEC(2010)1395 for more detail on the figures and the uncertainties attached to them. 
Roland Berger, 2011a. 
SEC(2010)1395.  Note  also  that  the  2006  inquiry  into  the  European  Gas  and  Electricity  Sectors  underlined  that 
"Amounts invested in cross-border infrastructure in Europe appear dramatically low. Only 200 million € yearly is 
invested in electricity grids (…)." 

9

 
 
                                                 
numbers  have  in  the  meantime  been  largely  confirmed  by  national  regulators  and  exceeded  by 
estimates  from  transmission  system  operators15.  The 2010  impact  assessment  also  estimated  that  the 
full delivery of the needed infrastructure would have significant positive overall effects on GDP and 
employment compared to BAU, with a cumulative effect of +0.42% of GDP and 410,000 additional 
jobs over the period 2011-202016. 

The  security  of  new  and  existing  energy  infrastructures,  as  a  key  element  to  ensure  their  integrity, 
reliability and climate resilience are important parts of the EU's energy policy. Infrastructure security 
is  the  subject  of  a  specific,  complementary  policy  called  the  European  Programme  for  Critical 
Infrastructure Protection (EPCIP). Given the possible impacts of events related to climate change such 
as storms, floods, heat and droughts, climate proofing of existing and even more so new infrastructures 
is  equally  important17.  Present  and  future  critical  energy  infrastructures  will  need  to  comply  with 
existing legal instruments18 in view of implementing the physical and operational measures to achieve 
a high level of security – including cyber-security – against malicious acts. Other risks, such as those 
related to natural hazards may also be addressed within this policy and other specific instruments in 
the  area  of  safety.  The  measures  necessary  to  mitigate  these  risks  will  create  additional  investment 
needs,  which  are  part  of  the  network  operators'  core  duty  of  ensuring  safe,  secure  and  reliable 
transmission  of  energy.  They  are  not  specifically  addressed  in  the  following,  as  they  can  only  be 
assessed by relevant actors in the spatial planning and development process for one or several projects. 

3.1. Problems  related  to  permit  granting  procedures  and  public  involvement  for  energy 

infrastructure projects 

Lengthy  and  ineffective  permit  granting  procedures,  along  with  public  opposition,  are  amongst  the 
major  reasons  impeding  the  timely  implementation  of  energy  infrastructure  projects,  in  particular 
electricity overhead lines. The time from start of the process to final commissioning of a power line19 
is frequently more than ten years, and the commissioning of a project which faces substantial public 
opposition can even take longer (see Annex 6 for project examples). This is of particular concern in 
view  of  the  massive  investments  in  electricity  transmission  necessary  up  to  2020  and  the  according 
number of permits to be granted20. 
In  the  context  of  a  survey  to  which  24  TSOs  responded,  16  identified  difficulties  related  to  the 
administrative  permit  granting  procedure  and  21  identified  public  opposition  as  relevant  reasons  for 
delays in the implementation of electricity infrastructure21. Results of another survey amongst TSOs of 
13 MS showed that public opposition was considered as the most important potential cause for delays 
(rating: 5.2 of 6 points), followed by complex permit granting procedures (rating: 4.5 of 6 points)22. 

15  
16  

17 

18  

19  
20  

21 

22  

See SEC(2011)755 for more detail. 
The  impact  of  developing  an  offshore  grid  would  be  particularly  positive  in  this  regard.  A  case  study  on 
Bremerhaven on the German North Sea has shown that companies in the city have attracted about EUR 250 million 
and  created  some  700  new  jobs  in  the  period  2006-2009  (Source:  EWEA,  "Oceans  of  Opportunity",  September 
2009). 
Impacts  of  climate  change  and  extreme  weather  events  have  shown  to  disrupt  energy  services  (with  significant 
costs  to  the  economy).  According  to  the IAEA,  about  half  of  the  system  faults  in  electricity  grids  are  caused  by 
weather  effects. Adapting  energy  infrastructure,  including transmission  lines,  to these  effects could, according  to 
the literature available to date, entail significant costs (see for example Vattenfall Europe (2006); Van Ierland, E.C. 
et al. (2007); ADAM project (2009); US National Research Council (2010)). Despite these first studies allowing an 
initial  discussion  of  the  issue,  its  specific  relevance  for  transmission  infrastructure  needs  to  be  further  assessed, 
based on more evidence. 
Council  Directive  2008/114/EC  of  8  December  2008  on  the  identification  and  designation  of  European  critical 
infrastructures and the assessment of the need to improve their protection 
The major phases of a typical project development process in electricity are presented in Annex 6. 
One example is the offshore grid development in the Northern Seas: According to ENTSO-E, it could lead to about 
250  offshore  cables  needing  onshore  landing  points  between  now  and  2030.  It  should  however  be  noted  that 
planning and permit granting procedures are different for onshore and offshore installations, the detail and amount 
of environmental and socio-economic spatial data used, the number of possible planning solutions and the time it 
takes to involve all stakeholders being usually higher on land than at sea. 
Acknowledging  these  problems,  TSOs  and  NGOs  have  formed  an  alliance  to  find  solutions  (Renewables  Grid 
Initiative and Smart Energy for Europe Platform), and some Member States have already introduced legislation to 
facilitate procedures (such as UK, IE, NL, DE). 
Roland Berger study on permit granting procedures, 2011. 

10

 
 
                                                 
The two main drivers causing the long delays will be examined in the following sections: 

1.  Inefficient  administrative  procedures,  notably  with  regard  to  the  organisation  of  the 

procedures, and the conduct and competences of involved parties; 

2.  Opposition of affected population 

3.1.1. 

Inefficient administrative procedures 

•  Complex  and  fragmented  process:  Although  the  stages  of  the  permit  granting  process  are 
generally  similar  in  different  Member  States,  the  concrete  procedures  within  one  phase  differ 
highly  from  one  country  to  another,  and  often  also  between  the  different  regions  within  one 
country,  particularly  in  those  countries  with  federal  structures  where  planning  competence  is  at 
regional level (Austria, Belgium)23, which makes cross-border projects even more of a challenge. 
Furthermore, permit granting processes are also generally of extremely fragmented nature. There 
are  typically  many  authorities  indirectly  whose  opinion  is  required  in  the  process.  their  number 
can  reach  up  to  50  per  project.  The  number  of  authorities  directly  involved,  i.e.  responsible  to 
issue constitutive, legally-binding permits, is usually lower, ranging between one and more  than 
ten (for data see Annex 7). If responsibility for the delivery of the permits is spread over several 
authorities, this leads to difficulties in identifying responsibilities, different interpretation of laws, 
inconsistencies in the handling of procedures, friction losses and duplication of work.  

•  Lack of upfront planning and coordination: It is in many Member States up to the promoter to 
plan  the  process  and  coordinate  the  different  bodies  and  permits,  with  limited  guidance  from 
public  administrations.  However,  due  to  lacking  managerial  resources  and  competences  of 
promoters, coordination activities are often inefficient. Lack of appropriate upfront planning and 
coordination  procedures  has  particularly  severe  consequences  for  cross-border  projects,  where 
delays  on  one  side  of  the  border  can  significantly  impede  progress  on  the  other  side.  Such 
procedures are also crucial for wind offshore infrastructure projects, which often span large areas 
such as entire regional seas. Acknowledging the benefits of an effective upfront maritime spatial 
planning, the Commission is at present carrying out an impact assessment. 

•  Lack of time limits: In many Member States there are no binding time limits in place to ensure 
that  decisions  are  taken  in  a  timely  fashion.  In  13  MSs  there  are  time  limits  for  the  entire 
procedure and/or its individual stages. However, in many MSs these are not always respected as 
enforcement  mechanisms  are  not  applied  or  do  not exist.  Surveys  show  that  the  permit  granting 
process  (i.e.  pre-application  efforts  and  statutory  administrative  procedure)  has  an  average 
duration of between four and ten years (see Annex 7 for details). Adding about three years for first 
planning efforts and construction, this leaves an average duration of 7-13 years24. 

•  Unclear  documentation  standards  and  lack  of  quality:  Specific  difficulties  arise  in  the  pre-
application phase, when usually only limited information is available regarding the elements to be 
analysed and submitted with the application, and when promoters hand in application documents 
of poor quality. This leads to cumbersome and lengthy request-response cycles between promoters 
and authorities, particularly when deadlines for additional requests are missing. 

•  EU  legislation25  and  national  legislation  have  set  high  standards  for  environmental  protection, 
which has been perceived as a major challenge by promoters during the past years. This legislation 
is  not  leading  to  delays  per  se,  nor  does  it  prevent  projects  from  taking  place,  but  the  lack  of 
coordinated implementation by national authorities has posed major difficulties for promoters, as 
the  fulfilment  of  requirements  is  often  time  consuming  and  can,  if  not  implemented  adequately, 

23  

24  

25  

Germany  adopted  a  law  in  2011  to  shift  planning  competence  from  the  state  to  the  federal  level 
(Netzausbaubeschleunigungsgesetz – NABEG). 
Judicial  procedures  are  not  included  in  this  time  frame.  To  be  noted  that  for  complex  cross-border  projects  the 
duration tends to exceed the average duration. 
Directive  2001/42/EC  on  the  assessment  of  the  effects  of  certain  plans  and  programmes  on  the  environment; 
Directive 85/337/EEC on the assessment of the effects of certain public and private projects on the environment; 
Directive 92/43/EEC on the conservation of natural habitats and of wild fauna and flora; Directive 2009/147/EC on 
the  conservation  of  wild  birds;  Directive  2000/60/EC  establishing  a  framework  for  the  Community  action  in  the 
field of water policy 

11

 
 
                                                 
lead  to  delays  in  the  process.  A  comprehensive  analysis  of  impacts  on  the  environment  may  – 
depending on the available data for the specific site concerned – take one year or more as a whole 
vegetation period or two migration seasons have to be analysed. Particular difficulties arise if the 
assessment of the implications for the site or the status of a water body is negative, and if there are 
no  alternative  solutions  available,  as  construction  is  in  this  case  only  allowed  if  the  project  is 
granted the status of overriding public interest by the national competent authority and if adequate 
compensation  measures  are  taken,  such  that  promoters  face  uncertainty  whether  a  project  can 
eventually be carried out. This issue is particularly relevant in MSs with large and scattered parts 
of land designated as Natura2000 habitats26, and in border regions, which are often along natural 
barriers of environmental significance (e.g. Pyrenees along the ES-FR border, coastal areas). 

3.1.2.  Opposition of affected population 

Opposition  by  landowners,  citizens  living  in  the  vicinity  of  potential  installations  and  stakeholder 
organisations poses the most significant impediment in the permit granting process. This is particularly 
true  for  Western  MSs,  where  citizens  seem  to  be  more  sensitive  to  (perceived)  environmental  and 
visual  impacts,  but  it  is  increasingly  the  case  also  in  new  MSs.  Public  opposition  usually  leads  to 
numerous  objections  during  consultations  (up  to  20.000)  which  have  to  be  answered  by  authorities 
and/or promoters, leading to significant additional efforts and delays in the process. Complicated and 
lengthy negotiations with landowners may also lead to delays at the stage when the developer needs 
to obtain the right to use the land in order to start construction. Lodging appeals to courts is another 
means  of  public  reaction  preventing  the  start  of  construction.  In  some  countries,  court  appeals  are 
possible  at  any  time  throughout  the  permit  granting  process  and  beyond  (e.g.  AU,  IT),  delaying  the 
process even further. There is usually less opposition to offshore projects as citizens are not directly 
affected by installations. However, strong resistance of citizens living in the vicinity of landing points 
can  prevent  the  timely  connection  of  wind  farms.  The  main  reasons  for  public  opposition,  notably 
unclarity  about  the  added  value  of  a  project,  real  or  perceived  impacts  on  the  environment  and 
landscape,  health  and  safety  concerns,  and  late  and  insufficient  involvement  of  the  public  and 
stakeholders are presented in Annex 8. 

3.2. Problems related to the regulatory framework for energy infrastructure investments 

Electricity and gas transmission are regulated sectors with costs for network investment, operation and 
maintenance recovered through tariffs fixed by national regulation, which differs from MS to MS (see 
Annex  9  and  10  for  statistics  and  relevant  elements  of  the  regulatory  framework  concerning  EU 
electricity and gas markets and networks). In most MSs, cost recovery for projects is based on verified 
national  market  needs  and  cheapest  available  solutions,  in  order  to  ensure  cost-efficiency  and  keep 
tariffs  low  for  national  consumers27.  The  existing  framework  is  therefore  not  geared  towards 
delivering the identified European infrastructure priorities in view of further integrating the European 
energy networks and meeting the European climate and energy objectives. 

It should also be noted that the commercial viability and hence the "bankability", i.e. capacity to attract 
commercial  financing,  of  infrastructure  projects  is  intrinsically  linked  to  the  regulatory  framework. 
Infrastructure operators and investors have repeatedly called for a stable and incentivising regulatory 
framework with adequate long-term signals, notably for cross-border investments. The way, in which 
investments  costs  and  risks  are  treated,  directly  determines  the  return  and  hence  influences  the 
incentive  to  invest  or  to  lend  money  for  a  project.  At  the  same  time,  changing  conditions  in  capital 
markets can influence regulation for such investments (see also section 3.3). 

The  three  main  shortcomings  with  regard  to  the  regulatory  framework,  which  hinder  cross-border 
infrastructure  investments,  are  described  in  the  following.  Examples  of  electricity  and  gas 
infrastructure projects subject to regulatory difficulties are given in Annex 11. 

26  
27  

E.g. 30% in the case of Slovenia. 
Transmission tariffs account on average for only about 5-10% of household electricity prices across EU MSs. 

12

 
 
 
                                                 
3.2.1.  Asymmetric benefits and externalities 

With  national  energy  networks  becoming  both  more  decentralised  and  increasingly  interdependent, 
cross-border  projects  between  at  least  two  –  isolated  or  well-interconnected  –  Member  States  or 
projects in one MS with significant cross-border impact multiply, which either feature an asymmetric 
distribution  of  costs  and  benefits  among  beneficiaries,  or  offer  externalities  not  appropriately 
internalised  by  either  market  signals  or  the  existing  regulatory  system.  These  two  categories  partly 
overlap, as many of the externalities discussed also have a cross-border, supranational dimension. 

Concerning  asymmetric  impacts,  a  new  internal  electricity  line  can  benefit  the  origin  country  by 
reducing its internal congestions, but also border countries by increasing transits. A gas reverse flow 
infrastructure on the territory of one Member State can be for the sole benefit of its neighbour, if the 
latter has only a single other gas supply route. Similarly, a new cross-border line (e.g. Austria-Italy in 
electricity,  Hungary-Slovakia  in  gas)  can  de  facto  permit  to  increase  transit  for  both  the  immediate 
neighbours and third countries, which are indirect beneficiaries. 

As a result, internal as well as cross-border investments can positively impact the functioning of third 
country  networks,  without  any  explicit  participation  from  the  concerned  network  operators  to  the 
incurred  investment  cost28.  This  leads  to  a  significant  problem  of  free  riding  due  to  the  asymmetry 
between  benefit  distribution  and  cost  allocation29.  In  gas,  the  investment  risk  for  new  transmission 
networks is moreover strongly linked to the upstream and downstream commitments. 

In addition, the more MSs are interconnected with each other, the more the identification of benefits 
can be complex and difficult to predict. Indeed, the benefits of a new electricity line on the territory of 
two  MSs  but  benefiting  several  others  indirectly  can  be  very  difficult  to  predict  for  the  indirect 
beneficiaries, as these benefits depend on various factors such as long term price differentials, which 
themselves are influenced by a large set of parameters (generation mix in the exporting and importing 
country, support schemes for renewables, future other transmission lines). Given these uncertainties, 
benefits and revenues might not be quantifiable at all ex ante. 

Today, there is no common European or region-specific framework for benefit identification and cost 
allocation.  For  more  complex  projects,  this  absence  has  often  led  to  complex  and  lengthy  decision-
making  negotiations  between  individual  operators  and  national  regulatory  authorities  or  even  made 
certain projects impossible to realise30. More specifically for gas, the lack of transparent, timely and 
efficient coordination across borders creates uncertainty to market participants and risks for network 
operators31. Under today's narrow framework, operators today have few incentives to develop cross-
border investments when benefits go to another area. 

Concerning  externalities,  they  are  positive  or  negative  impacts  provided  by  a  given  infrastructure 
investment, which are not properly reflected by existing market  signals and revenue streams, i.e., in 
the  case  of  regulated  grids,  transmission  tariffs  and,  in  electricity,  congestion  rents32.  In  some  cases 
increasing the capacity or the electricity grid to the optimum level even decreases the congestion rents. 
While the socio-economic benefit, notably at regional or EU-wide level, of a project providing such 
externalities  would  outweigh  its  cost,  the  investment  will  not  take  place  if  it  is  based  on  a  merely 
corporate  based  commercial  viability  evaluation  or  on  optimising  national  interests  in  one  MS.  The 

28  
29  
30  

31  

32  

In its draft position paper on cost allocation, CEER calls these benefits “commercial externalities”. 
Cf. Glachant and Kalfallah, 2011 
The  Kriegers  Flak  project  is  an  excellent  example:  It  initially  envisioned  the  development  of  three  wind  farms 
within  German,  Swedish  and  Danish  waters,  linked  by  a  combined  offshore  grid  connection,  which  would  also 
serve  as  an  interconnection  between  the  three  countries.  The  three-country  solution  has  in  the  meantime  been 
abandoned with Sweden's withdrawal, and the development of the project has been delayed because of regulatory 
challenges, despite EUR 150 million of EU funding received in the context of the European Energy Program for 
Recovery. 
The 2006 sector inquiry had already outlined that on certain borders, long-term pre-liberalisation gas transmission 
capacity  reservations  still exist despite the  ruling  of  the  European  Court  of  Justice  that  such  reservations  are  not 
compatible with EC law, unless they were notified under Directive 96/92/EC. 
In  its  draft  position  paper  on  cost  allocation,  CEER  calls  the  externalities  discussed  under  this  category  “non 
commercial externalities”. 

13

 
 
                                                 
main categories of externalities were already discussed in the 2010 impact assessment and are further 
detailed in Annex 12. 

3.2.2.  Lack of appropriate regulatory incentives and long-term signals to meet EU priorities 

Compared to the European infrastructure priorities and the EU's energy and climate policy objectives, 
such  as  the  20-20-20  targets  for  2020  or  the  80-95%  emission  reduction  objective  for  2050,  the 
existing  regulatory  framework  does  not  give  appropriate  incentives  and  long-term  signals  for  the 
implementation  of  all  projects  necessary  to  meet  these  priorities.  NRAs  have  so  far  not  sufficiently 
taken  account  of  the  corresponding  investment  challenge  for  networks  up  to  2020  and  beyond  and 
their specific responsibility under the third market framework for making these investments happen. 

In  addition,  given  their  cross-border  nature  and  the  broader  benefits  and  positive  externalities  they 
provide as described in the previous section, projects of common interest in particular will often face 
additional  technological  or  operational  risks.  Given  the  additional  effort  their  development  implies, 
operators will be reluctant to enter into the development of these projects. And without adequate return 
on investment, investors and banks will discard these projects compared to other "standard projects" 
with a lower but more certain risk-return profile. This will further endanger the timely implementation 
of the EU's infrastructure priorities. 

Some  countries  have  recently  introduced  –  in  addition  to  the  existing  third  market  legislative 
framework  (see  section  1)  –  additional  incentive  schemes  in  their  regulatory  framework  to  promote 
certain categories of investments. France (for gas) and Italy (for electricity and gas) for example give 
explicit  incentives  for  congestion  reduction  and  cross-border  investments.  Some  NRAs  have  also 
introduced explicit incentives for innovation (UK, Italy). 

Member State 
Austria 

France 
Germany 

Italy 
Great Britain 

Netherlands 
Portugal 

Spain 

Incentive Scheme 
Possible ex-ante consideration of extraordinary investment costs (project specific mark-
up of 0.20% for gas) 
Gas: New investments can receive ROR add-on upon decision by the regulator 
Investment budgets are approved for expansion investments by the regulator upon certain 
conditions. After a certain period, the investment budget is transferred into the RAB. 
Investment premiums of 2%-3% for certain categories of investments 
Specific innovation incentive schemes for low-carbon outputs (e.g. Networks Innovation 
Competition,  Innovation  Allowance,  Revenue  Adjustment  Mechanism,  Transmission 
Investment for Renewable Generation (TIRG)) 
Extra income for substantial investments upon decision by the regulator 
Gas: Cost of capital and amortisation are smoothed for the whole concession period (e.g. 
40 years). 
Investment allowances 

Table 1: Existing national transmission investment incentive schemes (source: CEER) 

However,  such  mechanisms  exist  only  in  certain  Member  States,  remain  limited  with  regard  to  the 
types of investment they cover and are only partly in line with the EU's infrastructure priorities. 

Finally,  it  should  be  noted  that  investment  signals  and  tariffs  are  intrinsically  linked  as  the  tariff 
methodology sets the main conditions for the recovery of the investment costs for regulated networks. 
NRAs decide on cost allocation via the tariff setting in accordance with national preferences, user and 
network  particularities.  NRAs  will  therefore  be  reluctant  to  provide  by  themselves  incentives  for 
projects  of  common  interest,  which  might  negatively  impact  their  national  customers  for  the  shared 
and bigger overall benefit of costumers in several other Member States. 

3.2.3.  Lack of coordination for cross-border investment approval process 

As projects of common interest will by definition affect at least two Member States, they will require 
approval of at least two NRAs for the corresponding investment, notably with regard to cost allocation 
among the two Member States involved. Coordination of procedures on both sides of the border for 
such approval is crucial to prevent delays or obstacles for the realisation of such projects. 

14

 
 
This  is  even  mort  important,  as  national  regulations  differ  with  regard  to  the  way,  in  which 
investments are accounted for and remunerated. For the gas sector, the 2009 KEMA study concluded 
that differences in commercial viability of the same project according to the different national regimes 
could create a serious barrier to investment: "Investors will compare the return with similar projects in 
terms of risk and allocate their money accordingly". Concerning specifically open seasons, CEER and 
the  Gas  Regional  Initiative  North-West  have  underlined  difficulties  related  notably  to  different 
regulatory  rules  applying  in  different  MSs,  the  uncoordinated  launch  of  open  seasons,  the  lack  of 
transparency due to invoked confidentiality by market operators and the insufficient reliability of the 
non-binding bidding phase33. 

Concerning electricity, experts working on regulatory issues for offshore grid development under the 
NSCOGI recognised that "the regulatory regimes for offshore transmission are different and may need 
to  become  more  consistent  in  future  if  coordinated  development  is  to  be  achieved".  They  noted 
"notable  differences  in  grid  charging  regimes  and  procedures  between  the  countries  and  these, 
together with the different levels of renewables support, could lead to developers seeking to locate in 
areas with low connection charges and high support mechanisms resulting in sub-optimum siting"34. 

However,  cooperation  among  NRAs  and  TSOs  for  cross-border  investments  and  attempts  at 
coordinating  procedures  have  proved  to  be  difficult  and  cumbersome,  thereby  creating  delays  in 
project approval and delivery (e.g. Dutch-German or Bulgarian-Greek cooperation in gas or Franco-
Spanish cooperation in electricity).35 

3.3. 

Problems related to financing of energy infrastructure projects 

Energy infrastructure projects are primarily financed by the private sector. Most commonly corporate 
financing  is  used:  TSOs  develop  projects  with  their  own  capital  (balance  sheet)  and  loans  from 
commercial  banks  and  international  financial  institutions36.  Project  finance,  where  the  long  term 
financing is only based upon the projected cash flows of the project rather than the balance sheets of 
the  project  sponsor,  is  used  only  rarely37  (see  Annex  13).  Moreover,  in  order  to  increase  their 
investment  capacity,  TSOs  may  seek  corporate  equity  investments  from  other  companies  (also  from 
outside the energy sector). Such companies offer additional capital in return for participation in profits 
generated by the TSO’s projects. 

While this system functions rather well in a predictable and stable regulatory environment, there are 
factors, which make the financing of infrastructures – notably those of cross-border nature targeted by 
this  initiative  –  difficult38.  Financing  will  be  even  more  challenging  for  projects  with  low  or  no 
commercial viability, which are often those falling into the categories listed in section 3.2.1. Because 
of  their  high  economic,  social  or  environmental  benefits,  public  funding  would  be  fully  justified  to 
trigger an investment decision for such projects. Nevertheless, the existing support is insufficient both 
in form and available volumes. The three main factors likely to hinder investments are discussed in the 
following. 

33  

34  
35  

36  

37  

38  

CEER,  "Monitoring  Report  2010  on  the  compliance  with  the  Guidelines  of  Good  Practice  of  Open  Season 
procedures  (GGPOS)",  Ref:  E10-GMM-11-04,  7  December  2010;  ERGEG  Gas  Regional  Initiative  North-West 
(GRI NW), "Open Season Coordination", 28 April 2009. 
NSCOGI Working Group 2, "Report to the Steering Committee", May 2011 
It should be noted that this impact assessment does not examine in further detail, how different national regulatory 
regimes  by  themselves  impact  investment  decisions  and  to  what  extent  harmonisation  would  be  beneficial.  This 
question will be addressed under the third package framework (see section 1). 
TSO equity in projects typically varies between 20%  and 100% of the total investment depending on the project 
risks and scale. 
As a general rule, if a project lies within the TSO's service area and is mainly linked to domestic transmission or 
distribution  (gas)  or  uses  alternating  current  technology  in  a  meshed  grid  (electricity),  TSOs  will  use  corporate 
financing.  Project  financing,  which  implies  setting  up  a  special  purpose  company,  is  used  for  larger,  specific 
projects such as LNG terminals, storage, merchant lines or complex joint ventures (e.g. mid-stream and some cross-
border pipelines) in gas and high-voltage direct current lines or storage in electricity. 
It should be noted that the financing challenges identified vary between Member States. 

15

 
 
 
                                                 
3.3.1.  Limited financing capacities of TSOs 

In  view  of  the  scale  change  in  both  investment  volumes  and  investment  delivery  times  necessary  to 
deliver on the energy infrastructure priorities until 2020, many TSOs, especially in eastern European 
Member States, will reach the limits of their financing capacity. The volumes of new investments will 
exceed the financing possibilities offered by their balance sheet size. Both debt and equity providers 
have confirmed that, given the levels of available equity, TSOs will face challenges raising sufficient 
amounts  of  debt  at  reasonable  cost,  especially  because  of  borrowing  ceilings  or  the  absence  or 
insufficiency of investment grade ratings, as lenders are not going to accept higher debt/equity ratios. 
Therefore, certain TSOs could need large equity injections by private investors or public owners to be 
able to contract more debt for their future investment programmes. Partly or fully state-owned TSOs 
will depend to a large extent on their government. Given the very difficult budgetary situation of most 
EU  MSs,  it  is  unlikely  that  they  will  accept  significant  equity  injections.  This  is  especially 
handicapping when extensive investment plans exist and TSOs already have a high debt/equity ratio 
(70/30 or more), as is the case for National Grid or Tennet. 

In  addition, TSOs  are  increasingly  facing  difficulties  with  accessing  long-term  debt  on  favourable 
terms.  Following  the  financial  crisis,  banks  have  reacted  with  a  radical  shortening  of  maturities, 
increased  pricing  and  collateral  requirements.  Basel  III  rules39  will  require  banks  to  keep  a  higher 
percentage  of  equity  on  their  balance  sheets.  Long-term  capital  commitments  for  infrastructure 
projects  will  become  more  expensive  and  difficult  to  execute.  Furthermore,  lending  conditions  have 
appeared  to  be  insufficiently  adapted  to  project  and/or  corporate  needs  of  TSOs  (loan  duration  too 
short, impossibility to make a substantial bullet payment at the end of the loan, limited flexibility, no 
bridge  financing  offered  between  the  construction  phase  and  the  operational  phase)40.  As  a  result, 
banks  will  favour  less  complex  and  bigger  unitary  transactions  over  more  complex,  innovative  or 
riskier projects. Furthermore, access to EIB loans may become more difficult for certain TSOs41. 

These constraints will affect a TSO’s ability to deliver on its overall investment programme (including 
infrastructures  of  European  and  of  solely  national  relevance).  PCIs  will  have  to  compete  for 
investment  budget  with  national  priorities.  Given  the  increasing  constraints  on  lending  capacities, 
bond  markets  to  raise  larger  debt  volumes  could  play  an  increasingly  important  role  in  the  coming 
years.  However,  issuing  bonds  implies  that  TSOs  have  a  solid  credit  rating.  Today,  however,  about 
40% of TSOs in Europe (gas and electricity) are not rated42 and therefore have no access to funding 
from bonds and private placements. As energy networks are regulated, an increase in tariff levels for 
energy consumers could be an alternative way to raise capital to finance new investments. However, 
there are important social and political limits to increasing tariffs (see chapter 10). 

3.3.2.  Difficulties for energy infrastructure investments to attract new institutional investors 

Institutional investors such as pension funds, insurance companies and wealth funds are increasingly 
moving  into  infrastructure  investment  given  its  potential  to  match  long-term  assets  and  provide 
diversification.  The  stability  provided  by  the  regulated  model  corresponds  to  pension  funds’ 
investment  profile,  characterized  by  relatively  low  rates  of  return  –  around  7%-8%43  –  and  long 
investment  horizons.  These  investors  are  also  becoming  increasingly  ready  to  invest  directly  in 
infrastructure  assets.  This  is  new,  as  their  exposure  to  infrastructure  has  traditionally  been via  listed 

39  

40  
41  

42  
43  

The Basel III global regulatory standard will come into force in 2013. It strengthens bank capital requirements and 
introduces new requirements on bank liquidity and bank leverage. 
Roland Berger, 2011a. 
Loans from the EIB are seen as the most important component of debt financing by many TSOs, especially smaller 
TSOs  in  Eastern  Europe.  Many  TSOs  have  reached  limits  with  regard  to  how  much  unsecured  lending  they  can 
receive from the EIB. As a general principle, the EIB aims at not providing more than 10% of unsecured lending 
compared to a TSO's equity. In the EU15 TSO sector, the EIB already is often already above this ceiling. In most 
EU12 Member States however, the EIB does not yet agree to higher unsecured lending and requires bank or state 
guarantees. 
Roland Berger, 2011a. 
Compared to 10%-12% infrastructure funds typically offer their investors. Source: InfraNews, “How Real a Threat 
to Infra Funds is the Direct Investing Phenomenon?” 24 May 2011. 

16

 
 
                                                 
companies  (such  as  utilities),  or  via  real  estate  portfolios44.  Their  role  as  financiers  for  TSOs  and 
dedicated infrastructure project companies is therefore expected to rise. 

However,  the  arrival  of  such  new  classes  of  investors,  which  might  have  different  expectations 
concerning  the  risks  incurred  compared  to  current  regulatory  practice,  may  require  regulatory 
adaptations.  Furthermore,  there  need  to  be  investment  opportunities  available,  i.e.  equity  opened  to 
participation  and/or  debt  products.  The  fact  that  to  date  only  some  TSOs  are  fully  open  to  equity 
investment from third parties, given their ownership structure (see Annex 13, Figure 16 and 17), limits 
the inflow of capital from institutional investors and will not help to ease the investment challenge in 
the short to medium term. 

3.3.3.  Lack of adapted funding instruments and sufficient envelopes 

The  2010  impact  assessment  already  described  the  available  financing  under  the  existing  TEN-E 
programme  (in  its  Annex  2)  and  its  shortcomings  (notably  limited  budget,  inflexibility,  no  risk 
mitigation instruments, no funding outside the EU, insufficient synergies with other EU funds). It also 
highlighted the positive contribution made by the European Energy Programme for Recovery45, which 
has responded to some of the weaknesses identified, but was a one-off exercise. 

In  addition,  energy  infrastructrures  today  can  benefit  from  the  support  of  Structural  and  Cohesion 
Funds. Under the 2007-2013 budget, EUR 1.6 bn have been allocated to Member States for projects 
classified as TEN-E. However, available funds have seen only a slow uptake by Member States. The 
programming approach makes it less flexible to shift funds between projects and programmes, even if 
they are seen as particularly relevant from the EU energy policy perspective at a certain point of time. 
The  funds  are  not  centrally  managed,  which  makes  it  difficult  to  coordinate  across  and  between 
countries to ensure the regional network benefits of investments. 

European  energy  infrastructures  can  also  benefit  from  grant  support  under  the  EU  research 
programmes.  Such  support  is  important  from  the  technology  development  and  demonstration 
perspective, but it does not contribute directly to the construction of industrial-scale projects. 

The  table  below  summarises  the  financial  efforts  at  EU  level  to  support  the  development  of  energy 
infrastructures during the current financial period (2007-2013). 

Funds allocated within 
financial perspective 2007-
2013 

Electricity and gas 
infrastructure 

3 500 – 7 000 

155 
2 268 

1 607 

150 

Funds spent/committed 2007-2009 

Gas infrastructure 

Studies  Works 
3 407 
- 
7 
1 352 

- 
- 
22 
11 

Electricity 
infrastructure 
Studies  Works 
2 561 
488 
18 
903 

- 
- 
23 
2 

24 

8 

- 

- 

50 

- 

7 680 – 11 180 

4 823 

4053 

IFI 

EU 

EIB 
EBRD 
TEN-E 
EEPR 
Structural 
Funds 
RTD 
Framework 
Programme 
Total IFI and EU 
funds 

Table 2: Total funds (loans and grants) from EU institutions allocated to electricity and gas infrastructure 
within financial perspective 2007-2013 (* EEPR: Some infrastructure projects related to works include studies) 

44  

45  

OECD,  "Pension  Fund  Investment in  Infrastructure",  Working Paper  on  Insurance and  Private Pensions,  January 
2009. 
Regulation  (EC)  No  663/2009  of  the  European  Parliament  and  of  the  Council  of  13  July  2009  establishing  a 
programme to aid economic recovery by granting Union financial assistance to projects in the field of energy (OJ 
L200, 31.7.2009) 

17

 
 
 
 
 
 
 
 
 
                                                 
The range of financial tools available at EU level to promote projects of common interest is for the 
moment effectively limited to grants. There are no specific “innovative financial instruments”, which 
would support projects in a different manner than just by reducing the initial capital expenditure for 
investors.  There  is  no  possibility  to  provide  risk  capital  to  projects46.  There  are  also  no  risk  sharing 
arrangements,  through  which  the  Commission  could  enable  financial  institutions  to  provide  sector 
specific  lending  facilities  (loans  on  adapted  terms,  guarantees,  facilitation  of  direct  market  (bonds) 
financing)47 addressing the risks of specific projects. The existing tools do not allow for using the EU 
budget to accelerate project preparation by e.g. providing start-up capital. 

With a growing number of complex and cross-border projects of European importance, well designed 
equity or debt instruments would be likely to assist them in facilitating access to equity and/or debt 
finance,  reducing  the  cost  of  capital,  adapting  lending  conditions  to  better  match  project  cash  flows 
and  facilitating  project  finance  structuring  through  standard  equity  and  debt  instruments.  It  is  also 
essential to note that such form of support would come at a lower expense to the public budget (higher 
leverage)48. It should however be noted that innovative financial instruments will never be the remedy 
for all types of projects, especially if project financing is a prerequisite. Such instruments can only be 
used for projects which generate sufficient revenues to repay their debts and remunerate for financial 
support received – hence the need for the commercial viability of projects. 

4. 

BASELINE SCENARIO 

This chapter looks at how energy infrastructures would develop over the coming decades, should no 
further  policy  actions  be  taken.  It  builds  on  the  chapter  "Baseline  scenario"  of  the  2010  impact 
assessment, which presented the methodology used for the energy infrastructure needs assessment and 
analysed  the  resulting  energy  trends  and  infrastructure  needs.  The  findings  of  this  chapter  are  not 
repeated here. In the following, we do however, on the basis of a detailed assessment of the current 
policy  framework  in  Annex  14,  analyse  how  much  and  which  type  of  infrastructure  would  be 
delivered and which one not, if no further action was taken. This allows us to refine the analysis of 
investments  at  risk  of  not  being  delivered  when  needed  ("investment  gap"  in  the  2010  impact 
assessment). 

As  already  highlighted  in  the  2010  impact  assessment  and  as  described  in  the  previous  section,  the 
current  planning,  permit  granting,  regulatory  and  financing  framework  for  energy  infrastructure 
development will lead to significant under-delivery of infrastructures under business as usual (BAU). 

Insufficient top-down prioritisation and cross-border planning will not allow focussing attention 
on  those  infrastructures,  which  bring  the  highest  value  added  in  view  of  reaching  the  2020  energy 
policy targets. As a result, there is a high risk of projects of common European interest not receiving 
the political attention they need to be pushed trough by 2020. 

Persistent  delays  due  to  complex  and  lengthy  permit  granting  procedures  and  low  public 
acceptance  will  further  delay  new  infrastructure  projects,  notably  in  electricity.  Under  business  as 
usual, the real duration of the statutory authorisation procedure would continue to vary between less 
than  2  years  and  10  years  depending  on  the  Member  States,  with  an  average  of  about  4  years  (see 
Annex 7). In many Member States, public resistance to new infrastructure projects would increase this 
duration by a significant amount of years due legal recourse procedures. The efforts associated with 

46  

47  

48  

The Marguerite Fund, to which both the Commission and the EIB have contributed, is expected to invest also in 
energy projects. However, the high yield expectation is likely to exclude typical energy transmission projects. 
Such  risk  sharing  instruments  have  already  been  developed  for  other  sectors.  Since  more  than  ten  years,  the  EU 
budget  has  been  using  financial  instruments.  Under  the  2007-2013  financial  framework,  a  new  generation  of 
financial instruments has been put in place in cooperation with the EIB, such as the Risk-Sharing Finance Facility 
(RSFF) under the 7th R&D Framework Programme, or the Loan Guarantee Instrument for TEN-T projects (LGTT). 
Although fragmented, experience until now with financial instruments has been positive in these sectors. Court of 
Auditors' reports have generally praised the effectiveness of these instruments, with exceptions in certain cases. 
Market  based/innovative  instruments  are  characterised  by  a  higher  leverage  (in  comparison  to  grants)  and  their 
potential to generate revenue for the body that provides them (unlike grants, they do not come for free) 

18

 
 
                                                 
 
the  permit  granting  procedure  could  exceed  10%  of  total  project  costs49,  thereby  also  increasing  the 
investment  and  the  overall  electricity  system  cost  and  binding  resources,  which  could  be  used  more 
efficiently for the actual investments necessary in grid infrastructure. 

In line with the results of the 2005 "TEN Energy Invest" study already presented in the 2010 impact 
assessment, the ratio “performed investments” on ”scheduled investments” in  electricity could be as 
low as 50% for the coming decade, given the increased levels of local opposition and associated media 
focus  on  certain  projects  since  200550.  This  business-as-usual  scenario  can  be  compared  to  the 
planning presented in the 2010 electricity TYNDP: Despite conservative estimates for commissioning 
dates,  almost  30%  of  all  projects  identified  foresee  completion  in  or  after  2020  or  have  not  set  a 
commissioning  date  at  all.  This  applies  in  particular  to  35  transboundary  projects  listed  in  the  2010 
TYNDP. 

Applying these results to the total investment needs in electricity of EUR 100 bn (excluding smart grid 
investments), it can be estimated that up to EUR 50 bn worth of projects could be subject to delays 
beyond  2020  and  jeopardize  the  efforts  of  the  EU  to  meet  the  Union's  2020  energy  and  climate 
objectives. This number has been largely confirmed by national regulators51. 

Concerning  requirements  set  by  environmental  legislation,  an  analysis  of  the  current  TYNDP 
showed  that  about  20  projects  may  face  difficulties  due  to  conflicts  with  Natura2000  areas.  EU 
environmental  legislation  leaves  substantial  flexibility  to  the  MS  competent  authorities  to  solve  the 
conflicting objectives between security of supply and renewables integration and the protection of the 
local  wild  life.  If  these  conflicts  are  not  satisfactorily  solved,  some  of  these  energy  infrastructure 
projects may be not be delivered. 

Nationally  focused  regulation,  lack  of  cost  allocation  solutions  and  difficult  coordination  between 
NRAs  and  TSOs  would  further  delay  the  realisation  of  projects  with  cross-border  impacts  and 
increasingly  asymmetric  costs  and  benefits.  This  will  particularly  affect  the  implementation  of  the 
identified infrastructure priorities, which are mainly based on cross-border or even regional projects. 
Insufficient risk-related incentives in line with policy objectives could lead to lock-in situations with 
infrastructures,  which  in  the  short  term  contribute  to  energy  and  climate  policy  objectives  (e.g. 
emission savings) but generate fewer benefits in view of longer term objectives. 

Concerning  electricity  interconnectors,  between  2000  and  2011,  about  30  cross-border  electricity 
projects involving EU Member States have been commissioned, out of which 25 concerned new lines 
(see list in Annex 15). By comparison, the 2010 TYNDP foresees a total of 76 cross-border projects, 
out of which 58 projects concern new lines for a total value estimated by the Commission at over EUR 
31  bn.  In  the  absence  of  new  cost  allocation  rules,  it  is  unlikely  that  existing  regulation  and  new 
measures described above alone will allow completing the internal market, while adapting effectively 
to  the  fast  rising  electricity  flows  from  variable  renewable  generation  and  the  ensuing  needs  for 
balancing  and  storage  capacities,  in  a  context  of  rapidly  changing  national  energy  policies52.  This 
could also endanger the reliable operation of the European electricity grid as a whole53. Assuming a 
business-as-usual  development  pace,  only  about  25  out  of  the  58  needed  interconnectors  can  be 
expected to be online by 2020. This would leave about 30 projects or EUR 16 bn at risk. 

49 
50 

51  

52  

53  

This estimation is based on empirical data provided by various TSOs. 
The  ratio  is  even  lower  in  the  case  of  Germany:  The  2010  DENA  network  study  II  identifies  a  need  of  grid 
extension  of  3,500km  between  2015  and  2020.  A  first  DENA  study  in  2005  had  estimated  a  need  of  850km,  of 
which less than 100km have so far been completed. 
"The  CEER  survey  suggests  that  the  volume  of  investments  being  delayed  due  to  planning  procedures,  licensing 
and  lack  of  public  acceptance  is  likely  to  be  significantly  higher  [than  EUR  40  bn,  the  initial  Commission 
estimate]."  ("European  Infrastructure  Package:  Investment  needs  and  financing  mechanisms  –  Financing  Task 
Force conclusions", reference C11-FTF-02-01, 23 March 2011). 
Following  the  tsunami  and  ensuing  nuclear  accident  at  Fukushima  (Japan)  in  March  2011,  Germany  decided  in 
June  2011  to  phase  out  its  nuclear  power  generation  capacities  by  2022,  while  a  referendum  in  Italy  reverted  a 
previous decision to develop new nuclear power plants. Several other Member States are currently reconsidering 
their approach to nuclear approach. This will have important consequences on the electricity mix until 2020 and 
beyond, with corresponding impacts on the need for additional electricity and gas transmission infrastructure. 
Certain Central European operators in particular are warning about massive electrical power flows of insufficient 
control, which could lead to bulk outages of supply and, under extreme conditions, even a total blackout. 

19

 
 
                                                 
Concerning more specifically offshore grids in the Northern Seas, under business-as-usual with merely 
national  regulatory  frameworks  and  without  general  cost  allocation  rules  or  risk-related  incentives, 
internationally  optimised  solutions  –  including  direct  connection  of  wind  farms  to  international 
interconnectors or interconnectors between two wind farm hubs – will not be developed, while radial 
solutions  will  continue  to  be  the  preferred  option  of  TSOs  connecting  new  individual  wind  farms54. 
This would affect roughly EUR 10 bn out of a total investment of EUR 30 bn foreseen up to 2020 and 
prevent offshore grids from starting to develop into a meshed network already by 202055, increasing 
long-term costs and preventing optimal renewables and market integration at European level, also in 
view of developing a continental electricity highways system. 

Concerning innovative investments in electricity storage and smart grids, it can be expected that these 
will  progress  only  at  slow  pace  under  BAU,  given  the  risks  inherent  to  such  projects,  the  uncertain 
allocation of costs and benefits and the insufficiency of existing incentives. With regard to smart grids 
in  particular,  failure  to  act  at  EU  level  might  also  lead  to  insufficient  integration  of  large-scale 
renewables  capacities  and  deployment  of  electric  vehicles  as  well  as  lack  of  regional  cross-border 
demand-supply optimisation. As a result, peak demand in electricity could be up to 5% higher by 2020 
and up to 8% by 2030 respectively56, with corresponding needs for investment in expensive peak load 
and back-up generation assets. 

With regard to gas networks, the years 2000-2011 saw considerable development of new storages and 
LNG terminals with an upward trend throughout the period. Gas interconnectors, linking EU regional 
gas  markets,  however,  have  only  developed  slowly.  While  several  new  import  pipelines  are 
successfully coming  online  in  the  North  and  South of  the  EU,  only  4  new  gas  interconnectors  were 
built  in  the  past  decade.  The  EEPR  support  has  had  a  significant  impact  in  accelerating  major 
interconnector  investments  in  2011  (PL-CZ,  HU-CR,  RO-HU).  Other  projects  were  and  are  being 
delivered on the basis of exemptions (see Annex 15). 

Concerning planned future investments, the 2011 TYNDP considers higher investment needs of EUR 
89  bn  for  the  period  2011-2020  than  those  estimated  in  the  2010  impact  assessment  (EUR  70  bn). 
Projects worth about EUR 67.8 bn have not received a final investment decision (FID) yet, although 
they  will,  according  to  ENTSOG,  contribute  most  to  enhancing  security  of  gas  supply,  creating 
flexible  gas  networks  for  market  integration  and  linking  isolated  regions.  Most  of  them  are  cross-
border (EUR 58 bn). Currently planned FID projects, notably in storage, will only address additional 
demand under severe weather conditions (see Annex 15). It can therefore be concluded that under a 
business-as-usual development scenario and in the light of past investments, the value of projects at 
risk  of  not  being  delivered  could  be  significantly  higher  than  the  EUR  10  bn  estimated  in  the  2010 
impact assessment, in particular with regard to interconnectors. 

Concerning  CO2  transportation,  as  already  explained  in  the  2010  impact  assessment,  most  of  the 
potential  EUR  2.5  bn  investment  needed  over  the  period  2010-2020  will  not  be  delivered  under 
business-as-usual. 

Business as usual would also mean the continuation of the current TEN-E approach to financing, 
with limited amounts of EU funding focussed on studies rather than works57 and no reiteration of the 

54  

55  
56  
57  

The  Dutch-German  grid  operator  TenneT,  which  as  of  March  2011  had  over  7  GW  of  offshore  wind  farm 
connection  projects  ongoing  or  planned  in  the  German  North  Sea,  indicated  regulatory  clarity  among  the  key 
challenges for the feasibility and commercial viability of its projects. Operators in the United Kingdom have also 
indicated that the current round 3 tender process for offshore wind farm developments could lead to uncontrolled 
point-to-point connections onshore without overall optimisation, e.g. by developing integrated hub-and-spoke grid 
designs, as the latter involve too high and risky investments. This could lead to increased costs and difficulties for 
onshore onwards transmission on already fully used networks. NRAs have argued that hub solutions could develop 
in certain Member States of the NSCOGI from 2015 onwards. Results from the OffshoreGrid study show however 
that "teeing in", i.e. directly connecting wind farms into an interconnector, or linking two wind farm hubs in two 
different  Member  States  through  an  interconnector  makes  socio-economic  sense  in  many  cases,  notably  if  the 
concerned wind farms are far from shore. 
Commission estimation, based on OffshoreGrid study results. 
Source: IEA, April 2011 
In the 2007-2009 period, about 65% of the allocated TEN-E funds were dedicated to studies (45M€), while 35% 
went to works (25M€). 

20

 
 
                                                 
European  Energy  Programme  for  Recovery.  As  a  result,  projects  of  European  significance  would 
continue  to  mainly  receive  EU  grants  for  feasibility  and  front-end  engineering  and  design  studies. 
Financial support for the construction of projects would remain very limited: An expected EUR 55M 
of  the  available  funds  of  EUR  155M  would  cover  works  expenses.  In  addition,  EU  allowed  co-
financing  rates  for  works  would  continue  to  be  insufficient  to  boost  the  implementation  of  certain 
projects. Indeed, as demonstrated by the EEPR experience, for projects aiming at increasing security 
of  supply,  a  co-financing  rate  of  50%  or  more  can  be  necessary  to  unblock  the  project  while  the 
current  TEN-E  co-financing  rate  is  capped  at  10%  of  the  construction  costs58.  As  a  result,  only 
investments with a sufficiently high direct and short-term benefit for the investor(s) would be realised, 
which would be insufficient to meet the challenge arising from the step change in investments59. 

Concerning the other contributions to infrastructure financing, it can expected that the EIB lending 
trends to energy grid projects observed over the last couple of years would not be maintained. While 
the  EIB's  lending  volume  to  the  energy  infrastructure  industry  rose  from  EUR 2.5 bn  in  2007  to 
EUR 6 bn  in  2010  (with  about  EUR 3 bn  for  energy  transmission  and  EUR 3 bn  for  energy 
distribution),  the  EIB  Board  of  Governors  has  made  it  clear  that  it  did  not  wish  for  extended  EIB 
lending  towards  energy  grid  infrastructures,  with  lending  volumes  returning  to  pre-crisis  levels,  i.e. 
decreasing  by  roughly  one  third  compared  to  their  peak  in  2010.  Depending  on  the  evolution  of 
macroeconomic conditions and the speed of economic recovery in EU economies, this downside effect 
could  be  partly  compensated  by  a  renewed  interest  from  commercial  banks  in  lending  to  regulated, 
risk-free activities. 

On the equity side, equity capital provision will continue to be dominated by government involvement, 
as a large number of European TSOs have public institutions as their majority shareholders. This will 
limit  the  potential  involvement  of  external  shareholders,  leaving  internal  equity  stemming  from  the 
TSO's  own  operational  revenues  as  the  main  source  of  basic  financing  for  future  infrastructure 
investments. However, given the strong constraints on public finances for the coming years, it can be 
expected that, where external equity investments are feasible, such equity injections will be sought as 
an  alternative.  However,  it  might  prove  difficult  for  the  TSO  sector  to  attract  sufficient  amounts  of 
such investments, given the profile of relatively low returns (less than 10%) for low risks. 

In any case, even if there were sufficient debt and equity funds available under business as usual to 
meet the EUR 210 bn investment challenge, these market-based funds will not be sufficient to deliver 
the more complicated types of projects discussed above. But with a mere continuation of EU grants 
made  available  during  the  2007-2013  period  (excluding  the  EEPR)  and  given  the  likely  future 
evolution  of  (repayable)  loans  provided  by  financial  institutions,  far  less  than  EUR  2  bn  of  (non-
research) grants would be available for the period after 2013 up to 2020 under business-as-usual. This 
amount  will  be  severely  insufficient  to  satisfy  the  funding  needs  expected,  given  the  identified 
investments and their urgency until 2020. 

As a result of these trends of the baseline scenario, the Commission estimates that a significant 
share of the needed investment of approximately EUR 200 bn until 2020 will not be delivered on 
time  under  the  existing  framework.  This  will  make  the  achievement  of  the  EU's  energy  and 
climate  policy  objectives  in  terms  of  renewables  deployment  and  emission  reduction  by  2020 
impossible,  but  it  will  also  seriously  hinder  market  integration,  diversification  and  security  of 
supply. Lack of interconnections will reduce opportunities for system optimisation, increase the 
risk of disruption and trigger additional costly back-up and balancing generation investments. 
Supplying  energy  and  balancing  supply  and  demand  will  become  more  expensive,  with  the 
corresponding effects on the competitiveness of European industries, consumers and growth. 

58  

59  

Grants,  however,  would  not  provide  always  the  right  incentives  to  invest.    Indeed,  as  mentioned  in  Chapter  2 
Article 109 of the EU financial regulation, grants may not have the purpose or effect of producing a profit for the 
beneficiary.  Consequently,  while  having  a  positive  impact  on  network  tariffs  as  the  corresponding  costs  are  not 
passed  through  to  the  final  consumer  through  the  tariffs  –,  grants  could  be  perceived  as  a  missed  opportunity  to 
make business (by excluding the possibility for TSOs to earn revenues on the corresponding asset). 
See  also  conclusions  from  the  2009  TEN-E  Implementation  Report  (COM(2010)203  and  SEC(2010)505)  and 
SEC(2010)1396. 

21

 
 
                                                 
5. 

KEY PLAYERS AND AFFECTED POPULATION 

All  EU  citizens  are  affected  by  future  energy  policy  as  competitive,  secure  and  sustainable  energy 
supply is at the heart of any economic activity. Energy is a daily need in a modern world and is mostly 
taken for granted in Europe. More specifically, almost all actors in the energy sector and beyond are 
affected by the proposal: 
•  Transmission  and  distribution  system  operators  will  be  first  and  foremost  affected,  as  any  new 

initiative will touch upon planning and realisation of new transmission infrastructure; 

•  Promoters and operators of existing and new power plants as well as gas suppliers, both within the 
EU  and  in  third  countries,  as  a  new  policy  will  have  an  impact  on  the  evolution  of  network 
capacity all across the EU and in its neighbour countries. 

•  Member  State  governments,  administrations,  specialised  technical  and  environmental  authorities 
(at  national,  regional  or  local  level)  and  regulators  who  will  be  in  charge  of  implementing  and 
applying any new rules related to the identification of projects of common interest as well as their 
implementation through planning, permit granting, regulation and financing; 

•  Energy  consumers  (both  citizens  and  businesses),  as  energy  infrastructure  investments  will 
negatively affect final energy prices, while better interconnected, optimised and smarter grids will 
contribute to better balancing of energy supply and demand and increasing competition and hence 
influence positively the final energy price for electricity and gas; 

•  Landowners as well as citizens in the neighbourhood of new infrastructure, that might be affected 
temporarily  (construction)  or  permanently  (local  environmental,  safety  and  health  impacts  or 
visual impairment etc.), and corresponding stakeholder organisations (e.g. environmental NGOs). 

6. 

EU RIGHT TO ACT 

The  EU's  competence  in  the  area  of  energy  is  enshrined  in  the  Treaty  on  the  Functioning  of  the 
European Union (TFEU), Article 19460. The EU's role needs to respect the principles of subsidiarity 
and proportionality. 

Energy  transmission  infrastructure  (including  an  interconnected  off-shore  grid  and  smart  grid 
infrastructure)  has  Trans-European  or  at  least  cross-border  nature  or  impacts.  Member  State  level 
regulation is not suited and individual national administrations have no competence to deal with these 
infrastructures as a whole. From an economic perspective, energy network developments can best be 
achieved when planned with a European perspective, encompassing both EU and Member State action 
while  respecting  their  respective  competences.  A  bigger  market  can  also  better  encourage 
development of innovative technologies for transmission and distribution of energy and financing of 
large-scale investments such as those foreseen among the energy infrastructure priorities.  

Energy networks are therefore covered under Article 170 and 171 TFEU. Article 170 specifies: 
“The Union shall contribute to the establishment and development of trans-European networks in the 
areas of transport, telecommunications and energy infrastructures”. Article 171 sets the obligation that 
“the Union shall establish a series of guidelines covering the objectives, priorities and broad lines of 
measures envisaged in the sphere of trans-European networks; these guidelines shall identify projects 
of common interest”. 

Following  the  Commission's  November  2010  communication  on  energy  infrastructure  priorities,  the 
28  February  2011  TTE  Council  specifically  asked  the  Commission  to  present,  in  autumn  2011,  an 
initiative covering the main areas of action foreseen in the "Communication on energy infrastructure 
priorities for 2020 and beyond" and aiming in particular at "streamlining and improving authorisation 
procedures,  facilitating  public  acceptance",  and  at "creating  the  necessary  framework  and  incentives 

60  

“In the context of the establishment and functioning of the internal market and with regard for the need to preserve 
and improve the environment, Union policy on energy shall aim, in a spirit of solidarity between Member States, 
to: (a) ensure the functioning of the energy market; (b) ensure security of energy supply in the Union; (c) promote 
energy efficiency and energy saving and the development of new and renewable forms of energy; and (d) promote 
the interconnection of energy networks.” 

22

 
 
                                                 
for delivering infrastructure projects under the identified priorities, notably with regard to cross-border 
allocation of costs and benefits and their reflection in tariffs"61. 

Concerning  more  specifically  permit  granting  procedures,  Article  171-2  TFEU  on  trans-European 
networks  states  that  "Member  States  shall,  in  liaison  with  the  Commission,  coordinate  among 
themselves  the  policies  pursued  at  national  level  which  may  have  a  significant  impact  on  the 
achievement of the objectives referred to in Article 170". Moreover, Article 194-2 TFEU allows the 
EU  to  establish  the  measures  necessary  to  promote  the  interconnection  of  energy  networks. 
Furthermore, Article 171-2 states that  "the Commission may, in close cooperation with the Member 
State, take any useful initiative to promote such [Member State] coordination". Hence, the formulation 
of broad measures to create a framework, within which Member States carry out the permit granting 
procedures  according  to  their  national  specificities,  to  the  aim  of  accelerating  the  permit  granting 
process, falls in the remit of the EU. Frequent calls of industry as well as the acknowledgement of the 
European  Council  in  February  2011  that  "it  is  important  to  streamline  and  improve  authorisation 
procedures,  while  respecting  national  competences  and  procedures,  for  the  building  of  new 
infrastructure"  demonstrated  that  most  Member  States  have  so  far  not  been  able  to  resolve  the 
prevailing problems satisfactorily at national level. 

7. 

OBJECTIVES 

7.1.  General objective 

The  general  objective  of  this  initiative  is  to  ensure  sufficient  and  timely  development  of  gas 
transmission, storage and LNG/CNG infrastructure, electricity transmission, storage and smart 
grid infrastructure as well as oil and CO2 transmission infrastructure across the EU and in its 
neighbourhood in order to: 

• 

further develop the internal energy market by interconnecting Member States and connecting 
island, landlocked and peripheral Member States with the central regions of the Union, so as 
to ensure energy provision at affordable prices to European customers, 
ensure security of supply, 

• 
•  meet the EU’s energy and climate goals, both in terms of binding targets up to 2020 and of 

longer term emission reduction. 

7.2. 

Specific objectives 

More  specifically,  this  initiative  aims  at  implementing,  by  2020,  the  trans-European  energy 
infrastructure  priority  corridors  as  defined  by  the  February  2011  European  Council  conclusions.  To 
this end, it wants to: 

a)  Streamline  permit  granting  procedures  to  significantly  reduce  their  duration  for  projects  of 
common  interest  and  increase  public  involvement  and  acceptance  for  the  implementation  of 
such projects; 

b)  Facilitate  the  regulatory  treatment  of  projects  of  common  interest  in  electricity  and  gas  by 
allocating  costs  depending  on  the  benefits  provided and  ensuring  allowed  returns  are  in  line 
with risks incurred; 

c)  Ensure implementation of projects of common interest by providing necessary market-based 

and direct EU financial support. 

Consistency with other European policies 

7.3. 
This  inititiave  subscribes  to  the  Europe  2020  strategy62,  which  put  energy  infrastructures  at  the 
forefront  as  part  of  the  flagship  initiative  "Resource  efficient  Europe".  It  underlined  the  need  to 
urgently  upgrade  Europe's  networks  towards  a  European  "smart  supergrid",  interconnecting  them  at 
the continental level, in particular to integrate renewable energy sources. The priorities identified and 

61  
62  

http://register.consilium.europa.eu/pdf/en/11/st06/st06207-re01.en11.pdf  
COM(2010) 2020, 3.3.2010 

23

 
 
                                                 
the  measures  proposed  in  this  initiative  with  regard  to  permit  granting,  regulation  and  financing  are 
fully in line with these objectives. 

The  upcoming  legislative  proposal  forms  a  logical  package  with  the  “Connecting  Europe  Facility” 
(CEF) proposed by the Commission, which will be the subject of a separate regulation. This initiative 
will  replace  the  existing  TEN-E  policy  guidelines63.  It  will  set  the  infrastructure  priorities  for  the 
coming decade and provide for specific measures concerning permit granting and regulatory issues to 
ensure their implementation. 

With regard to financing, this initiative will only fix eligibility rules for projects of common interest to 
receive EU financial assistance. The award of this assistance will be governed by common rules for 
energy, transport and digital infrastructures in the CEF. The latter will in particular provide for the use 
of  grants  for  studies  and  works  concerning  energy  infrastructures.  But  it  will  also  open  up  the 
possibility to use some of the EU budget allocated to energy infrastructures through different financial 
instruments,  notably  debt  and  equity  instruments  and  project  bonds.  These  mechanisms  will  be 
presented  separately  under  the  EU's  new  financial  regulation  for  the  next  multi-annual  financial 
framework.  As  a  result,  part  of  the  budget  which  will  be  available  for  EU  financial  aid  to  energy 
projects would be earmarked to contribute to the cost of the bond enhancement mechanisms and other 
debt  and  equity  instruments.  As  such,  the  CEF  will  complement  the  measures  in  the  field  of  permit 
granting and regulation provided by this initiative. 

The  CEF,  thanks  to  this  Regulation,  will  be  able  to  concentrate  all  EU  funding  for  industrial-scale 
energy transmission infrastructure of European relevance (i.e. with significant cross-border impacts) in 
one instrument, including for projects that involve third countries. Available funds under the Cohesion 
Policy  will  be  dedicated  to  infrastructure  projects  of  national  or  regional  importance,  while  funding 
under the Common Strategic Framework for Research and Innovation will go to pre-industrial scale 
projects up to the demonstration level. 

Furthermore,  the  importance  of  strategic  energy  interconnections  with  our  neighbours  and  key 
suppliers was underlined in the Europe 2020 Strategy, which notably highlighted the need to promote 
energy  infrastructure  projects  in  the  Baltic,  Balkan,  Mediterranean  and  Eurasian  regions.  The  Joint 
Communication  of  the  Commission  and  the  High  Representative  “A  new  response  to  a  changing 
Neighbourhood”  adopted  on  25  May  201164  underlines  the  need  to  enhance  energy  cooperation, 
including  on  energy  infrastructures,  with  neighbouring  countries.  The  Joint  Communication  of  the 
Commision and the High Representative "A Partnership for Democracy and Shared Prosperity" issued 
on  8  March  201165  calls  notably  for  the  establishment  of  "an  EU-South  Mediterranean  Energy 
Community"  and  for  an  "EU-Mediterranean  partnership  in  the  production  and  management  of 
renewables". Development of energy infrastructures of common interest is also a key objective of the 
Eastern  Partnership  Platform  on  Energy  Security.  All  these  developments  fall  within  the  policy 
objective of reinforcing the external dimension of our energy policy as called upon by the 4th February 
2011  European  Council  Conclusions.  Key  orientations,  including  as  regards  infrastructures,  will  be 
developed  in  the  Commission  Communication  "The  EU  Energy  Policy:  Engaging  with  Partners 
beyond Our Borders" to be adopted in September 2011. 

This initiative is also a necessary pre-condition for the achievement of the two binding targets of 20% 
share of renewables and 20% of greenhouse gas emission reductions by 2020 and aims to be in line 
with  the  pathway  set  out  in  the  Commission’s  Communication  on  a  Roadmap  for  moving  to  a 
competitive low-carbon economy in 2050 and the EU's long term objective of an 80-95% reduction in 
greenhouse  gas  emissions  by  2050  compared  to  1990  levels66.  Through  the  promotion  of  smart  grid 
technologies,  it  also  facilitates  demand-side  efficiency  and  enables  electrification  of  transport.  The 
investments  promoted by this initiative correspond to a "no regret strategy". As such, it provides an 

63  

64  
65  
66  

Note  that  the  Commission  is  preparing  in  parallel  a  revision  of  the  guidelines  for  Trans-European 
Networks  in  Transport  and  new  guidelines  for  Trans-European  Networks  for  information  and 
communication technologies. 
COM(2011) 303, 25.5.2011 
COM(2011) 200 
COM(2011) 112 in combination with SEC(2011)288 

24

 
 
                                                 
important contribution to the Energy Roadmap 2050, which is currently being prepared for adoption 
by the Commission in late 2011. In line with the White Paper on adaptation to climate change67, the 
initiative aims at ensuring that due consideration is also given to this important issue. 

The  objectives  of  this  initiative  are  furthermore  consistent  with  EU  policies  on  competitiveness  and 
innovation. Finally, this initiative is without prejudice to and does not entail any formal amendment of 
existing EU environmental legislation. 

8. 

POLICY OPTIONS 

In order to better analyse solutions to the problems identified above, policy options will be presented 
and  discussed  for  each  policy  area  below  (see  Table  3).  All  the  options  are  coherent  with  the 
overarching EU objectives, strategies and priorities. A preliminary analysis will allow discarding those 
suboptions with the least positive impact. 

Policy area A: Permit granting, stakeholder involvement and compensation 
Option A.0 

Business as usual 

Option A.1 

Option A.2 

Establishment of a regime of Common European Interest 

Organisation and limitation in time of the permit granting process 

Element A.2.1: Organisation of the permit granting process 

Suboption 
A.2.1.a 

Suboption 
A.2.1.b 

Leading Authority without decision-making power at national level 
(“light one-stop shop”) 

Leading Authority with decision-making power at national level 
(“full one-stop shop”) 

Suboption 
A.2.1.c 
Element A.2.2: Limitation in time of the permit granting process 

Cross-border Leading Authority with European Authority of Last 
Resort and European permit granting procedure 

Requirement for Member States to establish time limits for each 
individual PCI 
Legally-binding time limits established by stakeholders in the 
framework of the regional initiatives 
Legally-binding time limit established by the EU legislative act 

Suboption 
A.2.2.a 
Suboption 
A.2.2.b 
Suboption 
A.2.2.c 
Establishment of a regime of Common European Interest and organisation and 
limitation in time of the permit granting process 

Option A.3 

Policy area B: Regulation 
Option B.0 

Business as usual 

Option B.1 

Cost allocation 

Suboption B.1.a  EU transmission tariff 

Suboption B.1.b  Ex-ante cost allocation 

Suboption B.1.c  Ex-ante cost allocation with ex-post adjustment 

Option B.2 

Investment incentives 

Suboption B.2.a  Risk-related incentives for PCIs 

Suboption B.2.b  Penalty and enforcement action for PCIs 

Option B.3 

Ex-ante cost allocation and risk-related incentives for PCIs 

Policy area C: Financing 
Option C.0 

Business as usual 

Option C.1 

Option C.2 

Option C.3 

Risk sharing instruments 

Risk capital instruments 

Grant support for project construction 

67  

COM(2009) 147 

25

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                 
Option C.4 
Table 3: Policy options 

Combination of grants, risk sharing and risk capital instruments 

8.1. 

Permit granting, stakeholder involvement  

This  section  presents  the  proposed  policy  options  and  suboptions  regarding  permit  granting  and 
stakeholder involvement for electricity and gas PCI. The policy options are assessed with regard to the 
principles of subsidiarity and proportionality as well as their effectiveness and are reflected against the 
opinions of stakeholders conveyed in the context of various public and stakeholder consultations. Oil 
and CCS projects will not be subject to the proposed measures under the proposed legislative act. Only 
projects  in  electricity  and  gas  are  facing  particular  urgency  with  a  view  to  their  contribution  to  the 
2020 objectives in terms of renewables generation and the prevention of climate change. This rationale 
does not apply to oil projects, and no major concerns about lengthy permit granting procedures were 
raised by stakeholders. For CCS projects, there is lack of evidence for measures in the field of permit 
granting due to the relative novelty of the technology and the lack of concrete infrastructure projects at 
this stage, and the public debate on CCS is considered as not mature enough for measures to be put in 
place. 

OPTION A.0: Business as usual - best practice and information exchange 

Under this option, best-practice and information exchange to facilitate administrative permit granting 
procedures, including environmental assessments, and to improve transparency and public acceptance 
would  be  encouraged.  The  Commission  would  publish  guidance  documents  and  highlight  best 
practices  encountered  in  Member  States.  At  European  level,  a  communication  campaign  would  be 
carried out, targeted at citizens to communicate better the costs and benefits of energy infrastructure 
and increase public awareness, which would complement activities at national level. 

Effectiveness, subsidiarity and proportionality 

This policy option is considered to be in line with the principles of subsidiarity and proportionality, as 
it  would  leave  the  implementation  of  measures  to  the  Member  States  on  a  voluntary  basis.  The 
introduction  of  guidelines  to  enhance  transparency  in  the  process  and  improve  communication  with 
citizens  has  been  clearly  advocated  by  the  majority  of  respondents  in  public  and  stakeholder 
consultations,  particularly  by  Member  States  and  civil  society.  As  however  the  majority  of 
respondents  also  favoured  the  introduction  of  a  one-stop  shop  concept  and  time  limits,  the 
effectiveness of guidelines without stronger implementation measures is clearly considered as limited. 
Several attempts (e.g. Commission Recommendation to improve permit granting procedures for TEN-
E projects68, Commission guidance for environmental impact assessments for TEN-E projects69) were 
made to encourage Member States to shorten the duration of their permit granting processes, but the 
analyses  conducted  in  the  context  of  this  impact  assessment,  and  the  various  Council  conclusions 
mentioned  in  Chapter  6  demonstrate  that  prevailing  problems  have  not  been  solved  sufficiently  at 
national  level,  with  exception  of  a  few  Member  States.  Therefore,  the  effectiveness  of  voluntary 
measures is considered as limited, which would justify the need for binding rules.  

OPTION A.1: Establishment of a regime of common interest 

Under  this  policy  option,  a  PCI  would  be  allocated  priority  status  compared  to  other  projects  in  the 
field  of  energy  infrastructure.  This  would  include  that,  with  the  adoption  of  the  list  of  PCI  by  all 
stakeholders  involved  in  the  competent  fora,  the  necessity  to  implement  a  PCI  would  have  to  be 

68  

69  

Commission  Recommendation  of  14  December  1998  concerning  the  improvement  of  authorisation 
procedures for trans-European energy networks, 
Commission  staff  working  document  -  Accompanying  document  to  the  Communication  from  the 
Commission  Trans-European  Networks  :  Toward  and  integrated  approach  {COM(2007)  135  final}/ 
SEC/2007/0374 

26

 
 
 
                                                 
acknowledged by all parties involved in the permit granting process70, such that it would not have to 
be demonstrated in dedicated tasks (such as written answers during public consultations) or procedures 
(such  as  the  Déclaration  d’Utilité  Publique  procedure  in  France).  In  essence,  after  a  PCI  has  been 
allocated a label of “common interest”, stakeholders would not have the opportunity to question the 
necessity of a project anymore, but would be able to focus efforts on the decision of the routing of the 
projects.  This  would  be  without  prejudice  to  the  need  of  adequate  communication  with  the  public 
about the costs and benefits of a given project. In Member States where certain fast-track or priority 
procedures have been implemented, the highest priority level possible would have to be applied, and 
authorities would have to give the most preferential treatment possible in terms of resources when 
processing  PCI  related  files.  Responding  to  the  challenges  identified  with  regard  to  environmental 
legislation, Article 6(4)71 of the Habitats Directive and Article 4(7) of the Waterframework Directive 
would apply in that the least harmful route of a PCI could, despite negative implications for the site, be 
carried out for reasons of imperative public overriding interest. Prior to the allocation of this status, the 
conditions  of  the  environmental  legislation  in  place  would  have  to  be  met:  appropriate  assessments 
would  have  been  carried  out,  alternative  solutions  could  not  be  identified,  and  all  necessary 
compensatory measures would have to be taken. This rule would remove the responsible authorities’ 
discretion  to  assess  whether  the  project  of  imperative  overriding  public  interest,  as  this  would  be 
decided  by  all  stakeholders,  including  Member  States,  through  the  selection  of  the  project  in  the 
context of the PCI identification process. A PCI could thus not be prohibited from being built due to 
negative  impacts  on  the  site,  whilst  the  need  to  carry  out  appropriate  assessments  is  fully 
acknowledged so as to minimise the impact on protected habitats. Complementary guidelines would 
have to be prepared by the Commission regarding the significance of effects and scope of assessment 
as well as compensatory measures. 

Effectiveness, subsidiarity and proportionality 

These  measures  are  considered  to  be  of  positive  effectiveness  regarding  the  delivery  of  projects,  as 
PCIs would benefit from a priority treatment in Member States. Responses in public and stakeholder 
consultations stated that PCI should benefit from the same political support in the Member States as 
national priorities. Some Member States formally or informally supported the allocation of the status 
of public overriding interest to PCI, although it was acknowledged that the question of compatibility 
with the EU acquis would have to be addressed. Other Member States as well as industry advocated at 
a more general level that the EU should take measures to solve conflicts between environmental and 
energy/climate change objectives and not leave it to the Member States’ authorities, and the European 
Parliament  called  on  the  Commission  to  present  a  corresponding  proposal.72NGOs  reacted  rather 
reserved on particularly this rule, but some NGOs signalled their willingness to support grid extension 
measures, provided that a coherent strategy with regard to the integration of renewables is followed. 
Under  this  option,  the  allocation  of  the  status  of  "public  overriding  interest"  would  continue  to  be 
decided  at  national  level,  as  the  Member  States  are  involved  in  the  selection  of  projects  and  would 
have to approve the final list of PCIs. 

In conclusion, these measures are considered to be effective, solving the difficulties of environmental 
nature  where  necessary,  giving  the  Member  States  appropriate  stake  in  the  decisions  to  take,  and 
limiting the need to change national permit granting frameworks. This option is thus considered in line 
with the principles of subsidiarity and proportionality.  

OPTION A.2: Rules on the organisation and duration of the permit granting process 

70  

71  

PCI defined as interconnection between points A and B, without prejudice to find the most suitable trajectory for 
this interconnection 
According  to  Article  6(4)  of  the  Habitats  Directive,  a  project  may  be  carried  out  for  imperative  reasons  of 
overriding  public  interest  in  spite  of  a  negative  assessment  of  the  implications  for  the  site,  in  the  absence  of 
satisfactory alternative solutions.  

72  European  Parliament  resolution  of  5  July  2011  on  energy  infrastructure  prirorities  for  2020  and  beyond 

(2011/2034(INI)) 

27

 
 
 
                                                 
This  option  would  establish  concrete  rules  regarding  the  framework  within  which  permit  granting 
procedures are carried out. These rules would comprise two main elements: organisation of the permit 
granting  process  and  duration  of  the  permit  granting  process.  For  each  of  these  elements,  three 
suboptions have been identified. 

Element A.2.1: Organisation of the permit granting process 

Suboption  A.2.1.a:  Leading  Authority  without  decision-making  power  at  national  level  (“light 
one-stop shop”) 

MS would have to establish a single Leading Authority at national level, responsible for the overall 
coordination  of  the  permit  granting  process  of  the  PCIs  located  in  their  respective  territory.  The 
Leading Authority would serve as the main interface for the project promoter, and would involve and 
aim at achieving a common understanding between all other authorities and stakeholders concerned, 
with the objective that the most appropriate decision or decisions are taken within the stipulated time 
limit. Concrete responsibilities would include the set-up, implementation and monitoring of a permit 
granting schedule, scoping activities to identify the issues to be covered in the application documents, 
and  the  handling  of  consultation  procedures,  according  to  guidelines  for  early  and  effective  public 
involvement  as  part  of  the  legislative  proposal.  These  would  include  requirements  to  elaborate  a 
manual of procedures for increased transparency for  all stakeholders, and to agree on a consultation 
concept  to  be  elaborated  by  the  project  promoters  (providing  for  an  informal  public  consultation 
before  submission  of  the  application  file).  Cross-border  cooperation  would  be  ensured  through 
regional  fora,  regular  meetings  between  Leading  Authorities  and  the  elaboration  of  joint  permit 
granting schedules. 

Suboption A.2.1.b: Leading Authority with decision-making power at national level (“full one-
stop shop”) 

MS  would  have  to  designate  a  single  Leading  Authority  at  national  level,  which  would  have  the 
responsibilities as outlined under Suboption A.2.1.a. At the end of the process, the Leading Authority 
would  have  to  issue  one  comprehensive  administrative  decision  concerning  the  construction  of  the 
project.  

With  regard  to  the  decision-making  competence  of  the  Leading  Authority,  Member  States  could 
choose between two schemes: 

Under  the  integrated  scheme,  the  comprehensive  administrative  decision  issued  by  the  Leading 
Authority  would  be  the  sole  legally-binding  decision  resulting  from  the  statutory  permit  granting 
procedure.  Where  other  authorities  are  concerned,  these  could  give  their  opinion  as  input  to  the 
procedure,  which  the  Leading  Authority  would  have  to  take  into  account  when  taking  the  decision. 
The  integrated  permit  granting  scheme  does  not  correspond  to  the  concept  of  "integrated 
environmental  assessments",  as  different  environmental  authorities  could  give  their  opinion  on 
different subject matters. 

Under the coordinated scheme, the comprehensive administrative decision could encompass multiple 
individual legally-binding decisions issued by the Leading Authority and other authorities concerned. 
The Leading Authority would have to establish, on a case-by-case basis, a reasonable time limit within 
which  the  individual  decisions  have  to  be  issued.  Provided  that  the  provisions  required  by  EU  and 
national legislation are respected, the Leading Authority could overrule an individual decision or take 
an individual decision on behalf of another authority concerned, if it is not delivered within the time 
limit  and  if  the  delay  cannot  be  adequately  justified,  or  if  it  is  not  considered  appropriate  by  the 
Leading Authority.  

Suboption  A.2.1.c:  Cross-border  Leading  Authority  ("light  one-stop  shop")  with  European 
Authority of Last Resort and European permit granting procedure 

MS  would  have  to  establish  jointly  a  cross-border  Leading  Authority  which  would  coordinate  the 
procedures  for  each  PCI  and  be  responsible  for  the  set-up,  implementation  and  monitoring  of  the 
permit granting schedule. The national authorities involved in the process would retain their decision-

28

 
 
making  competences.  In  the  event  of  an  unjustified  expiry  of  the  final  time  limit  for  the  final 
administrative decision, an Authority of Last Resort at European level would take the final decision. 
At  this  stage,  the  PCI  legislation,  and  a  European  permit  granting  procedure  would  apply.  It  is  the 
Authority of Last Resort to assess whether a delay is not justified. 

Effectiveness, subsidiarity and proportionality 

Consultations with stakeholders have shown that the majority of respondents favours the concept of a 
one-stop shop (79% of respondents of the public consultation on permit granting). With regard to the 
competences of the one-stop shop concept, the preferences of stakeholders were almost equally split 
between  the  options  of  a  light  one-stop  shop  versus  an  authority  with  substantial  decision-making 
power  (full  one-stop  shop).  Industry  was  slightly  in  favour  of  the  centralisation  of  decision-making 
power. Of the Member States responses submitted, including as reaction to the stakeholder workshops 
organised,  seven  explicitly  supported  the  concept  of  the  one-stop  shop  (with  full  decision-making 
power  at  national  level:  CZ,  decision-making  power  at  EU  level:  ES,  LT,  general  support  not 
specifying  decision-making  competence:  CY,  BE,  FR,  SE,  no  decision-making  power:  FI)  whereas 
two opposed the idea (SL for fear of additional administrative burden, DK due to subsidiarity). In six 
Member States, such concept already exists and was explicitly advocated by most (UK, NL, IE, DE, 
IT, EL). Some of the latter advocated the need to introduce this concept (as well as other measures) 
across  the  EU,  as  in  the  case  of  cross-border  projects  delays  in  the  neighbouring  Member  State 
significantly affect the domestic part of a project. It should also be noted at this point that the majority 
of  respondents  across  stakeholder  groups  raised  public  opposition  as  a  major  obstacle  in  the  permit 
granting process, and that remedies to involve citizens effectively and early in the process should be 
found. 

Responding  to  the  various  concerns  raised,  and  in  light  of  the  more  detailed  assessment  of  the 
suboptions in Annex 16, the introduction of a full one-stop shop with decision-making power has been 
identified  as  the  most  preferred  suboption  as  it  is  considered  to  strike  the  best  balance  between 
effectiveness in terms of reduction of the duration of the permit granting process and the principles of 
proportionality  and  subsidiarity.  This  suboption  takes  into  account  the  experience  in  Member  States 
where the introduction of a one-stop shop approach has been successful in reducing delivery times of 
the permits, and where decision-making power of the one-stop shop has been crucial for the authority 
to effectively drive the management process forward. The issues at stake, in particular with regard to 
environmental challenges, would continue to be adequately addressed by this centralised approach, as 
under  both  the  integrated  and  coordinated  approach  the  authority  in  charge  could  continue  to  issue 
opinions/permits  for  its  particular  field  of  environmental  competence.  This  has  been  proved  in  the 
Netherlands  and  in  the  UK.  Cost-effectiveness  would  be  given  under  this  suboption  as  compliance 
costs would practically be the same for the designation of the Leading Authority under a light one-stop 
shop. However, the full one-stop shop would reduce the administrative costs spent on the handling of 
the procedures, as decisions could be taken more quickly.  

This  suboption  also  reflects  the  concerns  raised  with  regard  to  issues  of  proportionality  and 
subsidiarity, as decision-making remains with the  Member States (no EU Authority of Last Resort), 
and  it  gives  Member  States  the  opportunity  to  choose  one  of  two  approaches  (integrated  vs 
coordinated scheme), therefore limiting the need for substantial reorganisation of the permit granting 
process.  The  one-stop  shop  is  considered  also  as  a  crucial  element  in  addressing  the  obstacles  with 
regard  to  public  resistance,  as  it  would  be  responsible  to  issue  transparency  guidelines  and  enforce 
certain rules related to public involvement which would be part of the legislative act, e.g. with regard 
to the appropriateness of the consultation strategy of the project promoters, the enforcement of early 
public consultations and participation in communication activities. It is expected that an authority with 
responsibility for the final decision has an intrinsic interest in effectively managing the communication 
process, for  which e.g. the UK  and the Netherlands, which have a similar  approach to the proposed 
measures, provide good examples. 

Therefore, suboptions A.2.1.a, A2.1.c have been discarded at this stage. 

Element A.2.2 Duration of the permit granting process 

29

 
 
Suboption A.2.2.a: Requirement for Member States to establish time limits for each individual 
PCI 

Under this suboption, the legislative act would require Member States to establish time limits for each 
individual PCI, which allows to account for the national specificities of the permit granting processes 
and the characteristics of individual projects. Upon establishment of the Union-wide list of PCIs, the 
Leading  Authority  would  have  to  define  an  adequate  time  limit  which  it  would  communicate  to  the 
project  promoter  and  other  authorities  concerned.  In  the  event  that  a  time  limit  is  not  respected, 
sanction  mechanisms  could  apply  in  those  Member  States  where  these  are  foreseen  by  national 
legislation. 

Suboption  A.2.2.b:  Legally-binding  time  limits  for  PCIs  established  by  stakeholders  in  the 
framework of the regional initiatives 

In  the  framework  of  the  regional  fora  and  in  the  context  of  the  selection  of  PCI,  MS,  the  national 
regulatory authority/ies, and possibly the Leading Authority/ies and other relevant stakeholders invited 
(such as NGOs and citizens’ initiatives) would have to jointly agree on individual time limits for the 
permit  granting  process  as  well  as  the  completion  of  the  project  of  the  respective  PCI.  The 
stakeholders would consequently have to sign an intergovernmental agreement, which would indicate 
the  time  limits  agreed  upon.  This  document  would  serve  as  the  legal  basis  for  possible  sanction 
mechanisms to be initiated at EU level, if the time limit is not respected .  

Suboption A.2.2.c: Legally-binding time limit for PCIs established by the EU legislative act 

Under this suboption, the time between the start of the permit granting process and the final positive or 
negative  administrative  decision  concerning  the  construction  of  the  PCI  could  not  exceed  about  3-4 
years, which corresponds to today's EU27 average duration for the statutory procedure. The start of 
the permit granting process would be identified as the agreement on the notification of the project by 
the  Leading  Authority  and  the  project  promoter.  This  time  frame  would  not  include  any  judicial 
processes. In MS where parts of the procedures, including spatial planning, do not result in a legally-
binding permit, Leading Authorities would be required to ensure that their duration is well-integrated 
in the overall time frame. The time between the acceptance of the submitted application documents by 
the Leading Authority and the final administrative decision should not exceed 1 year. 

No automatic approval or rejection of the project would be linked to the expiry of the time limit. To 
effectively  enforce  the  timely  delivery of  the  projects,  sanction  mechanisms  could  be  applied  at  EU 
level  if  projects  are  subject  to  significant  unjustified  delays.  The  Commission  would  have 
discretionary  margin  to  assess  whether  delays  are  unjustified  and  sanction  mechanisms  should  be 
applied.  These  would  include  infringement  procedures  where  MS  fail  to  take  appropriate  action, 
complemented by reporting requirements. 

Effectiveness, subsidiarity and proportionality 

Regarding time limits, the majority of stakeholders who responded to the public consultation favoured 
their  introduction  (60%),  particularly  representatives  from  industry.  Four  Member  States  explicitly 
supported this measure (CZ, CY, (SCTL), BE, LT) whereas two opposed it (SE fears that time limits 
could lead to bad preparation of assessments and permits, DK due to subsidiarity). In some Member 
States,  time  limits  already  exist  for  the  statutory  procedure  (e.g.  UK,  IE,  NL).  Particularly  NGOs 
warned  of  the  risks  of  introducing  time  limits,  as  these  could  jeopardise  democratic  principles  and 
lower environmental standards if procedures cannot be carried out appropriately. A central issue raised 
was the consequence of the expiry of a deadline.  Whereas it was mainly considered that time limits 
without appropriate implementing measures and legal consequences in case of their expiry would not 
have substantial effects, automatic approvals or rejections of the project were mainly considered as not 
viable options.  

Taking  into  account  the  range  of  opinions  conveyed,  as  well  as  one  of  the  overall  objectives  of  the 
proposal, i.e. the achievement of the 2020 targets, the prescription of time limits at EU level has been 
assessed  as  the  most  preferred  suboption.  As  explained  more  in  detail  in  Annex  16,  the  suboptions 
leaving more flexibility to Member States prove to be not practical in terms of their implementation, 
as  the  decision  process  on  individual  time  limits  would  be  too  cumbersome,  and  as  sanction 

30

 
 
mechanisms,  which  are  considered  as  necessary  for  the  enforcement  of  time  limits,  would  only  be 
applied in Member States where these sanctions exist (the option of automatic approval or rejection of 
projects has been assessed as not feasible in line with stakeholders' views). The legal grounds for the 
EU  to  act  would  be  missing.  However,  taking  into  account  concerns  especially  raised  by  Member 
States with regard to subsidiarity, the preferred suboption would leave flexibility to the Member States 
to  define  individual  time  limits,  including  for  the  various  stages  of  the  process,  and  to  set  more 
ambitious  deadlines  if  considered  appropriate.  As  the  time  limit  envisaged  is  expected  to 
accommodate well already existing time limits in some Member States, including for EIA procedures 
(average duration 1 year) and public consultations (average duration 4-8 weeks), no substantial change 
of procedural law should be necessary (for more explanations on the impacts see Chapter 9). 

Therefore, suboptions A.2.2.a, A2.1.b have been discarded at this stage. 

In  conclusion,  the  preferred  suboptions  would  set  a  framework  within  which  Member  States  could 
carry out their procedures according to national specificities, and are considered as most appropriate 
with  regard  to  the  effectiveness  of  the  prescribed  measures  as  well  as  ambitions  with  respect  to  the 
principles of proportionality and subsidiarity. 

OPTION  A.3  Establishment  of  a  regime  of  common  European  interest  and  rules  on  the 
organisation and duration of the permit granting process 

This  option  would  include  both  option  A.1  on  the  establishment  of  a  regime  of  European  common 
interest  and  selected  suboptions  under  A.2  on  the  organisation  and  duration  of  the  permit  granting 
process. 

Effectiveness, subsidiarity and proportionality 

See explanations above. 

An  overview  establishing  the  link  between  the  problems  identified  in  Chapter  3  and  the  policy 
measures  proposed in this Chapter is provided in Annex 17, highlighting, inter alia, the benefits of a 
centralised approach through the establishment of a one-stop shop, as this concept addresses most of 
the challenges described. 

8.2. 

Regulation 

OPTION B.0: Business as usual 

Under this option, no legislative action would be taken on regulatory issues related to investment in 
new electricity and gas infrastructures. Third package guidelines already under preparation on capacity 
allocation and congestion management would be completed and applied, but no further attempts would 
be  undertaken  to  establish  cross-border  cost  allocation  rules  for  new  infrastructure  and  to  provide 
specific incentives for certain types of projects.  

Effectiveness, subsidiarity and proportionality 

The  business  as  usual  option  relies  on  the  future  full  implementation  and  application  of  the  third 
internal market rules by the Member States. As the Commission Communication of November 2010 
showed, given the urgency of the 2020 objectives, the business as usual is not an option.  

The public consultation of national regulatory authorities, the ENTSOs and its network operators and 
investors illustrated that national incentive schemes are not necessarily oriented towards the EU wide 
climate  and  energy  objectives,  e.g.  the  rate  of  return  do  not  sufficiently  reflect  the  risks  faced  by 
project promoters, and that the investment challenge is not sufficiently taken into account by national 
regulatory authorities.  

The  internal  market  framework  is  to  provide  for  common  cross-border  rules  on  capacity  allocation, 
tariffs and others, and is to give NRAs the competences to approve tariffs or methodologies. However, 
tariff structures and regulatory frameworks are likely to remain national in scope. The IEMP does not 
provide  for  a  mechanism  at  EU  level  on  how  costs  incurred  in  one  country  but  for  the  benefit  of 
another  country  should  be  recognized  in  the  tariff  systems.  While  today's  tariffs  are  effective  for 

31

 
 
national network expansion, they are not effective to advance energy infrastructure investments with a 
view to the implementation of the EU energy and climate objectives. There is no top-down approach 
on the identification of costs and benefits from an EU energy wide system perspective. There are no 
EU  wide  rules  on  sharing  the  costs  of  complex  cross-border  projects  in  particular  where  they  are 
asymmetric (cost allocation) and deviating from 50-50 agreements between TSOs. In the light of the 
slow progress in past investments as outlined in  the Annex Figures , without reinforced cooperation 
among  all  parties,  including  NRAs,  networks  operators,  Member  States  and  the  Commission,  the 
deployment of energy infrastructure will not be secured from the third internal market package alone.  

OPTION B.1: Cost allocation 

To solve the cost allocation problems outlined above, rules are necessary to properly allocate costs as 
a function of the benefits or positive externalities obtained and reflect this allocation accordingly in the 
network access tariffs paid by the beneficiaries. 

Suboption B.1.a: EU transmission tariff 

Under this option, a small percentage of national tariffs in each Member State would be collected to 
fund  PCIs.  Such  an  EU  wide  tariff  would  require  substantial  harmonisation  of  tariff  structures,  a 
separate  regulatory  asset  base  under  EU  regulation-  This  risks  creating  distortions  by  establishing  a 
distinction between tariffs for PCIs and tariffs for other projects.  

Effectiveness, subsidiarity and proportionality 

While  operators  and  academia  consider  an  EU  wide  transmission  tariff  as  an  effective  solution,  its 
degree  of  harmonization  seems  to  be  not  proportionate  and  is  also  likely  to  generate  significant 
opposition from Member States and national regulators. Such harmonisation seems premature, given 
the  limited  benefit  provided  compared  to  the  likely  difficulty  to  implement  it  and  the  possible 
distortion effects. Depending on the design, it could be perceived as a new EU energy tax added to the 
final energy prices which raises not only subsidiarity concerns but ignores the differences with regard 
to the current level of development of grids in the various Member States, notably as a result of past 
investment  efforts,  and  hence  the  fact  that  some  countries  will  have  to  invest  much  more  over  the 
coming 10 years than others.  

In the light of this, option B.1.a is therefore discarded and not assessed further. 

Suboption B.1.b: Ex-ante cost allocation mechanism 

Under  this  option,  PCIs  would  also  be  funded  by  national  tariffs.  However,  TSOs  and  NRAs  of 
directly  concerned  Member  States  and  immediate  neighbours  would  have  to  agree  in  a  coordinated 
approval process, for each PCI, on an ex-ante cost allocation solution, which would, based on a cost-
benefit  analysis73,  identify  how  benefits  are  allocated  between  these  Member  States  and  distribute 
investment costs for the project among national tariff schemes. To further accelerate the process, the 
time to agree on a common procedure and time schedule for the regulatory treatment of such cross-
border PCIs would be limited and ACER be tasked to intervene in case of persistent disagreement. 

NRAs  as  represented  by  CEER  and  within  ACER  taskforces  contributed  to  the  examination  of  the 
scope  for  cost  allocation  with  dedicated  working  papers  (see  Annex  list).  NRAs  underlined  that  the 
principle should be a three-step-approach: costs should be levied on the users, beneficiaries and only 
then on taxpayers. Within the North Sea Countries' Offshore Initiative a working group on regulatory 
issues  concluded  that  cost  allocation  issues  may  arise  with  regard  to  advance  capacity  and  the 

73  

This  cost-benefit  analysis  will  serve  as  a  harmonised  tool  at  EU  level  to  evaluate  the  global  optimality  of 
infrastructure  projects,  based  on  common  input  data,  grid  and  market  modelling  and  identify  benefits  overall 
benefits and costs, taking into account various social, economic, environmental and climate externalities, including 
climate proofing. 

32

 
 
 
  
 
                                                 
asymmetry  of  costs  and  benefits,  in  particular  the  benefits  from  RES  support schemes.  A  procedure 
involving TSOs, NRAs and ACER was considered to suit the purpose. NRAs underlined that existing 
cost  allocation  principles  (ITC  mechanism,  congestion  rents)  and  regulatory  practise  (e.g.  open 
seasons for gas) largely suffice. The overall conclusion was therefore that there is only a need for a 
general cost allocation principle along the three-step-approach and a framework for an agreement.  

Suboption B.1.c: Ex-ante cost allocation mechanism with ex-post adjustment possibility 

This  option  would  be  identical  to  the  previous  one,  but  each  agreement  would  have  to  contain  a 
revision clause outlining the rules for ex post adjustment. This would allow changes in the allocation 
of variable benefits and costs to be taken into account during the lifetime of a project. 

NRAs suggested that some fixed cost element  could be allocated  ex-ante and that variable  elements 
could be adjusted ex-post, depending on the regulatory framework and its approach on how such ex-
post adjustments or risk sharing is done.  

OPTION B.2: Investment incentives 

Suboption B.2.a: Risk-related incentives for PCIs 

In the workshops with NRAs it was repeatedly underlined that NRAs' independence needs to 
be respected to decide on the incentives and that any incentive mechanism needs to be based 
on the tariff system and limited only to PCIs commensurate to the risks of the project. These 
views  were  also  supported  by  Member  States.  These  concerns  were  taken  on  board  as  this 
option  would  oblige  NRAs  to  provide  PCIs,  which  have  demonstrated  higher  risks  than 
business-as-usual  projects,  adequate  incentives  for  their  implementation,  in  line  with  the 
principle of risk-adjusted return and the requirement to provide for long-term incentives via 
tariffs under the third package. 

Eligible risks would be: 

-  Technology risks for new transmission technologies; 
-  Risks related to offshore transmission grid development; 
-  Specific  risks  related  to  operations  and  revenue  streams,  notably  for  projects  with  long-term 

benefits. 

There  would  be  no  automaticity  for  these  specific  incentives,  but  TSOs  would  have  to  provide 
sufficient  justification  for  the  reasonableness  of  the  chosen  technology  and  proof  for  the  extra  risks 
claimed. This should also ensure that the incentive covers an action that can be controlled by the TSO. 

Regulators would be able to choose from a set of options to trigger investments, including notably: 

-  Equity  adders  to  match  risks  and  regulated  returns:  The  mark-up  of  such  adders  should  be 

commensurate to the risk effectively incurred by the operator. 

-  Rules  for  anticipatory  investment:  These  rules  could  involve  capacity  payments,  regulated 

auctions, mandatory capacity obligations and other long-term incentives. 

-  Early  recognition  of  efficiently  incurred  pre-operation  costs  not  already  covered  under  existing 

regulation. 

Regulators  would  have  to  justify  their  choice.  This  decision-making  at  national  level  would  also 
reflect  the  fact  that  financial  incentives  for  TSOs  differ  across  the  EU  depending  on  the  regulatory 
framework,  the  unbundling  regime,  the  ownership  as  well  as  shareholder  structures.  The 
appropriateness  of  a  particular  incentive  scheme  will  therefore  depend  on  the  country,  TSO  and 
project in question. 

Effectiveness, subsidiarity and proportionality 

This option is considered to be the most effective option to provide the market participants with the 
incentives  to  make  the  necessary  investments.  In  order  to  ensure  proportionality  of  such  incentive 
schemes and their compliance with state aid rules, the incentives should be only limited to the cases 

33

 
 
 
where  PCIs  are  affected  (limited  number  of  EU  added  value  projects)  AND  in  relation  to  the  risks 
incurred and set via tariff regulation. In line with the principle of subsidiarity, the NRAs are to decide 
on  the  choice  of  incentives  on  the  basis  of  the  justifications  provided  by  operators  in  line  with  the 
country  specific  regulatory  framework  and  network  and  industry  structure.  In  line  with  the  market-
based approach and confirming NRA views, the possible use of public funding under the Connecting 
Europe Facility to address specific project risks, should only be envisaged once the market operators 
and regulatory measures have be exhausted.  

Suboption B.2.b: Penalties and enforcement action for PCIs 
As  the  alternative  to  incentive  regulation  under  option  B.2.a  this  option  would  build  on  3rd  IEMP 
legislation and aims giving NRAs and ACER the regulatory powers to enforce the implementation of 
all PCIs 74 In case of persistent non-delivery of a PCI by one or several TSOs, despite their inclusion 
in the TYNDP, NRAs would be enabled to impose penalties on the concerned TSOs, e.g. by reducing 
their  regulated  revenues,  or  ensure  project  implementation,  e.g.  through  application  of  the  measures 
under  Article  22.  In  case  NRAs  cannot  agree,  ACER  would  ensure  the  mediation.Article  22  of 
Directive 2009/72/EC and 2009/73/EC gives NRAs the right, with regard to independent transmission 
operators (ITO), to ensure the implementation of all projects considered to be necessary in the short 
term  according  to  the  TYNDP.  If  an  investment  is  not  carried  out  by  the  TSO,  the  NRA  can  either 
force  the  TSO  to  execute  it,  organise  a  tender  procedure  open  to  any  investor  or  oblige  the  TSO  to 
accept a capital increase to finance the said investment and allow investors to participate in the capital. 
The 3rd IEMP strictly provides for such enforcement only for the ITO unbundling model and does not 
address the question of how cross-border projects would be jointly enforced. 

Effectiveness, subsidiarity and proportionality 

Such  enforcement  would  be  effective  for  the  implementation  of  the  PCIs,  proportionate  and  fully 
respect the subsidiarity of the NRAs and in line with internal market rules. However, in practice NRAs 
may refrain from implementing such penalties, in particular the tender procedure or equity increase for 
other  investors,  due  to  the  main  characteristics  of  the  TSO  ownership  structure  with  high  state 
involvement.  

OPTION B.3: Ex-ante cost allocation and risk-related incentives for PCIs 

This option would combine option B.1.B for an ex ante cost allocation mechanism and option B.2.a 
introducing risk related incentives for projects of common interest. 

8.3. 

Financing 

OPTION C.0: Business as usual – continuation of the TEN-E with similar budget under the 
Connecting Europe Facility  

Under this option, the financial support under the Connecting Europe Facility to energy infrastructures 
would be limited to mainly co-financing feasibility and project preparation (front-end engineering and 
design  and  similar)  studies  (continuation  of  the  principles  of  the  current  TEN-E  programme).  No 
support  would  be  available  under  the  TEN-E  budget  for  projects  outside  the  EU,  which  would 
continue  to  benefit  from  various  other  EU  programmes.  Targeting  EU  support  on  major  energy 
infrastructure  in  third  countries  that  would  contribute  to  improving  the  EU’s  security  of  supply, 
connecting  renewables  or  increasing  the  EU’s  energy  systems’  flexibility  will  not  be  possible. 
Structural  funds  would  provide  very  limited  support  to  energy  infrastructure  projects  in  eligible 
Member States, without the possibility to channel funds to projects of the highest European relevance. 
The range of financial facilities available through the EIB would not evolve. 

74  

The Commission argues in its interpretative note on the roles of NRAs that the rule of Article 22 should not prevent 
NRAs from applying the mechanism to all TSOs independently from the unbundling option chosen. 

34

 
 
 
 
                                                 
OPTION C.1: Risk sharing instruments 

Under this option, the EU financial support under the Connecting Europe Facility would be channelled 
to  projects  through  financing  instruments  and  facilities  made  available  jointly  with  financial 
institutions,  for  example  the  EIB.  The  instruments  proposed  would  be  under  the  debt  and  equity 
platform principles proposed by the European Commission75. By accepting to share certain risks with 
financial institutions, the Commission would enable them to address more exhaustively the financing 
needs of energy projects. Projects could benefit from an improved access to bond and loan financing 
on favourable terms (extended duration, targeted guarantees, and increased debt financing volumes). 

The  risk  sharing  mechanism  will  require  that  the  EU  provides  a  financial  institution  with  budgetary 
resources  to  provision  for  portions  of  statistically  possible  losses  that  operations  under  such 
instruments  could  generate.  Normally,  the  risk  taking  would  be  compensated  via  a  risk  premium 
charged  to  the  benefiting  projects.  The  Union  contribution  would  be  capped  at  an  agreed  budgetary 
amount, thereby strictly limiting budgetary exposure and determining the size of such a facility. 

The following instruments or facilities could be inter alia envisaged: 
•  project bond credit enhancement: This would be particularly suited for larger projects; 
• 

lending enhancement (enabling a financial institution to provide e.g. loans with longer repayment 
period  better  aligned  with  the  economic  lifetime  of  energy  assets;  increased  lending  volumes; 
construction phase bridging loans): Such measures would suit projects of all sizes; 
enhancement  facility  (enabling  a  financial  institution  to  issue  guarantees76  addressing  individual 
project needs, including capacity utilisation guarantees77). 

• 

OPTION C.2: Risk capital instruments 

Under this option, the EU financial support under the Connecting Europe Facility would take the form 
of  an  investment  in  specific  projects  of  common  interest  or  a  special  purpose  vehicle  developing 
projects  with  the  two-fold  objective  of  a)  providing  equity  capital  needed  to  attract  investors  and 
financiers, and/or b) kick-starting certain riskier projects. Support could take the form of: 

•  Equity  support:  The  EU  would  provide  capital  to  equity  fund(s)  (directly  or  via  a  financial 
institution)  which  actively  invest  in  targeted  projects.  In  order  to  make  co-investment  more 
attractive to third party investors and provide them with fair returns, the return target on the EU 
share  could  be  subordinated  vis-à-vis  other  investors  even  though  the  reward  structure  should 
reflect the risk taken as far as feasible. The EU participation in the funds would be in line with the 
main principles of the debt and equity platform proposed by the European Commission. 

•  Seed capital: In order to accelerate more complex, innovative or multi-stakeholder projects, EU 
financial aid would be used as seed capital to help moving a project from the “studied concept” to 
the project phase. Depending on the individual needs of each project, seed capital could also fund 
the  preparation  of  design,  legal  assistance  for  necessary  agreements,  the  setting-up  of  dedicated 
project development companies, or the process to obtain permits or launch procurement. In return 
for providing such seed capital, the EU would receive an equity share in the project, which could 
be bought back by other shareholders at a pre-determined future date (compulsory put option). 

OPTION C.3: Grant support to project construction 

Under this option, the EU would be able to support projects of common interest with the Connecting 
Europe  Facility  in  the  electricity  (transmission,  storage,  smart  grids)  and  gas  sector  (transmission, 
storage,  LNG/CNG)  for  construction  works  (including  procurement  of  construction  material), 

75  

76  

77  

European  Commission,  “A  Budget  for  Europe  2020:  the  current  system  of  funding,  the  challenges  ahead,  the 
results of stakeholders consultation and different options on the main horizontal and sectoral issues”, Commission 
Staff Working Paper accompanying the Communication "A Budget for Europe 2020", SEC(2011) 868. 
Such a guarantee would be an on-budget instrument like LGTT and not imply any contingent liability for the EU 
budget. 
This would guarantee that, in case the downside scenario in capacity use materialises after project commissioning, 
the promoter will be able to benefit from a liquidity facility to cover the revenue shortfall and to serve its obligation 
towards debt providers. The mechanism would reflect the LGTT instrument already existing under TEN-T. 

35

 
 
                                                 
provided it has been demonstrated that the socio-economic cost-benefit analysis yields a positive result 
(also taking into account various externalities) and that the regulatory solutions proposed (notably cost 
allocation and risk-related incentives) alone are not sufficient to make project delivery possible. The 
EU could support up to 50% of the eligible cost of projects and in case of security of supply projects 
up to 80%. The optimal rate of support would be assessed individually for each project. This option 
builds on what is already now possible under the existing TEN-E scheme (with a contribution capped 
at 10% of a project's eligible costs) and the precedence set by the EEPR programme. 

EU grants could also be made available on a repayable basis, to address the risk of advanced capacity 
provision.  Such  a  grant  would  cover  a  portion  of  the  project's  eligible  construction  costs  and  be 
repayable  if  the  actual  use  of  the  infrastructure  exceeds  the  short-term  expectations  and  therefore 
ensures  commercial  viability  of  the  project.  In  exceptional  cases,  if  there  is  no  interest  (or  even 
opposition)  by  operators  to  develop  a  project  clearly  identified  as  being  of  common  interest,  an 
international  tender  could  be  launched  where  grant  financing  could  be  offered  as  an  incentive  to 
interested  investors.In  addition  to  construction  support,  the  EU  would  continue  to  co-finance 
feasibility  and  preparatory  studies  at  co-financing  rates  of  up  to  80%,  as  is  already  the  case  under 
TEN-E today. Such support would be available to both mature and less mature projects, which need 
further feasibility studies to assess their viability and common interest. Grants would be distributed via 
calls for project proposals. 

OPTION C.4: Combination of grants, risk sharing and risk capital instruments 

Under  this  option,  all  the  above  forms  of  EU  support  would  be  made  available  at  EU  level  in  the 
Connecting Europe Facility. The combination of market-based and direct financial support created this 
way would provide flexibility of providing the most cost-effective remedy to specific project risks and 
features at the various stages of development of the project. It should be noted that in case EU support 
is accompanied by national co-financing, or if Member States can decide upon the use of EU funding, 
the State aid rules (if applicable) must be respected, notably to ensure necessity and proportionality of 
the measure. 

9. 

ANALYSIS OF IMPACTS 

This chapter analyses the impacts of the various policy options and their suboptions. We will thereby 
insist on the most relevant impacts for each policy area. It should be noted that the evaluation of all 
business-as-usual options is done in chapter 4. 

9.1. 

Permit granting, stakeholder involvement and compensation 

In the following, we present an assessment of the economic, social and environmental impacts of the 
each of the short-listed suboptions78. 

OPTION A.1: Establishment of a regime of common European interest 

In terms of  overall impact, this option is expected to have intermediate positive effects as it would 
contribute to the timely delivery of significantly more projects than under BAU, provided appropriate 
measures  on  regulation  and  financing  are  in  place.  This  result  is  based  on  the  assumption  that  fast-
track/priority  procedures  exist  in  10  MS,  but  in  only  5  MS  this  procedure  is  linked  with  a  one-stop 
shop and/or time limit. In MS with fast-track/priority procedure alone the observed reduction in delays 
has been only of a few months79. This option would also address those PCIs not realised under BAU 
because of lack of recognition of their necessity or public overriding interest, as e.g. written objections 
during  public  consultations  on  this  matter  would  not  have  to  be  formally  answered  and  grounds  for 
appeals would be more restricted. 

78  

79  

Regarding economic impacts, on costs, a distinction is made between compliance costs and administrative costs. 
Since the permit granting process as such is defined as an information obligation (according to IA Guidelines), all 
costs  related  to  activities  pursued  within  the  permit  granting  process  are  classified  as  administrative  costs. 
Compliance costs are classified as those costs related to the adaptation of national legislation and the establishment 
of the necessary structures by MS, as well as adaptation of processes established by promoters. 
Roland Berger, 2011b. 

36

 
 
                                                 
Concerning social impacts, citizens would be affected in that they would not have the possibility to 
formally question the necessity of a project in the context of the permit granting procedures, e.g. in the 
form of written objections or in litigation procedures in the form of appeals. However, this rule would 
be without prejudice to discussions related to the routing of a particular PCI, and potentially necessary 
explanations  about  costs  and  benefits  of  a  project,  such  that  citizens  would  not  be  deprived  of  their 
right  to  be  adequately  informed.  Further,  a  number  of  citizens  will  be  affected  by  visual  impacts  of 
electricity  overhead  lines  on  their  property  and  in  their  vicinity.  Regarding  safety  and  health  issues, 
thresholds  for  electro-magnetic  fields  implemented  by  MS  have  to  be  respected  when  constructing 
electricity overhead lines, which are often lower than the recommendations given by the EU80. 

The impacts on the environment are not expected to increase greatly under the new regime vis-à-vis 
the  current  one,  given  the  assumption  of  earlier  completion  of  projects  rather  than  significantly 
increasing the overall volume. Impacts affect the local flora and fauna81. Some short-term disturbances 
to  animals  and  destruction  of  plants  and  habitats  may  occur  during  construction  work,  and  some 
permanent displacements of animals and destruction of plants might take place due to the existence of 
underground  cables,  gas  pipelines  and  electricity  pylons.  Further,  overhead  electricity  lines  might 
make  it  necessary  to  keep  open  vegetation  in  corridors  in  wooden  areas  and  cause  habitat 
fragmentation  to  animal  and  plant  species  and  disturbances  to  birds.  These  impacts  will  vary 
depending on the project, but are considered to be rather limited for electricity line projects, as, due to 
the size of electricity pylons only small areas are affected, and underground impacts of gas pipelines 
and cables are expected to be less important due to the limited existence of wildlife there. As regards 
specifically the impact of electricity lines on birds, there is only a minor risk of electric shocks of birds 
with high voltage lines82. However, collision risks for large bodied soaring bird species may be serious 
if no adequate mitigation measures are taken. A micro-level assessment of impacts on the environment 
cannot  be  carried  out  at  this  stage,  as  this  is  subject  to  the  analysis  to  be  carried  out  by  project 
promoters under the relevant legislation in place. 

As regards particularly the measure related to the allocation of the status of public overriding interest 
to PCIs in the context of the Habitats Directive, the impact on the local flora and fauna is expected to 
be relevant for only a subset of the 20 projects identified as possibly in conflict with Natura2000 areas, 
which  are,  however,  crucial  for  the  achievement  of  energy  and  climate  policy  objectives83.  As 
explained in Chapter 4, a preliminary analysis has been conducted to identify projects which may need 
to make use of the Lex Specialis, by matching, at an aggregate level, the possible route of the cross-
border projects taken up in the existing TYNDP with Natura2000 areas. Yet, the final list of PCIs is 
subject to a selection process, and the identification of possible conflicts with protected areas is subject 
to  the  environmental  assessments  to  be  carried  out  by  project  promoters.  This  means  that  the  exact 
route  of  the  PCI  and  the  concrete  alignment  will  be  determined  in  the  process  comparing  all 
alternatives and not before that. Therefore, a more detailed assessment of the impacts is not possible at 
this stage. With regard to legislation in the field of water policy, problems related to water issues have, 
in  contrast  to  problems  related  to  Natura2000  areas,  not  been  stated  as  a  major  concern  by 
stakeholders. Only limited use, if at all, is expected to be made of the Lex Specialis in the framework 
of  the  Waterframework  Directive,  such  that  the  impacts  on  inland  surface,  transitional,  coastal  and 
groundwater are expected to be minor. However, if necessary, the legislative act would allow for the 
prioritisation of energy projects consistent with provisions on the Habitats legislation. A more detailed 
analysis cannot be provided at this stage for the same reasons valid for the assessments on flora and 
fauna, and since a comparison of aggregate data with the routing of relevant projects is not possible, as 
information on neither data nor the characteristics of the project (whether surface, underground etc.) is 
sufficiently available at this stage. Overall, due to the requirement to carry out appropriate assessments 

80  

81  

82  
83  

Council  Recommendation  1999/519/EC  on  the  limitation  of  exposure  of  the  general  public  to  electromagnetic 
fields (0 Hz to 300 GHz). 
Short-term  disturbances  to  animals  and  destruction  of  plants  and  habitats  during  construction  work,  permanent 
displacements of animals and destruction of plants due to the existence of underground cables, gas pipelines and 
electricity pylons. 
Haas, Dr. Dieter and Bernd Schürenberg, "Stromtod von Vögeln", p.16, January 2008. 
Immediate and strong impacts would only be expected if PCIs were completely exempted from the obligation to 
carry out appropriate assessments. However, this is not considered as viable with regard to biodiversity objectives. 

37

 
 
                                                 
as established by environmental legislation, the obligation to choose the least harmful route, and the 
necessity to undertake adequate mitigation and compensation measures, it is expected that the above 
described limited negative impacts will be offset. 

Where the urgent need of integrating renewables and preventing climate change make the balancing of 
environmental  and  climate  change  objectives  necessary,  this  rule  could  set  a  precedent  for  non-PCI 
projects  in  the  field  of  energy,  in  that  Member  States  could  choose  to  extend  the  scope  of  this 
provision. However, it is expected that no precedent is created for other sectors, as the energy sector 
faces particular urgency regarding the delivery of projects due to the 2020 objectives. 

Strong positive effects with regard to climate policy objectives are expected – if the EU cannot meet 
its energy and climate objectives climate risks will further grow and deteriorate the environment. The 
construction  of  electricity  lines  enables  the  large-scale  deployment  of  renewable  energies,  with  its 
positive impacts in terms of reduction of CO2 emissions. Whilst it is difficult to quantify impacts and 
compare  effects  on  the  local  environment  with  the  contribution  of  energy  infrastructure  to  the 
prevention of climate change, it is expected that the overall balance of impacts is positive. In addition, 
the fight of climate change has positive effects on the preservation of biodiversity, as global warming 
could extinct certain species not adapted to higher temperatures84. 

Regarding economic impacts, the assurance that the necessity of a project is acknowledged and that 
projects can be built despite potential conflicts with Natura2000 areas will increase investors' certainty 
and positively contribute to the projects' commercial viability. Minor impacts in terms of compliance 
costs  are  expected:  In  MSs  where  the  necessity  of  a  project  or  the  application  of  any  other  priority 
scheme  is  established  by  law,  resources  would  be  needed  on  the  authorities'  side  to  adapt  national 
legislation, such that PCIs are accounted for in these. 

Regarding  administrative  costs,  the  reduction  of  resources  needed  for  processing  a  given  number  of 
projects is estimated at about 3% on the promoters' side, and 12% on the authorities' side. As described 
in Annex 16, this results from the fact that less resources would be needed to handle objections related 
to  the  necessity  of  the  project,  and  that  existing  fast-track  procedures  would  be  applied.  Additional 
savings to be expected in the context of litigation procedures are not taken into account here, as these 
are not subject to the legislative act85. 

In  terms  of  the  legal  feasibility  of  this  option,  some  adaptation  of  national  legislation  would  be 
necessary in those countries where priority or fast-track regimes and/or the acknowledgement of the 
necessity of a project are established by a legislative act (e.g. UK). In countries where the necessity of 
a project is established by a procedure on a case-by case basis (e.g. France), this procedure could serve 
to define the concrete routing of a PCI. In other countries, the EU legislative act would serve as legal 
basis. It is expected that the measure related to the Habitats and Waterframework Directives would not 
require  an  explicit  amendment,  but  would  rather  constitute  a  Lex  Specialis,  which  is  not  in 
contradiction with the rules established. However, the analysis of this measure has not been entirely 
concluded to date and will be subject to a more detailed legal analysis as part of the elaboration of the 
legislative act. 

OPTION  A.2:  Rules  on  the  organisation  and  duration  of  the  permit  granting  process 
(suboptions  A.2.1b  "full  one-stop  shop"  and  A.2.2.c  "legally-binding  time  limit  established  by 
legislative act") 

The  overall  impact  of  this  option  is  expected  to  be  strong  and  positive,  as  it  would  allow  a  large 
majority  of  projects  needed  by  2020  to  be  delivered  on  time,  provided  appropriate  measures  on 
regulation and financing are in place. The number of projects realised on time would be higher than 
with option A.1, under which fast-tracking with one-stop shop and time limits would only be possible 
in those Member States where it is already established. Analysis has shown that the existence of a one-
stop shop is positively correlated with the duration of the permit granting procedure86 (see Annex 7). 
In  countries  where  one-stop  shops  exist  (EL,  IE,  IT,  NL,  UK),  the  entire  permit  granting  process 

84  
85  
86  

Some species adapted to higher temperatures could however be positively affected. 
See Annex 17 for more details on methodology and assumptions. 
Note that one-stop shops identified have different degrees of decision-making power. 

38

 
 
                                                 
including  pre-application  efforts  has  an  average  duration  of  4-5  years87.  Legally-binding  time  limits 
will  reinforce  the  positive  impact  of  the  one-stop  shop  measure  on  durations,  as  they  are  crucial  to 
incentivise promoters and authorities to complete the permit granting process in a timely fashion, and 
for sanction mechanisms to be taken at EU level if considered appropriate and justified. Regarding the 
two-step  approach  (2-3  years  for  pre-application  efforts  and  1  year  for  the  statutory  permitting 
procedure, experience in MS where one-stop shop concepts and time limits have been introduced has 
proven that this two-step  approach is effective and feasible,  and leaves ample  time for promoters to 
complete assessments (for more details on the effectiveness of the one-stop shop and time limits, see 
Annex  16),  which  was  also  confirmed  by  a  study  carried  out  in  the  context  of  this  Impact 
Assessment.88 

In Member States where the current time frames are significantly longer than the four years proposed, 
it is expected that the measures foreseen under this policy option reduce the duration of the process, 
whilst  legal  requirements,  particularly  with  regard  to  public  consultations  and  environmental 
assessments, can continue to be respected. In essence, the time limit would incentivise authorities as 
well as project promoters to work against a given time line, which generally has positive effects on the 
delivery of projects.  

The  time  limit  can  however  not  be  considered  as  a  stand-alone  measure,  but  has  to  be  assessed  in 
combination with the full one-stop shop, which would hold the final responsibility of implementing a 
permit granting schedule, controlling the process and identifying intermediary milestones, and whose 
introduction would reduce the friction losses and delays occurring when a number of parties handles a 
project in an uncoordinated manner. Complementary measures regarding mandatory scoping activities 
(the  identification  of  issues  to  be  covered  in  the  application)  would  further  make  it  possible  for 
promoters to have certainty regarding the issues to be assessed, including environmental impacts. 

However,  the  time  limit  would  force  the  relevant  parties  to  limit  the  content  of  assessments  to  the 
necessary  issues,  based  on  realistic  scenarios,  without  demanding  assessments  for  improbable 
consequences  as  it  is  in  some  cases  reported  practice.  Public  consultations  will  under  the  proposed 
measures  continue  to  be  held  according  to  national  rules,  but  where  opposition  due  to  NIMBY 
phenomena  delays  projects  outside  the  framework  of  formal  public  consultations  and  where 
responsible authorities avoid decisions due to e.g. upcoming elections, the time limits, together with 
the full one-stop shop and appropriate sanctions, would accelerate decision-taking. It should be noted 
that decisions can be either positive or negative. Concerns that, under the coordinated approach, local 
authorities defer their decision to the national level have proven to be not valid, as the local authorities 
try to keep the decisions at their level to retain the maximum influence possible, as has been shown in 
the Netherlands. 

The measures foreseen would only be binding for electricity and gas projects, but could however have 
positive  spill-over  effects,  as  Member  States  could  choose  to  apply  these  to  other  infrastructure 
projects. Particularly in the field of renewables energy integration, this could have even more positive 
implications for the delivery of the 2020 objectives. 

However, it is expected that not all projects would be completed on time despite these measures. Some 
PCIs would not get the fast-track/priority treatment, while others would be stopped in cases where a 
public  authority  does  not  grant  the  status  of  overriding  interest  when  it  comes  to  the  crossing  of 
Natura2000 areas, or if long debates on necessity prevent the project before the start of the statutory 
process. 

Concerning  social  and  governance  impacts,  this  option  would significantly  improve  conditions  for 
citizens to participate in the decision-making process regarding the routing of a PCI. The time limit 
introduced  by  the  legislative  act  to  be  binding  on  the  project  promoters  would  not  jeopardise 

87  

88  

In the Netherlands for instance, the one-stop shop as main feature of the new permit granting regime has resulted in 
the  reduction  of  the  entire  process  from  an  average  of  10-15  years  to  6  years  (including  realisation  of  about  2 
years), whereas in some other countries where only loose or no coordination mechanisms exist, the completion of 
procedures  can  take  significantly  longer.  Acknowledging  the  difficulties  related  to  a  fragmented  permit  granting 
process, Germany has just adopted a law (NABEG) to shift permit granting competence from state to federal level. 
Roland Berger study on permitting (2011). 

39

 
 
                                                 
democratic principles and touch upon existing rights, as statutory public consultations have an average 
duration  of  between  4  and  8  weeks  and  project  promoters  will  have  to  respect  them..  These  time 
frames can be well-integrated in the time frames foreseen under the legislative act, as has been proved 
in several Member States. The measures foreseen would rather be beneficial to citizens, as the Leading 
Authority  and/or  promoters  would  be  responsible  to  give  clear  indications  about  intervention 
possibilities  for  citizens  (e.g.  manual  of  procedure,  project  website)  and  elaborate  consultation 
concepts  at  the  start  of  the  permit  granting  process.  Further,  an  early  (informal)  public  consultation 
would be required also in Member States where such consultations are not already carried out, thereby 
enabling citizens to raise their concerns at an early stage of the process. Hence, the implementation of 
time  limits  would  not  prevent  citizens  from  actively  participating  in  the  procedure,  but  instead,  by 
"frontloading" the process through early information and consultation, give them more opportunity to 
participate when decisions about alternative routes can still be influenced.  
Some authorities might face effects on their autonomy in areas for which they are competent89. This 
would be the case if a Member State chooses to implement an integrated approach (Alternative 1), as 
all  authorities  other  than  the  Leading  Authority  would  lose  their  responsibility  of  issuing  a  legally-
binding permit. Yet, they would still give their opinion to the Leading Authority, which would have to 
take it into account to prevent litigation procedures. 

But  Member  States  could  also  implement  a  coordinated  approach  (Alternative  2),  where  authorities 
may  retain  their  responsibilities  and  continue  to  issue  their  permits.  In  this  case,  only  Leading 
Authorities  at  federal  level  would  be  affected  in  their  autonomy,  as  well  as  authorities  which  are 
responsible  to  issue  consolidated  permits  for  a  particular  area  of  expertise.  The  Leading  Authority 
would  take  over  coordination  tasks,  but  the  responsible  authorities  could  continue  to  issue  technical 
permits. Other authorities involved in the procedure would only be affected if the Leading Authority 
had to step in because of unjustified time overruns. Evidence is only available to a limited extent, as, 
according to the analysis carried out, this approach has only been implemented in the Netherlands. 

Table 4 gives an overview of the type of authorities typically involved in the permit granting process 
across Member States and the consequences of the new regime (under both alternatives) in terms of 
decision-making power for each of them. 

Type 
of 
Alternatives 

authority 

/ 

Leading Authority at national 
level  -  full  national  one-stop 
shop  (e.g.  NL,  UK,  IE,  IT,  EL, 
DE  (taking  into  account  new 
legislation (NABEG)) 
Leading Authorities at federal 
state level (AU, partially BE) 
Authorities  responsible  to  issue 
a  consolidated  permit  for  a 
particular  area  of  expertise 
(Responsible Authorities) (e.g. 
FR, HU) 
Other  technical,  environmental, 
regional  and  local  authorities 
the  permit 
to 
input 
giving 
issuing 
granting  process  or 
(Other 
individual 

permits 

Alternative 
approach 
authority issues permit) 

1: 
(only 

integrated 
leading 

No impact 

Alternative  2: 
approach 
authorities 
permits) 
No impact 

issue 

coordinated 
(individual 
respective 

No  competence  under  new 
regime 
Input  in  form  of  opinion  to  the 
permit  granting  procedure,  no 
consolidated permit 

Input  in  form  of  opinion  to  the 
permit  granting  procedure,  no 
individual permit 

in 

No  competence  under  new 
regime 
technical 
form  of 
Input 
permit 
main 
possible, 
coordination  and  consolidation 
taken  over  by 
to  be 
tasks 
Leading Authority  
No impact 

89  

The  particular  authorities  involved  vary  across  Member  States.  They  generally  include  national  ministries 
responsible  for  energy  and  for  environment,  regional  technical  and  environmental  authorities,  municipalities  and 
other local authorities, etc. 

40

 
 
                                                 
authorities involved) (all MS) 
Table 4: Consequences of new permit granting regime on authorities involved 

Environmental  impacts  are  not  expected  to  considerably  differ  from  the  impacts  described  under 
policy option A.1. They would be slightly stronger from the perspective of impacts on local flora and 
fauna as well as on climate change, as more projects are expected to be completed under this policy 
option. 

Concerns that environmental impact assessments are not adequately carried out and reviewed due to 
the  introduction  of  time  limits  are  considered  as  not  valid.  The  time  frame  envisaged  would  well 
accommodate the time needed for the EIA procedure (a study estimated the average time needed from 
notification to decision as 1 year)90 and further assessments required according to other environmental 
legislative  acts,  as  proved  in  Member  States  where  streamlined  procedures  have  been  introduced. 
Regardless whether an integrated or coordinated approach is chosen by the respective Member State, it 
would  not  be  compulsory  to  harmonise  environmental  assessment  procedures.  Autonomous 
assessments  may  continue  to  be  carried  out,  as  individual  permits  or  opinions  could  continue  to  be 
given by the authorities responsible for their particular field of competence.  

With  regard  to  economic  impacts,  compliance  costs  would  be  higher  than  under  option  A.1.  MSs 
would have to adapt national legislation to accommodate (re)assignment of coordination and decision-
making powers, and would have to set up the necessary administrative structures and to transfer staff 
from  authorities  previously  responsible  and/or  recruit  additional  staff.  As  only  a  limited  number  of 
PCIs  will  be  subject  to  the  measures  envisaged  (about  five  per  Member  State),  the  number  of 
additional staff needed is not expected to be significantly high. Under the coordinated approach, it is 
expected that one person can process two projects, such that about 2.5 FTE would be needed. Thus, 
compliance  costs  are  considered  to  be  limited  under  the  assumption  that  Member  States  choose  the 
coordinated approach under this policy option, where authorities retain most of their responsibilities, 
and  that  an  existing  authority  will  be  designated  as  Leading  Authority,  such  that  no  entirely  new 
structures  will  have  to  be  created.91  Promoters  will  have  to  familiarise  themselves  with  the  new 
regime.  

Positive  impacts  on  administrative  costs  are  also  expected  to  be  more  significant  under  this  policy 
option. As shown in Annex 18, it is estimated that under the new regime, 25% of administrative costs 
can be saved per project on the promoters' side, with a reduction from EUR 114.5 million in the time 
frame 2014-2020 to EUR 85.9 m, assuming a total of 150 electricity projects to be authorised. On the 
authorities' side, 34% of administrative costs could be saved, with a reduction from EUR 22.6 m under 
BAU  to  EUR  15  m.  This  accumulates  to  total  savings  of  26%  of  administrative  costs  from  EUR 
137.1 m to EUR 100 m for both authorities and promoters in the period 2014-2020.92 

It  should  at  this  point  be  noted  that  the  reduction  of  administrative  costs  and  the  alleviation  of 
administrative  burden  on  promoters  is  not  the  main  objective  of  the  legislative  act  subject  to  this 
impact  assessment  as  it  would  constitute  only  a  minor  part  of  the  overall  construction  costs.  This 
proposal rather aims at ensuring the realisation of the infrastructure investments on time. 

In  terms  of  legal  feasibility,  the  need  to  adapt  national  legislation  depends  on  the  one-stop  shop 
approach selected by a Member State, being more extensive for the integrative approach than for the 
coordinated approach. Feasibility of this suboption has been proved in those Member States where full 
one-stops  with  different  forms  of  decision-making  power  have  been  established.  Respect  of 

90  

91  

92  

GHK, "Collection of information and data to support the IA study of the review of the EIA Directive", 2009. Note 
that notification in this context means application for screening. 
Austria  with  planning  and  permit  granting  competence  at  federal  state  level  would  be,  according  to  the  analysis 
conducted, an exception, such that a new authority would be responsible at national level.  
Results  are  based  on  the  relatively  conservative  assumption  that  two  authorities  are  responsible  for  the  permit 
granting  process  under  BAU,  which  are  coordinating  other  technical,  regional  and/or  local  authorities  and 
stakeholders  involved.  However,  this  is  only  one  type  of  permit  granting  regime  existing  in  the  different  MS. 
Impacts  would  be  greater  if  there  were,  as  it  is  in  many  MS  the  case,  more  responsible  authorities,  or  if  the 
responsible authority was not or only partially coordinating other authorities and stakeholders involved. In the latter 
case, a shift of administrative costs (not more than 2%) from promoter to authority is expected. 

41

 
 
 
                                                 
requirements  in  place  is  inherent  to  the  permit  granting  process  as  authorities  have  to  ensure  that 
permits can withstand administrative or judicial reviews. Regarding time limits, adaptation of national 
legislation  is  expected  to  be  necessary  in  Member  States  where  national  rules  foresee  different  time 
limits, but these adaptations are expected to be of limited extent. However, according to the analysis 
carried out, the time limits established by some of the Member States for the entire statutory permit 
granting procedure, which are generally shorter than one year, or for individual steps of the process 
can be well accommodated within the time limit, such that there would be no need for adaptation of 
national  procedural  law.  Member  States  would  not  be  prevented  from  setting  more  ambitious 
deadlines  than  the  ones  foreseen  by  the  legislative  act.  The  time  limit  established  by  the  EU  would 
only  define  the  point  in  time  when  EU  sanction  mechanisms  apply,  but  leave  Member  States  the 
flexibility to set and enforce time limits according to their national practice (for more explanations see 
Annex 16). In conclusion and as stated in Chapter 8, it is considered that the measures foreseen are in 
line with the principle of proportionality, as the need to adapt national legislation is limited compared 
to the positive impacts described above, and as this policy option would set conditions for a general 
permit  granting  framework,  within  which  Member  States  will  be  able  to  carry  out  their  procedures 
according to national specificities. 

. 

OPTION  A.3  Establishment  of  a  regime  of  common  European  interest  and  rules  on  the 
organisation and duration of the permit granting process 

The  overall  impact  of  this  policy  option,  which  combines  the  impacts  of  options  A.1  and  A.2,  is 
considered to be the most positive of all options, as it would lead to the on-time completion of almost 
all  the  needed  projects  by  2020,  provided  appropriate  measures  on  regulation  and  financing  are  in 
place.  It  would  make  compulsory  in  all  Member  States  those  measures,  which  are  crucial  for  the 
facilitation  and  acceleration  of  permit  granting  procedures,  not  only  those  where  fast-track  regimes 
and one-stop shop approaches have been implemented, and prevent projects from being stopped due to 
issues  related  to  the  necessity  or  public  overriding  interest  of  the  project.  Environmental  impacts, 
social impacts on employment and economic impacts on GDP are expected to be stronger under this 
policy  option  as  all  projects  would  be  completed.  Regarding  compliance  and  administrative  costs, 
effects would accumulate, with a reduction of administrative costs of 28% on the promoters' side, and 
46% at the authorities' side, equalling a reduction of 31% in total from EUR 137.1 m under BAU to 
EUR 95 m. 

Table  5  illustrates  the  compatibility  of  the  main  measures  envisaged  with  a  typical  permit  granting 
process, particularly with regard to EU environmental requirements. The only deviation from existing 
practice  would  consist  in  the  automatic  allocation  of the  status  of  "public  overriding  interest"  to  the 
least  harmful  route  of  a  PCI,  in  that  the  environmental  authorities'  discretion  to  allocate  such  status 
would be removed. 

42

 
 
Table 5: Compatibility of measures under Policy Option A.3 with existing permit granting practice and 
EU environmental legislation 

Resulting  from  this  analysis,  policy  option  A.3  is  the  preferred  option,  combining  the  measures 
necessary to achieve the 2020 target. 

9.2. 

Regulation 

OPTION B.1: Cost allocation 

Suboption B.1.b: Ex ante cost allocation mechanism 

The  economic  impact  of  such  a  measure  would  be  significant,  as  it  would  make  possible  certain 
investments,  for  which  no  viable  cost  sharing  would  be  possible  under  BAU.  It  would  do  so  by 
changing the way, in which costs for cross-border investments are allocated. Costs would have to be 
allocated as a function of the expected benefits. In theory, this mechanism could potentially support up 
to  150  projects  in  electricity  and  up  to  50  projects  in  gas93.  It  can  however  be  expected  that  an 
effective  cost  allocation  solution  will  be  only  found  for  a  certain  number  of  projects,  leaving  a 
significant volume of projects with too complex or uncertain benefits unsolved. 

It is difficult to assess precisely the distributional or social impacts of this option, i.e. how the new 
mechanism  would  affect  various  market  participants,  but  some  of  them  will  pay  less  than  under  the 

93  

This estimation is based on the assumption that in electricity, there would be about 100-120 cross-border projects 
between now and 2020 (the 2010 TYNDP contains 76) and an expected maximum of 30 internal line projects with 
significant  cross-border  impact.  In  gas,  there  would  be  about  30  interconnections  (without  final  investment 
decision), a limited number of reverse flow projects and very few LNG and storage projects with significant cross-
border impact. Note that these numbers could be significantly smaller in the case of project clustering. 

43

 
 
 
 
                                                 
current cost sharing scheme, while others will pay more. As a general rule, one can expect that TSOs 
from Member States with large amounts of new variable generation capacities and large consumption 
needs, notably from electricity imports, are likely to contribute more than before, as these will be the 
main  beneficiaries  from  cross-border  infrastructure  development.  Those  building  grids  for  the  needs 
generated  in  other  Member  States  are  likely  to  contribute  less.  In  any  case,  such  cost  allocation  is 
likely  to  deliver  a  more  equitable  burden  sharing  among  Member  States.  It  should  be  noted  that 
Member States would be free to compensate for the  distributional or social impacts  created on their 
territory, subject to compliance with existing EU legislation in this field. 

This option would have a large positive environmental impact by delivering projects that are crucial 
for  reaching  the  20%  share  of  renewables  in  2020.  Given  the  higher  number  of  projects  delivered, 
limited  negative  impacts,  both  temporary  and  permanent,  can  be  expected  from  this  measure  on  the 
immediate environment and neighbourhood of projects. 

Ex  ante  cost  allocation  will  have  limited  administrative  impacts.  NRAs  will  be  required  to  get 
involved in the regulation of projects not situated on their territory and to cooperate more in groups 
with several other NRAs and TSOs from several different Member States. This could create additional 
needs for human and technical resources. Given its role in assisting NRAs and providing compromise 
solutions  for  cost  allocation  if  necessary,  it  is  estimated  that  ACER  would  have  additional  resource 
needs equivalent to about 1 full time position for every 15 cost allocation cases. Such additional costs 
would have to be covered under the budget allocated to energy infrastructures. 

Concerning  the  feasibility  of  such  a  measure,  implementing  an  ex  ante  cost  allocation  mechanism 
would  require  legislative  action  at  EU  level  to  establish  the  principle,  according  to  which  national 
tariffs  might  cover  costs  incurred  outside  of  the  territory  of  the  concerned  Member  State.  It  is  not 
expected  that  it  would  require  any  national  transposition  in  Member  States,  but  it  might  require 
regulatory adaptations in the way, in which NRAs approve investment costs. The establishment of a 
clear  cost  allocation  principle  and  a  procedure  would  ensure  the  framework  for  cross-border  cost 
allocation  negotiations  which  are  done  today  on  a  case-by-case  agreement  with  high  potential  for 
difficulties or resistance from national TSOs and NRAs to agree on a common cost allocation solution. 

The  overall  effectiveness  of  this  measure  is  considered  to  be  positive,  but  insufficient  to  fully 
address the investment challenge. 

Even assuming a smooth functioning of this new mechanism, ex ante allocation will prove impossible 
for certain projects, leaving a limited number of very complex projects without funding solution. Cost 
allocation  would  also  not  address  the  problem  of  insufficient  market  demand  for  security  of  supply 
projects, notably in gas. 

Suboption B.1.c: Ex ante cost allocation mechanism with ex post adjustment possibility 

The impacts of this suboption would be largely identical to the ones of the previous one. The ex ante 
cost allocation mechanism with ex post adjustment would however have slightly different economic 
and  distributional  impacts,  as  it  would  allow  for  changes  in  the  allocation  of  costs  over  a  given 
period  of  operation  of  the  considered  infrastructure.  This  would  notably  allow  to  take  into  account 
significant changes compared to initial assumptions on generation and load (e.g. if new capacities are 
added or existing ones withdrawn) or existing transmission capacities (e.g. if a new infrastructure is 
built in the immediate neighbourhood). 

While such a possibility would increase the precision of the allocation mechanism, it would also create 
financial uncertainty for TSOs and external investors and lenders who will have to take on a downside 
revenue risk. While such a risk is considered to be acceptable for larger TSOs who fund their projects 
on a corporate finance basis, it could be unacceptably high for smaller TSOs and for projects funded a 
non  recourse  project  finance  basis.  Such  risks  would  in  any  case  have  to  be  covered  by  a dedicated 
mechanism. 

Implementation  of  this  suboption  could  also  trigger  additional  administrative  costs,  as  TSOs  and 
NRAs could have to re-evaluate benefits and renegotiate cost allocation. . This sub-option may deter 

44

 
 
in particular other investors, such as third parties, as they may risk the guarantee for cost recovery if 
ex-post adjustments will take place. 

Because of these shortcomings, suboption B.1.b is the preferred suboption. 

OPTION B.2: Investment incentives 

Suboption B.2.a: Risk-related incentives for PCIs 

Incentives  for  PCIs  with  higher  risks  would  link  higher  return  to  higher  risks,  thereby  creating  a 
positive economic impact for infrastructure delivery in line with general regulatory principles, while 
recognising the challenges posed by certain investments. It is expected that PCIs without these higher 
risks would be implemented would be implemented regardless of the existence of such a scheme and 
would therefore not be affected. Tailoring incentives for a limited number of projects would reduce the 
risk of general overinvestment that TSOs would have, in case incentives were offered for all PCIs. 

The financial impact of such an adder on network tariffs would remain very limited, given that the 
expected volume of eligible investments is low. Assuming new annual investments of EUR 10 bn (an 
amount likely to be much larger than the value of new high-risk PCIs every year) and 30% of equity 
financing for these assets, Roland Berger has calculated that a premium of 2 percentage points would 
result in an EUR 60 m cost on an annual basis, or about 0.3% of overall transmission costs in Europe, 
which account for about 5-10% of final electricity and wholesale gas prices only (see Annex 18). The 
real impact would therefore most certainly be much smaller than EUR 60 m. 

As  these  incentives  will  mainly  benefit  offshore  grid  development  and  innovative  onshore  long-
distance transmission projects (because of the specific risks related to them), they would also provide 
significant positive environmental impacts in the medium to long term, as such infrastructure would 
enable deep GHG emission reductions and a much higher share of renewable energy. 

Once  established,  the  administrative  impact  for  such  measures  would  be  limited,  given  the  small 
number  of  eligible  projects,  especially if  covered by  national  tariffs.  If  paid  for  by  a  dedicated  fund 
filled with contributions from national tariffs or congestion rents in electricity, an entity at EU level 
would have to be tasked with collecting and managing these funds (e.g. ACER). 

In  terms  of  feasibility,  this  suboption  would  need  EU  legislative  action  establishing  the  precise 
conditions  triggering  the  obligation  for  NRAs  to  offer  such  incentives  and  rules  for  the  recovery  of 
corresponding  costs.  In  the  case  of  equity  adders,  national  regulators  could  have  to  adapt  their 
investment remuneration rules to prevent any cumulative effects with mark-ups existing under national 
regulation. This could require additional measures, including the modification of national adders. 

Suboption B.2.b: Penalties and enforcement action for PCIs 

This  suboption  could  in  theory,  by  forcing  TSOs  to  deliver  agreed  priority  projects,  increase  social 
welfare on European level. The economic impact for the concerned TSOs however could be negative, 
either  because  of  reduced  revenues  through  the  penalties  in  case  of  non  delivery,  or  because  of 
additional uncovered risks taken up in case of project delivery. This in turn could affect the capacity of 
the TSO to deliver on other projects. 

Administrative  impact  of  such  a  measure  would  be  limited.  Enforcement  of  investments  would 
require significant additional work from NRAs and possibly also ACER, though such cases are likely 
to be very rare, if the penalty/enforcement scheme is designed in a sufficiently dissuasive way. 

Concerning  feasibility,  such  measures  would  require  conferring  new  powers  to  NRAs,  which  some 
Member States might resist. They would also trigger strong opposition from TSOs. The added value of 
such  a  compulsory  scheme  compared  to  a  scheme  based  on  incentives  seems  therefore  limited. 
However,  if  a  future  review  of  these  incentive  instruments  concludes  that  they  are  not  sufficiently 
successful  in  leading  to  project  delivery,  a  solution  based  on  penalties  and  enforcement  could  be 
studied in more detail. 

As a result, suboption B.2.a is the preferred suboption. 

OPTION B.3: Ex-ante cost allocation and risk-related incentives for PCIs 

45

 
 
This  option  would  be  the  preferred  option,  as  it  would  combine  the  positive  impacts  of  both 
preferred suboptions and allow covering the largest number of PCIs. 

9.3. 

Financing 

OPTION C.1: Risk sharing instruments 

Concerning  economic  and  social  impacts,  this  option  would  improve  access  to  capital,  as  project 
promoters  would  be  able  to  use  new  sources  of  financing  (e.g.  bonds),  financing  on  more  adapted 
terms  and  risk  mitigating  measures  (e.g.  guarantees).  It  would  improve  the  commercial  viability  of 
projects and lead to positive investment decisions. Furthermore, the introduction of such instruments 
will  contribute  to  the  extending  capital  market  financing  (bonds)  to  infrastructure  and  create 
opportunities  in  the  energy  sector  for  new  classes  of  investors.  This  overall  positive  impact  will 
however  not apply  to  projects  lacking  commercial  viability94.  The decreased  cost  of  financing  made 
possible  would  also  translate  into  a  lower  overall  cost  of  PCIs,  thereby  having  a  positive  impact  on 
network tariffs. 

The  financial  impact  can  only  be  measured  once  concrete  PCI  are  identified  and  their  individual 
characteristics are known. For PCIs with low market demand, risk sharing instruments will not help. 
Like  risk  capital  instruments,  such  a  form  of  support  would  come  at  a  lower  expense  to  the  public 
budget  than  direct  grants.  The  multiplying  effect  of  EU  funds  used  this  way  could  be  particularly 
high:  it  is  estimated  that  EUR  1  from  the  EU  budget  could  facilitate  up  to  EUR  25  of  overall 
investment. An assumed EUR 500 m allocated to such instruments could facilitate implementation of 
projects worth up to EUR 12.5 bn. 

Introduction  of  risk  sharing  instruments  can  only  be  done  in  cooperation  with  financial  institutions 
charged with the administration of these instruments. This would reduce the administrative burden 
of the Commission, but additional resources would be needed within the financial institutions for set-
up and day-to-day management. 

In  terms  of  feasibility,  this  option  should  be  relatively  easy  to  implement,  as  it  would  not  require 
particular  legal  acts  at  national  level  and  it  not  expected  to  raise  opposition  from  stakeholders95. 
Implementation would need to be in line with the Commission's debt and equity platform. 

OPTION C.2: Risk capital instruments 

The  economic  and  social  impact  of  such  a  measure  would  positive,  as  provision  of  equity  would 
result in increasing financing capability of projects and additional stimulus for attracting investors and 
new  investor  groups.  By  assisting  projects  in  their  early  phase,  it  would  contribute  to  increase  and 
substantially  accelerate  the  pipeline  of  mature  projects,  especially  if  they  are  more  complex, 
innovative and involve a large number of stakeholders, thereby contributing to delivery of projects of 
European  relevance.  However,  such  instruments  are  unlikely  to  help  projects  lacking  commercial 
viability.  They  would  also  require  ring-fenced,  dedicated  project  structures,  which  remain  the 
exception in energy infrastructures. It seems therefore likely that they would only be applicable to a 
small subset of the needed investments. 

As for option C1, the financial impact can only be measured once concrete PCIs are identified and 
the individual characteristics of those projects known. For many PCIs, risk capital instruments will not 
be  the  adequate  form  of  support.  For  suitable  projects,  a  high  leverage  of  the  EU  budget  could  be 
expected  with  a  multiplying  factor  between  1  and  1096.  Assuming  EUR  500  m  of  dedicated  EU 
budget, up to EUR 5 bn worth of projects could be delivered this way. 

94  

95  

96  

Risk sharing instruments might however help projects close to the point of viability: measures such as e.g. lower 
cost of financing may make these projects bankable. 
Some  stakeholders  have  however  argued  that  such  instruments  should  be  made  available  for  all  infrastructure 
projects, not only projects of common interest. 
Every euro from the EU would generate between EUR 1 and 10 of investment. The effect could be even higher in 
case of re-cycling of the budgetary resources during the budgetary period. 

46

 
 
 
                                                 
The administrative impact (for the Commission) will be substantial if equity investments were to be 
done  directly,  i.e.  without  an  intermediary  financial  institution.  In  line  with  the  equity  platform 
proposal  that  the  Commission  is  currently  preparing,  indirect  investments  (i.e.  outsourced  to  a 
financial  institution)  are  the  more  likely  solution.  This  will  create  substantial  resource  needs  within 
these  financial  institutions,  equivalent  to  several  full-time  positions.  Providing  seed  capital  and 
accelerating project development would also require additional Commission resources, especially for 
bigger and more complex projects. 

In  terms  of  feasibility,  implementing  this  option  should  not  pose  particular  difficulties,  as  the 
Commission has previously implemented similar risk capital instruments both directly and indirectly 
(Marguerite  Fund,  Galaxy  Fund).  No  substantial  opposition  from  stakeholders  is  expected.  The 
implementation  would  need  to  remain  in  line  with  and  draw  on  the  preparatory  work  done  for  the 
Commission's equity platform. 

OPTION C.3: Grant support to project construction 

The main economic and social impact of option would be its very positive contribution to delivering 
PCIs  otherwise  not  developed  by  market  forces  alone  as  described  in  section  3.2.1.  This  would 
particularly apply to the project categories with high positive externalities but at risk as summarised in 
Annex 12. The economic impact would be particularly high as the grant intervention would only target 
the most relevant projects of European relevance, which, if not realised, would seriously hamper the 
achievement of the 2020 energy and climate policy objectives. Grants will also in particular help those 
MSs, which contribute most to building PCIs, while not necessarily benefiting most from them. As EU 
grants are normally excluded from the project value reflected in the Regulated Asset Base (RAB), they 
will contribute to keeping network tariffs lower than if costs were fully included in the RAB. 

The  financial  impact  will  depend  on  the  amount  of  projects  seeking  such  support,  but  our  analysis 
suggests that demand for funds will exceed the amounts that can realistically be made available. It will 
also depend on the co-financing rate applied to individual PCIs. The underlying principle would be to 
keep the rate of support at the absolute minimum needed to trigger investment in a PCI. Nevertheless, 
for  some  security  of  supply  projects,  up  to  80%  of  support  compared  to  eligible  costs  may  be 
necessary, compared to only about 10% in the lowest cases, thereby reducing the leverage effect of EU 
funds. Assuming about EUR 8 bn of dedicated EU budget and an average co-financing rate of 30%, 
grants  deliver  about  EUR  24  bn  worth  of  projects.  In  addition,  grant  support  would  ensure 
implementation  of  projects  having  previously  benefited  from  co-financing  for  studies,  thereby 
delivering greater overall effectiveness of EU funds97. 

The administrative impact for the Commission will be directly correlated with the number of project 
and  the  budget  available  to  support  them.  Such  a  grant  programme  would  imply  centralised 
management  (potentially  with  the  support  of  an  executive  agency)  and  hence  require  significant 
additional resources98. 

Finally,  this  option,  as  all  previous  financing  options,  would  have  a  significant  positive 
environmental  impact  by  delivering  projects  that  are  crucial  for  reaching  the  20%  share  of 
renewables  in  2020  and  preparing  the  infrastructure  for  the  longer  term  EU  energy  and  climate 
objectives  including  decarbonisation  of  energy  supply,  which  could  otherwise  suffer  from  the 
environmental externality problem described above. 

In terms of feasibility, implementation of this option should not pose problems. It directly builds on 
the  experience  with  the  implementation  of  TEN-E  and  EEPR.  The  modalities  for  such  a  grant 
instrument are already specified in the existing financial regulation and its implementing rules. Some 
limited adaptations would be nevertheless required in case of tendering and repayable grants. 

OPTION C.4: Combination of grants, risk sharing and risk capital instruments 

97  

98  

Under the current TEN-E framework, many projects receive co-financing for their studies, but are never realised 
afterwards, thereby creating substantial sunk costs. 
For the management of the 44 projects selected under the EEPR, the Commission needs an average of 5 full-time 
equivalents over a period of 7 years. 

47

 
 
                                                 
As  this  option  combines  options  C1,  C2  and  C3,  its  impacts  derive  from  the  combination  of  the 
impacts of the individual options. But providing a toolbox of market-based instruments (C1 and C2) 
and  direct  financial  support  (C3)  will  also  lead  to  synergies  and  efficiency  gains,  as  it  will  be 
possible to flexibly provide the most cost-effective solution for specific project risks and features. 
The implementation of some projects will be sufficiently stimulated by risk sharing and/or risk capital 
instruments,  whereas  for  a  limited  number  of  PCIs,  grants  will  be  only  solution.  Consequently  the 
economic,  social  and  environmental  impact  would  be  highest,  as  all  investments  could  be 
supported as necessary in view of implementing the defined infrastructure priorities by 2020, provided 
the overall amount of about EUR 9.1 bn available EU budget is confirmed. The financial impact of 
this toolbox could be optimised on a project-by-project basis99. 

In  terms  of  administrative  impact,  the  combination  of  various  forms  of  EU  level  support  would 
inevitably  require  additional  resources  within  the  Commission  and  for  financial  institutions. 
Nevertheless,  economies  of  scale  between  the  different  instruments  could  be  achieved  through 
efficient coordination, thereby keeping the burden below the burden level reached if each option were 
implemented  separately.  Finally,  this  option,  despite  being  the  most  comprehensive  response  to  the 
identified challenges, would not be more difficult to implement than any of its individual components. 

As a result, this option is the preferred one. It reflects the proposals concerning the future EU 
budget  as  made  by  the  European  Commission  on  29  June  2011.  It  fully  reflects  the  proposed 
Connecting Europe Facility. 

10. 

COMPARISON OF POLICY OPTIONS 

From  the  analysis  in  the  previous  chapter,  the  following  options  have  been  identified  as  preferred 
options: 
•  Concerning  permit  granting:  establishment  of  a  regime  of  common  European  interest,  full  one-

stop shop and time limit for projects of common interest; 

•  Concerning regulation: ex ante cost allocation and risk-specific incentives for PCIs; 
•  Concerning financing: combination of grants, risk sharing and risk capital instruments. 

While the establishment of a regime of common European interest is a pre-condition for accelerating 
the premit granting process, only a full one-stop shop with a unified time limit defined for all projects 
of  common  interest  can  ensure  timely  delivery  of  the  needed  infrastructure  investments  and  thereby 
also reduce administrative burden. 

Ex ante cost allocation and incentives targeted at the most risky projects would ensure delivery of a 
significant  share  of  projects  of  common  interest,  which  have  assymmetric  costs  and  benefits  across 
borders,  use  innovative  technologies  or feature  other  kinds  of  specific  risks.  By  keeping  the  ex  ante 
allocation  process  rather  simple,  with  responsibility  for  finding  solutions  first  and  foremost  in  the 
hands  of  TSOs  and  NRAs,  and  by  not  introducing  a  complicated  ex  post  adjustment  mechanism,  it 
strikes the right balance between effectiveness and efficiency. 

Finally, only the full combination of all market-based risk sharing and risk capital instruments together 
with  EU  grants  will  allow  addressing  in  the  most  efficient  way  the  individual  needs  of  projects  and 
theerefore  delivering  the  highest  number  of  projects  of  common  interest,  including  commercially 
viable projects with specific risks that can be addressed by risk sharing facilities, complex project at 
early  stage  that  need  to  be  triggered  by  seed  funding,  and  commercially  non  viable,  but  socio-
economically beneficial projects that necessite direct support. The provision of significant amounts of 
EU grants will be vital to guarantee implementation of all projects at risk identified in chapter 4, as 
proposed by the European Commission in its Communication on the future budget for Europe. 

From the previous analysis, it can be concluded that none of preferred measures in the different 
policy areas taken alone is capable of delivering the necessary investments, given the multiplicity 

99  

The precise allocation of the total budget amount available to risk sharing instruments, risk capital instruments and 
grants  cannot  be  specified  at  this  stage,  as  it  will  require  further  analysis  and  be  subject  to  the  results  of  the 
proposed selection and evaluation process (including cost-benefit analysis) for PCIs. 

48

 
 
                                                 
of obstacles faced. This calls for policy action combining the preferred options identified in each 
policy area. Indeed, the preferred options can only provide their full benefits in conjunction with 
the  preferred  options  in  the  other  two  policy  areas.  With  more  efficient  and  transparent  permit 
granting,  the  project  pipeline  ready  for  cost  allocation  or  financing  will  simply  not  be  sufficient  to 
meet the 2020 target. Without appropriate regulatory measures, there is a high risk of delays for cross-
border coordination, even if permit granting goes smoothly. It may also imply an inefficient spending 
of  EU  funds,  as  grants  could  be  provided  to  projects  that  might  have  simply  required  proper  cost 
allocation,  or  seed  capital  involvement  in  projects  who  could  have  gone  ahead  with  a  regulatory 
incentive  alone.  Without  appropriate  financing  instruments  at  EU  level  including  direct  grants,  the 
projects providing large benefits to the EU as a whole without being commercially viable will not be 
built, leaving also the permit granting and regulatory measures applied before without final success. 

Realising the needed investments between now and 2020 will have a significant impact on the cost of 
transmission,  notably  in  electricity.  According  to  ENTSO-E  estimations,  EUR  100  billion  of  new 
investment  would  represent  on  average  about  1.5-2€  per  MWh  (0.15-0.2c€/kWh)  of  power 
consumption in Europe over the next 10 years or about 2% of the bulk power prices. This calculation 
does  not  take  account  of  possible  variations  between  Member  States  and  the  cumulative  effect  that 
these  investments  will  have  together  with  the  costs  for  grid  refurbishment  necessary  to  replace  old 
infrastructure.  According  to  Commission  estimations,  total  electricity  infrastructure  investments  for 
the  period  2011-2020  could  amount  to  about  one  to  two  times  the  value  of  the  TSOs'  existing 
regulated asset base (RAB)100. But this average hides big variations, with certain Member States facing 
investments  worth more than three times their current RAB. Network tariffs could double in certain 
Member  States101.  Even  if  the  share  of  transmission  costs  in  overall  electricity  and  gas  prices  is 
limited, the impact of this RAB increase on final prices could be significant102 and compounded by the 
expected  increase  of  electricity  prices  due  to  the  cost  of  national  renewables  support  schemes  and 
could  become  politically  sensitive  in  different  Member  States  in  various  parts  of  the  EU.  This 
underlines  the  benefit  expected  from  providing  EU  grants  to  projects  with  high  European  but 
insufficient commercial value. 

With  the  chosen  package  of  preferred  options,  the  negative  impacts  on  the  environment, 
individual  citizens  and  tariffs  will  be  largely  outweighed  by  the  benefits  expected  from  the 
completion of the trans-European networks. This completion will allow achieving the energy and 
climate  targets  agreed  at  EU  level,  notably  the  20%  renewables  share  and  the  20%  GHG  emission 
reduction by 2020. Adequate infrastructure will also facilitate the full integration of the internal energy 
market  in  electricity  and  gas,  thereby  creating  new  opportunities  for  system  optimisation  and 
efficiency, competition and choice for the final consumer and hence exerting a overall lowering effect 
on energy prices. But it will also make our energy supplies more secure, by providing diversification 
of sources, routes and counterparts and by increasing system stability, but also by improving the the 
security  and  climate  resilience  of  our  networks.  All  this  will  contribute  to  the  significant  positive 
overall effect on GDP and employment already identified in the 2010 impact assessment (+0.42% of 
growth  and  410,000  additional  jobs  compared  to  the  baseline  scenario  over  the  period  2011-2020). 
The  preferred  package  of  options  is  therefore  considered  proportional,  effective  and  efficient  with 
regard to the objectives pursued. Table 6 below summarises the impacts of all options and suboptions. 

Options 

Economic  and  social 
impacts 

A.1 Regime of Common  + 

Environmental 
impacts 
= 

Other impacts 

Legal feasibility: - 

100  

101  

102  

The RAB is a valuation concept to determine the value of assets detained by a TSO. The closing regulatory asset 
base  at  the  end  of  a  period  is  equal  to  the  opening  asset  base  at  the  start  of  that  period  plus  any  new  capital 
expenditure less any depreciation that occur during the regulatory period. Several TSOs have confirmed that their 
RAB is set to double over the period 2010-2020. 
Commission calculation. While the relationship between an increase in investments and the corresponding increase 
in tariffs is complex, depends on many factors (evolution of electricity consumption, operational expenses, losses, 
system  services  and  other  costs)  and  differs  from  Member  State  to  Member  State,  it  is  possible  to  make 
approximations with regard to the tariff impact. 
In a Member State where network costs make up for 10% of the total electricity bill, a 100% increase of these costs 
would increase electricity prices by 10%. 

49

 
 
                                                 
Options 

European Interest 
A.2 full one-stop shop 
and time limit of 4 years 
A.3 Regime of Common 
European Interest, full 
one-stop shop and time 
limit of 4 years 
B.1 Ex-ante cost 
allocation 
B.2 Risk-related 
incentives for PCIs 
B.3 Ex-ante cost 
allocation and risk-
related incentives for 
PCIs 
C.1 Risk-sharing 
instruments 
C.2 Risk capital 
instruments 
C.3 Grant support for 
project construction 
C.4 Combination of 
grants, risk sharing and 
risk capital instruments 
A3 & B3 & C4 

Economic  and  social 
impacts 

Environmental 
impacts 

Other impacts 

++ 

+++ 

++ 

++ 

+++ 

+++ 

++ 

+++ 

+++ 

+++ 

+ 

++ 

+ 

+ 

++ 

+ 

+ 

++ 

++ 

+++ 

Legal feasibility: - 

Legal feasibility: - 

Administrative: - 

Tariff impact: - 

Administrative 
tariff impact: - 

and 

Administrative: - 

Administrative: - 

Administrative: - 
Tariff: + 

Legal, administrative: - 
Tariff: + 

Table 6: Summary of impacts (= equivalent to baseline; + to +++ improvement compared to baseline; - to - - - 
worsening compared to baseline) 

11. 

MONITORING AND EVALUATION 

In  line  with  the  measures  proposed  in  the  preceding  IA,  the  following  specific  indicators  would  be 
used to monitor the evolution of the policy: 

Concerning  the  general  implementation,  by  2020,  of  projects  of  common  interest  necessary  to 
implement the trans-European energy infrastructure priority corridors as defined by the February 2011 
European Council conclusions: 

•  The general progress achieved for each project of common interest selected under the defined 
priority corridors (number of projects planned, under construction or commissioned; installed 
capacity  and,  if  applicable,  length  of  lines):  This  will  be  monitored  on  the  basis  of  regular 
reports from project promoters and national regulators. 

•  The interconnection level between Member States and the corresponding evolution of energy 
prices:  Concerning  electricity,  interconnector  capacity  defined  as  the  ratio  between  import 
capacity  and  installed  generation  capacity  in  a  given  Member  State  could  be  used,  as  well 
price  differentials  observed  between  international  interconnectors.  Concerning  gas,  price 
differentials between  major European hubs could be used. Price monitoring is already being 
done by DG ENER’s Energy Market Observatory; 

•  For electricity, the installed capacities for electricity generation from renewable sources, with 
a  specific  focus  on  offshore  wind  generation.  This  will  be  monitored  through  the  biennial 
reports  Member  States  must  submit  to  the  Commission  under  article  22  of  the  renewables 
directive; 

50

 
 
 
•  For gas, the share of each import source in overall imports (at national, regional and EU level) 
and the compliance with the N-1 and reverse flow. The latter two will be monitored under the 
Security of supply Regulation. 

a)  Concerning permit granting procedures and public involvement and acceptance: 

• 

• 

• 

the  average  and  maximum  total  duration  of  authorisation  procedures  for  projects  of 
common interest in electricity and gas; 

the  duration  of  each  step  of  the  authorisation  procedure  for  projects  of  common 
interest, compared to the timing foreseen by the initially agreed project milestones; 

the  level  of  opposition  faced  by  projects  of  common  interest  (number  of  written 
objections during the public consultation process, number of legal recourse actions). 

The data in this section will be monitored on the basis of regular reports from project promoters 
and Member States. 

b)  Concerning the regulatory treatment of projects of common interest: 

•  The  number  of  projects  of  common  interest  having  reached  a  cost  allocation 

agreement among TSOs and NRAs; 

•  The average duration for reaching an cost allocation agreement; 

•  The  number  and  type  of  projects  of  common  interest  having  received  specific 

incentives and/or support by NRAs; 

The data in this section will be monitored on the basis of regular reports from project promoters 
and national regulators. 

c)  Concerning market-based and direct EU financial support: 

•  The total value of annual investments in electricity and gas transmission, storage and 

LNG/CNG, compared to total investments during the period 2007-2013; 

•  The  annual  value  of  EU  funds  engaged  compared  to  the  total  value  of  beneficiary 

projects of common interest, for each instrument and as a whole; 

•  The  timeliness  of  disbursing  engaged  EU  funds,  both  for  market-based  instruments 
and EU grants, compared to initial project milestones and corresponding reasons. 

The Commission would ensure monitoring and evaluation via an implementation report on a bi-annual 
basis, a mid-term evaluation in 2017 and a final evaluation. In addition, the Commission proposes to 
set  up  a  transparency  platform  allowing  the  general  public  to  follow  the  advancement  of  individual 
projects of common interest. 

51

 
 
ANNEX 1 
GLOSSARY 

Agency for the Cooperation of Energy Regulators 

Business As Usual 

Baltic Energy Market Interconnection Plan 

Carbon Capture and Storage 

Compressed Natural Gas 

European Bank for Reconstruction and Development 

Environmental Impact Assessment 

European Energy Plan for Recovery 

European Investment Bank 

European Network of Transmission System Operators in Electricity 

European Network of Transmission System Operators in Gas 

European Regulators' Group for Electricity and Gas 

Emission Trading Scheme 

Gross Domestic Product 

Greenhouse Gas 

Gas Infrastructure Europe 

Giga Watt 

Impact Assessment 

Information and Communication Technology 

Inter-Transmission System Operator Compensation 

Liquefied Natural Gas 

Member State 

National Regulatory Authority 

ACER   

BAU 

BEMIP  

CCS 

CNG 

EBRD   

EIA 

EEPR 

EIB 

ENTSO-E 

ENTSOG 

ERGEG 

ETS 

GDP 

GHG 

GIE 

GW 

IA 

ICT  

ITC 

LNG 

MS 

NRA 

NSCOGI 

North Sea Countries Offshore Grid Initiative 

PCI 

RAB 

RES 

TEN-E   

TFEU 
3rd IEMP 

TPA 

TSO 

TWh 

TYNDP 

WACC 

Project of Common Interest 

Regulated Asset Base 

Renewable Energy Sources 

Trans-European Networks for Energy 

Treaty on the Functioning of the European Union 

Third Internal Energy Market Package 

Third Party Access 

Transmission System Operators 

Tera Watt hour 

Ten-Year Network Development Plan 

Weighted Average Cost of Capital

52

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ANNEX 2 
INPUT DOCUMENTS 

The impact assessment builds on the results of the following studies, some of which have already been 
used for the 2010 impact assessment (marked by an asterisk): 

1.  General 

− 

"Adaptation and Mitigation Strategies (ADAM) – Supporting European Climate Policy", project 
funded by the European Commission, final report, June 2009. http://www.adamproject.eu/  

−  *  Arup,  "Feasibility  of  Europe-wide  CO2  infrastructures",  study  for  the  European  Commission 

DG Energy, 2010. 

−  * Boston Consulting Group "Electricity Storage: Making Large-Scale Adoption of Wind and Solar 

Energies a Reality", study by Cornelius Piper and Holger Rubel, March 2010. 

−  CEER,  "European  Infrastructure  Package:  Investment  needs  and  financing  mechanisms  – 

Financing Task Force conclusions", Reference C11-FTF-02-01, 23 March 2011 

- 

*  Centro  Elettrotecnico  Sperimentale  Italiano,  Instituto  de  Investigación  Tecnológica,  Mercados 
Energeticos,  Ramboll,  "Energy  Infrastructure  Costs  and  Investments  between  1996  and  2013 
(medium-term)  and  further  to  2023  (long-term)  on  the  Trans-European  Energy  Network  and  its 
Connection to Neighbouring Regions with emphasis on investments on renewable energy sources 
and  their  integration  into  the  Trans-European  energy  networks,  including  an  Inventory  of  the 
Technical Status of the European Energy-Network for the Year 2003" (TEN-Energy-Invest), study 
for the European Commission DG Energy and Transport, October 2005. 

−  *  COWI,  Cambridge  Econometrics  and  KEMA,  "The  revision  of  the  trans-European  energy 
network  policy  (TEN-E)",  impact  assessment  study  for  the  European  Commission  DG  Energy, 
October 2010. 

−  * ENTSO-E, "Ten-Year Network Development Plan", 2010. https://www.entsoe.eu/index.php?id=232 

−  *  ENTSO-E,  "System  Adequacy  Forecast  2010-2025",  2009.  https://www.entsoe.eu/resources/ 

publications/system-development/ 

−  ENTSOG, 

Development 
http://www.entsog.eu/publications/index_g_investment.html 

"Ten-Year 

Network 

Plan", 

February 

2011. 

−  *  European  Commission,  Joint  Research  Centre  (JRC),  "Evolution  of  size  and  cost  of  a  trans-

European CO2 pipeline network", 2010. 

−  European  Commission,  "The  implementation  of  the  Trans-European  Energy  Networks  in  the 
period 2007-2009", report pursuant to Article 17 of Regulation (EC) 680/2007 and Articles 9(2) 
and 15 of Decision 1364/2006/EC, COM(2010)203, May 2010. 

−  European  Commission,  "Annex  to  Report  on  the  implementation  of  the  Trans-European  Energy 
Networks in the period 2007-2009", Commission Staff Working Document, SEC(2010)505, May 
2010. 

−  European Commission, "Energy infrastructure priorities for 2020 and beyond – A Blueprint for an 

integrated European energy network", COM(2010)677, November 2010. 

−  European  Commission,  "Impart  assessment  on  Energy  infrastructure  priorities  for  2020  and 
beyond  –  A  Blueprint  for  an  integrated  European  energy  network",  Commission  Staff  Working 
Document, SEC(2010)1396, November 2010. 

53

 
 
 
 
 
−  European  Commission,  "Smart  Grids:  from  innovation  to  deployment",  COM(2011)202,  April 

2011. 

−  European  Commission,  “Energy  Infrastructure  Investment  needs  and  financing  requirements”, 

Commission Staff Working Document (SEC(2011)755 final), June 2011. 

−  European Commission, “2009-2010 Report on progress in creating the internal gas and electricity 

market”, Commission Staff Working Document, 2011. 

−  European Commission, “DG ENER Staff Working Document: Report on Progress in Creating the 

Internal Gas and Electricity Market – Technical Annex”, 2011. 

−  European Parliament, "Energy Infrastructure Priorities", Directorate-General for Internal Policies, 
Policy  Department  Economic  and  Scientific  Policy  –  Industry,  Research  and  Energy,  Briefing 
Paper, March 2011. 

−  * EWI, "Model-based Analysis of Infrastructure Projects and Market Integration in Europe with 

Special Focus on Security of Supply Scenarios", University of Cologne, May 2010. 

−  *  "EWIS  –  European  Wind  Integration  Study",  final  report,  March  2010.  http://www.wind-

integration.eu/ 

−  * High-Level Advisory Group on ICT for Smart Electricity Distribution Networks: “ICT for a low 
carbon  Economy  –  Smart  Electricity  Distribution  Networks”,  supported  by  the  European 
Commission, DG for Information Society and Media, July 2009. 

−  *  ILF,  Purvin&Gertz,  "Technical  Aspects  of  Variable  Use  of  Oil  Pipelines  coming  into  the  EU 

from Third Countries", study for the European Commission DG Energy, 2010. 

−  *  OffshoreGrid 

study, 
http://www.offshoregrid.eu/ 

various 

presentations 

and 

interim 

reports, 

July 

2011. 

−  * Ramboll Oil and Gas, "Study on natural gas storage in the EU", October 2008. 

−  *  Supponen,  Matti,  “Influence  of  national  and  company  interests  on  European  electricity 

transmission investments”, PhD thesis for the Helsinki University of Technology, 2011. 

−  US  National  Research  Council,  "Hidden  Costs  of  Energy:  Unpriced  Consequences  of  Energy 

Production and Use", 2010. http://www.nap.edu/openbook.php?record_id=12794&page=R1 

−  Van  Ierland,  E.C.,  K.  de  Bruin,  R.B.  Delink,  A.  Ruijs  (eds.),  "Routeplanner  naar  een 
klimaatbestendig  Nederland  –  A  qualitative  assessment  of  climate  adaptation  options  and  some 
estimates of adaptation costs", Study performed within the framework of the Netherlands Policy 
Programme ARK, 2007. 

−  Vattenfall, "Höchstspannungsnetze: Freileitungen oder Kabel? Eine Analyse der Vattenfall Europe 

AG mit dem Beispiel des 380-kV-Kabelprojekts in Berlin", Vattenfall Europe, 2006. 

2.  Selection process and criteria 

−  Awad, M., K.E. Casey, A.S. Geevarghese, J.C. Miller, A.F. Rahimi, A.Y. Sheffrin, M. Zhang, E. 
Toolson,  G.  Drayton,  B.F.  Hobbs,  and  F.A.  Wolak,  "Economic  Assessment  of  Transmission 
Upgrades:  Application  of  the  California  ISO  Approach",  Ch.  7,  in  X.-P.  Zhang,  Restructured 
Electric  Power  Systems:  Analysis  of  Electricity  Markets  with  Equilibrium  Models,  Power 
Engineering Series, IEEE Press, July 2010. 

−  Proost, S., F. Dunkerley, S. Van der Loo, N. Adler, J. Bröcker, A. Korzhenevych, "Do the selected 
Trans European transport investments pass the Cost Benefit test?", Center for Economic Studies – 
Discussion papers, Katholieke Universiteit Leuven, Centrum voor Economische Studiën, February 
2010. 

− 

"REALISEGRID – Research, Methodologies and Technologies for the effective development of 
pan-European  key  grid  infrastructures  to  support  the  achievement  of  a  reliable,  competitive  and 

54

 
 
sustainable  electricity  supply",  project  supported  by  the  European  Commission,  various  reports 
and final conference, February 2011. http://realisegrid.rse-web.it/default.asp: 

−  D3.7.2:  Improving  consensus  on  new  transmission  infrastructures  by  a  thorough 

presentation of the benefits given by priority projects, Final, 2011-03-29. 

−  D3.3.1  Possible  criteria  to  assess  technical-economic  and  strategic  benefits  of  specific 

transmission projects 2010-04-29. 

−  D3.3.3  Tool  for  the  assessment  of  benefits  given  by  the  expansion  of  transmission 

infrastructures 2011-06-13. 

−  D3.4.2  Tool  for  a  coordinated  assessment  of  investments  in  electricity  and  gas 

infrastructures 2010-12-10. 

−  Rebours,  Y.,  M.  Trotignon,  V.  Lavier,  T.  Derbanne,  and  F.  Meslier,  “How  much  electric 
interconnection capacities are needed within Western Europe?”, Conference on European Energy 
Markets (EEM), June 2010. 

3.  Regulation and financing 

−  CEER,  "Energy  Infrastructure  Package  –  Draft  Position  Paper  on  Cost  Allocation",  Reference 

C11-IBP-30-03, 25 March 2011. 

−  ENTSO-E, "Overview of Transmission Tariffs in Europe: Synthesis 2010", September 2010. 

−  EUI THINK project, "Transition towards a low carbon energy system by 2050: What role for the 

EU?", draft report, 18 April 2011. 

−  Faruqui, Ahmad, Dan Harris, Ryan Hledik, "Unlocking the €53 billion Savings from Smart Meters 

in the EU", The Brattle Group Discussion Paper, October 2009. 

−  Glachant,  Jean-Michel,  Haikel  Kalfallah,  “Identifying  Benefits  and  Allocating  Costs  for  Cross-
Border Electricity & Gas Infrastructure Projects”, European Commission and  Florence School of 
Regulation workshop conclusions, 4 May 2011 

−  Helm, Dieter, "Redefining the models for private sector investment in infrastructure – The RAB 

Model", 9th February 2011 presentation, Slides for the UK Infrastructure Summit. 

−  Helm,  Dieter,  and  Tom  Tindall,  "The  evolution  of  infrastructure  and  utility  ownership  and  its 
implications, Oxford Review of Economic Policy, Volume 25, Number 3, 2009, pp.411–434. 

− 

IEA, "Technology Roadmap Smart Grids", April 2011. 

−  * KEMA, REKK, "Methodologies for Gas Transmission Network Tariffs and Gas Balancing Fees 
in Europe", study for the European Commission DG Transport and Energy, December 2009. 

−  Meeus, Leonardo; Saguan, Marcelo; Glachant, Jean-Michel; Belmans, Ronnie, "Smart Regulation 
for  Smart  Grids",  European  University  Institute  (EUI),  Robert  Schuman  Centre  for  Advanced 
Studies, EUI Working Paper RSCAS 2010/45 

−  Pelkmans,  Jacques,  Lionel  Kapff,  “Interconnector  Investment  for  a  Well-fuctioning  Internal 
Market:  What  EU  regime  of  regulatory  incentives?”,  Bruges  European  Economic  Research 
Papers, BEER n°18, 2010. 

−  Rious, Vincent, Jean-Michel Glachant, Philippe Dessant, "Transmission network investment as an 

anticipation problem", EUI Working Paper RSCAS 2010/04, January 2010 

−  Roland  Berger,  "Study  on  the  structuring  and  financing  of  energy  infrastructure  projects,  the 
financing  gaps  and  recommendations  regarding  the  new  TEN-E  financial  instrument",  study  for 
the European Commission DG Energy, May 2011 (2011a). 

−  Observatoire Méditerranéen de l’Energie, "Realisegrid – D3.6.2: Incentive schemes and regulation 

framework for transmission development in Europe", final report, 29 April 2010. 

55

 
 
−  Rothschild, presentation at the Hungarian EU Council Presidency / European Commission high-

level energy infrastructure conference, May 2011. 

−  SAP, "Smart Grids for Europe: Benefits, Challenges, and Best Practices", 2011. 

−  Union of the Electricity Industry (Eurelectric), Subgroup Regulation for Smart Grids – Networks 

Committee, Manuel Rodrigues Da Costa (PT) Chair, "Regulation for smart grids", 2011. 

4.  Permit granting, stakeholder involvement and compensation 

−  ENTSO-E,  "Position  Paper  on  permitting  procedures  for  electricity  infrastructure,  2010. 

https://www.entsoe.eu/fileadmin/user_upload/_library/position_papers/100629-ENTSO-
E_response_permitting_procedure.pdf  

−  ERSE,  "Realisegrid:  Preliminary  results  on  streamlining  planning  and  approval  procedures  of 
electricity  transmission  infrastructures",  interim  report,  2  July  2010.  http://realisegrid.rse-
web.it/content/files/File/Publications%20and%20results/Interim%20report.pdf  

−  ETSO,  Overview  of  the  administrative  procedures  for  constructing  110  kV  to  400  kV  overhead 
https://www.entsoe.eu/fileadmin/user_upload/_library/publications/etso/others/ 

lines, 
procedures%20400%20kv%20lines.pdf 

2006. 

−  EWEA, "Wind Barriers", 2010. http://www.windbarriers.eu/index.php?id=3 

−  Haas,  Dieter;  Schuerenberg,  Bernd,  "Stromtod  von  Vögeln,  Grundlagen  und  Standards  zum 

Vogelschutz an Freileitungen", 2003. http://www.birdsandpowerlines.org/ 

−  Ramboll, Mercados, "TEN-E Priority Corridors for Energy Transmission", study for the European 

Commission DG Energy and Transport, 2008. 

−  Roland Berger, "Permitting procedures for energy infrastructure projects in the EU: evaluation and 
legal recommendations", study for the European Commission DG Energy, May 2011 (2011b). 

−  UK  Department  for  Communities  and  Local  Government,  "Localism  Bill:  major  infrastructure 
http://www.communities.gov.uk/publications/ 

Impact 

projects, 
2011. 
localgovernment/localismimpactassessmentsum 

assessment", 

56

 
 
 
ANNEX 3 
RESULTS FROM THE PUBLIC CONSULTATION ON PERMIT GRANTING 

Executive summary 

Adequate,  integrated  and  reliable  energy  networks  are  a  crucial  prerequisite  for  EU  energy 
policy goals and for the EU's economic strategy. The European Commission has therefore, in 
its Communication "Energy infrastructure priorities for 2020 and beyond - A Blueprint for an 
integrated  European  energy  network"  put  forward  a  strategy  for  a  new  European  energy 
infrastructure  policy.  In  autumn  2011,  the  Commission  will  table  a  legislative  proposal, 
identifying  the  tools  necessary  for  the  implementation  of  this  policy.  As  widely 
acknowledged,  one  of  the  main  obstacles  impeding  and  delaying  energy  infrastructure 
development  are  long  and  non-transparent  permit  granting  processes,  along  with  a  lack  of 
public acceptance. Therefore, the Commission has been assessing possible solutions to ensure 
effective and time-efficient planning and coordination, good administrative practice as well as 
a more transparent and inclusive decision-making and communication approach. 

In  this  context,  as  part  of  the  process  of  preparing  the  legislative  proposal,  a  public 
consultation was launched, which was open from 1 March - 30 April 2011.103 81 replies were 
received  –  13  from  Member  States,  57  from  the  industry  and  related  organisations,  1 
academic  contribution  and  10  from  civil  society,  namely  citizens  and  NGOs.  Contributions 
from  the  industry  were  provided  by  system  operators  (transmission  as  well  as  distribution), 
producers,  the  renewable  industry  and  chambers  of  commerce  as  well  as  other  industry 
associations. This report summarises the contributions received. 

Public consultation questions and summary of replies: 

Question 1 Measures to facilitate the administrative procedures: "one-stop shop", time limits, 
and rewards and incentives:  
The introduction of binding time limits and a "one-stop-shop" (of some form) were welcomed 
by an overwhelming majority of respondents (60 % and 79 % respectively104).  Issues raised 
were  national  competence,  the  degree  of  decision-making  power  of  the  competent  authority 
and the avoidance of additional administrative structures. 30% of respondents supported the 
provision of rewards and incentives to facilitate project development while 20 % opposed this 
measure.  

Question 2 Guidelines to increase the transparency and predictability of the permit granting 
process:  
Guidelines were mostly considered useful. The three issues that were raised most often were a 
better communication strategy for the economic and social benefits of infrastructure projects, 
the full and early provision of environmental information and thus an earlier involvement of 
the  public  in  infrastructure  planning  (e.g.  providing  and  explaining  grid  expansion  plans). 
Member  States  stressed  that  especially  in  communicating  with  the  public  the  subsidiary 
principle has to be respected. 

103 http://ec.europa.eu/energy/infrastructure/consultations/20110430_infrastructure_projects_en.htm 
104 with  approximately 20 % not expressing a clear preference 

57

 
 
 
 
 
 
 
 
 
 
                                                 
Question 3 Improving public acceptance of infrastructure projects:  
Overall responses indicated that the main responsibility for communication should be with the 
project developer, but that local, regional, national and European authorities should facilitate 
these measures (depending on the project) and provide political support. An early discussion 
of  possible  environmental  and  health  risks,  a  better  communication  of  the  purpose  of 
infrastructure  projects  by  the  TSOs  and  the  inclusion  of  more  stakeholders  in  the  planning 
process were considered suitable measures by several respondents. 

Question 4 Compensation mechanisms to facilitate infrastructure projects: 
Roughly  half  of  the  respondents  were  opposed  to  the  harmonisation  or  standards  for 
compensation  mechanisms  across  the  EU  and  believed  that  the  competence  here  should 
remain within the Member States. Other respondents, mainly from the industry, believed that 
some form of standardisation can be helpful, especially with respect to cross-border projects. 

Question 5 Experience with national best practices: 
Several  best  practices  were  reported  that  were  successfully  addressing  different  issues,  e.g. 
longer pre-application procedures, a central coordination body within the ministry, a national 
grid development plan or non-monetary compensation measures for affected communities. 

Detailed summary 

Adequate,  integrated  and  reliable  energy  networks  are  a  crucial  prerequisite  for  EU  energy 
policy goals and for the EU's economic strategy. The European Commission has therefore, in 
its Communication "Energy infrastructure priorities for 2020 and beyond - A Blueprint for an 
integrated  European  energy  network"  put  forward  a  strategy  for  a  new  European  energy 
infrastructure policy. In autumn 2011, the Commission will table a legislative proposal which 
will put forward the tools necessary for the implementation of this policy. 

A  long  and  uncertain  permit  granting  process  was  indicated  by  many  major stakeholders as 
one  of  the  main  reasons  for  delay  of  infrastructure  projects.  The  time  between  the  start  of 
planning  and  final  commissioning  of  a  power  line  is  frequently  more  than  ten  years, 
assumingly  preventing  up  to  50%  of  commercially  viable  projects  from  being  realised  by 
2020. Reasons are manifold: Non-transparent permit granting procedures, coupled with lack 
of political support as well as the opposition of affected citizens. Cross-border projects face 
additional  opposition,  as  they  are  frequently  perceived  as  mere  "transit  lines"  without  local 
benefits. 

The Commission is therefore assessing how to improve the administrative procedures existing 
in  the  Member  States,  to  ensure  an  efficient  upfront  planning  of  the  permits,  time-efficient 
coordination  and  good  administrative  practice.  The  permit  granting  process  should  also  be 
made more transparent for all stakeholders and the general public, and communication with 
the affected population needs to be improved. 

58

 
 
 
 
 
 
 
 
 
 
 
 
 
 
In  this  context,  as  part  of  the  process  of  preparing  the  legislative  proposal,  a  public 
consultation  was  launched,  which  was  open  from  1  March  -  30  April  2011.105  The  public 
consultation  was  based  on  a  questionnaire  of  five  open  questions  addressing  the  following 
issues: 
1.  measures  to  improve  administrative  procedures  ("one-stop  shop",  time  limits,  rewards 

and incentives) 

2.  introduction of guidelines to increase transparency and predictability 
3.  improving communication with citizens to ensure higher public acceptance 
4.  requirements for compensation mechanisms at individual and community level 
5.  existing best-practices at national level to facilitate the permit granting process. 

81  replies  were  received  –13  from  Member  States,  57  from  the  industry  and  related 
organisations,  1  academic  contribution  and  10  from  civil  society,  namely  citizens  and 
NGOs. Contributions from the industry were provided by system operators (transmission as 
well as distribution), producers, the renewable industry and chambers of commerce as well as 
other  industry  associations.  The  individual  contributions  have  been  published  on  the  public 
consultation's webpage.106 

The  broad  spectrum  of  respondents  offers  an  insight  into  a  large  range  of  stakeholder 
opinions. 

Question 1:   As  explained  above  [see  consultation  document],  a  complex  and  non-
transparent procedural framework as well as poor administrative practice are 
major  reasons  for  delays.  There  are  different  options  which  could  help  to 
facilitate  administrative  procedures.  These  include,  as  outlined  in  the 
Communication "Energy infrastructure priorities for 2020 and beyond - A 
Blueprint for an integrated European energy network", the establishment of a 
national  contact  and  coordination  body  ("one-stop  shop")  per  cross-border 
project,  the  introduction  of  a  time  limit,  and  the  provision  of  rewards  and 
incentives  to  regions  or  Member  States  which  facilitate  the  permit  granting 
process.  Would  you  consider  these  measures  as  useful?  If  so,  under  which 
conditions? Are there any additional measures you would propose to facilitate 
the administrative procedures? 

The  proposed  measures  were  generally  welcomed  as  an  attempt  to  tackle  the  existing 
problems  and  delays  in  administrative  procedures.  Whilst  agreeing  with  certain  suggested 
provisions, different stakeholders pointed out that such facilitation was necessary not only at 
European  level  but  at  national  level  as  well.  Projects  of  Common  Interest  should  similarly 
enjoy the same political support in the Member States as national priorities.  

"One-stop-shop" 

The  idea  of  a  central  contact  and  coordination  body  for  the  permit  granting  procedures 
received  overwhelming  support  (79  %  of  respondents  supported  the  measure  while  only  2 
respondents  (~  2.5%)  opposed  it).  The  advantages  of  a  single  entry  point  for  permit 
applications were pointed out across all different stakeholders. This would limit the number of 
required permissions significantly and enable a coordinated publication of environmental and 

105 http://ec.europa.eu/energy/infrastructure/consultations/20110430_infrastructure_projects_en.htm 
106 http://ec.europa.eu/energy/infrastructure/consultations/20110430_infrastructure_projects_en.htm 

59

 
 
 
 
 
 
 
 
 
                                                 
other  information.  The  communication  with  the  public  would  become  smoother,  which  can 
benefit the acceptance of infrastructure projects among the population. 

It  was  pointed  out  that  projects  at  national level  should  clearly  remain  national  competence 
and  in  this  context  half  of  the  Member  States  opposed  a  standardisation  of  procedures  as 
different approaches already exist in a number of countries. EU-coordination for cross-border 
projects exclusively received support.  

Another  question  that  was  often  addressed  was  the  competence  of  the  proposed  "one-stop-
shops". Here the preferences were almost equally split between a pure coordination centre and 
a  body  with  significant  decision-making  power  with  industry  responses  slightly  favouring 
more  centralised  decision-making  power.  Many  proponents  made  clear  though  that  either 
measure should not create additional administrative structures.  

Time limits 

Time limits were supported by a majority of respondents, with 60 % being in favour and 10 % 
opposing  the  idea.  Particularly  NGOs  warned  of  the  risks  of  introducing  inappropriate  time 
limits.  Several supporters of time limits suggested maximum limits for each individual step 
of the application procedure or at least benchmarks to make the process more transparent.  

A central issue that was also raised were the consequences if a deadline was not met by the 
authorities.  Automatic  acceptances  could  decrease  public  acceptance  significantly,  while 
automatic  rejections  shift  the  consequences  back  to  the  project  developer.  Other  examples 
have a higher decision-making authority reviewing the files in case of a bureaucratic delay.  

Some  critics  state  that  simply  introducing  time  limits,  though  possibly  beneficial,  will  not 
erase  the  root  causes  of  slow  administrative  processing.  It  has  to  be  ensured  that  the 
authorities' staff capacities are sufficient to guarantee smooth permit granting process. 

Arguing  along  those  lines,  many  of  the  opposing  respondents  called  for  appropriate  time 
frames to guarantee  a  thorough  and  correct permit  granting  process  and  enough  time  for  an 
adequate consultation process. Some Member States saw general maximum time limits as an 
obstacle  when  dealing  with  more  complicated  projects  (e.g.  new  technologies).  A  diligent 
examination of the environmental impacts was also considered to be beneficial. 

Rewards and incentives  

Rewards  and  incentives  as  a  means  to  encourage  smoother  administrative  processes  faced 
more  opposition,  particularly  from  Member  States  and  NGOs.  In  contrast  most  industry 
responses expressed a positive attitude toward the measure. 

The reasons for opposition stemmed mainly from 3 reasons:  

−  Stakeholders  see  a  problem  in  defining  objective  criteria  to  assess  the  permitting 
agency's  work.  In  this  light  rewards  and  incentives  might  be  perceived  as  buying 
consent and be detrimental to public acceptance. 

−  The introduction of rewards and incentives cannot replace a diligent consultation and 
permit granting process and hence does not contribute to alleviating the root causes of 
administrative delays. 

−  Some responses queried the source of funding for this measure. 

60

 
 
 
 
 
 
 
 
 
 
 
 
Instead  of  financially  incentivising  smooth  processing  respondents  emphasized  that 
administrative capacities of the authorities involved should be strengthened and best practices 
and benchmarks should be encouraged. 

Additional issues 

The  already  existing  European  coordinators  for  cross-border  projects  were  mentioned 
positively.  In  this  context,  maintaining  the  possibility  to  resort  to  coordinators  as  political 
support for crucial cross-border connections was suggested by several stakeholders. 

A discrepancy was noted between the existing European environmental, urban planning and 
industrial  hazards  laws  and  the  objective  to  develop  a  European  energy  infrastructure. 
Therefore some Member States and individual industry responses called for a joint effort of 
the  different  Directorates-General  to  promote  and  facilitate  the  framework  for  energy 
infrastructure  development.  It  was  pointed  out  that  a  better  coordination  and  clear  priorities 
among the different objectives could shorten the permit granting process significantly. 

Question 2:   To increase the transparency and predictability of the permit granting process 
for  all  parties  involved,  guidelines  targeted  at  ministries,  local  and  regional 
authorities, project developers and affected citizens could be developed. 
Would you consider them useful? Which issues should they address? 

The introduction of guidelines to foster transparency and predictability was considered useful 
by  a  clear  majority  of  respondents,  especially  among  Member  States  and  stakeholders  from 
civil society. Several Member States stressed that the subsidiary principle has to be respected, 
particularly when communicating with the public. 

Many  respondents  emphasised  that  the  wider  economic  and  social  benefits  of  infrastructure 
projects need to be better communicated. The significance of transmission lines in general and 
each specific project has to be highlighted in order to increase public acceptance and achieve 
better  compromises.  Environmental  organisations  highlighted  that  the  purpose  of  the 
connection  (e.g.  integration  of  renewable  energy  sources)  should  be  communicated  to  the 
wider public. The specific benefits of a connection (e.g. decarbonisation, security of supply) 
could also have favourable or in other cases negative effects on the public opinion.  

The full and early provision of environmental and technical information was also considered 
an important measure to facilitate  public acceptance.  In this respect a minimum standard of 
communication – regarding the amount and the timing during the process – was suggested by 
several stakeholders. This approach enables earlier involvement of the different stakeholders 
in  the  process,  which  was  widely  favoured  by  respondents.  Reconciling  a  more  transparent 
process  (with  possibly  more  stakeholder  involvement)  with  the  need  to  speed  up  existing 
procedures was named as a major challenge for these measures. 

To  guarantee  more  transparency  regarding  network  development,  the  requirement  for  a 
national development plan or a network strategy was proposed. Plans similar to ENTSO-E's 
TYNDP would make further network expansions more predictable and comprehensible. The 
UK's National Policy Statements (NPS) set a clear strategy for further network development 

61

 
 
 
 
 
 
 
 
 
 
 
 
 
 
and also explain the evaluation process of applications in more detail. Laying open all steps of 
the process and the evaluation criteria can foster trust in the permit granting process and thus 
support in projects. 

Procedural reliability was valued as very important for all stakeholders. A clear prescription 
of responsibilities and tasks for each stakeholder at the different moments of the process was 
suggested  in  this  respect.  For  cross-border  projects  a  solid  method  for  cost-allocation  was 
called for, as well as a harmonisation of procedures to enable these projects further. 

Question 3:   The lack of public acceptance poses a major hindrance for the implementation 
of  energy  infrastructure  projects,  and  the  associated  achievement  of  energy 
and  climate  policy  objectives.  What  should  be  done,  apart  from  efforts  to 
increase  general  transparency,  to  improve  communication  with  citizens  at  an 
early  stage  of  the  project  and  to  ensure  that  the  environmental,  security  of 
supply,  social  and  economic  costs  and  benefits  of  a  project  are  correctly 
understood? Who should be responsible for /involved in this communication? 

Next  to  a  more  transparent  process  (covered  in  question  2)  respondents  addressed  3  main 
areas: 

information  policy  regarding  energy 

A  more  proactive 
infrastructure  development, 
particularly from the TSOs' side: A further explanation of their activities and the purpose of 
new projects  were deemed highly important. The different stakeholders agreed that creating 
awareness for the necessity of grid expansion is going to be a key factor. The projects have to 
be better linked to the wider benefits, a sustainable energy future – connecting grid expansion 
to  security  of  supply,  the  integration  of  the  internal  market  and  efforts  to  tackle  climate 
change. 

In  this  regard  respondents  were  in  favour  of  a  more  integrative  planning  procedure,  also 
encompassing  NGOs,  academia  and  other  stakeholders.  Some  environmental  NGOs  pointed 
out that in light of a coherent strategy they were willing to support grid extension measures 
and  their  promotion,  which  could  prove  crucial  for  public  acceptance.  Furthermore  it  was 
suggested  that  independent  research  institutes  could  play  a  role,  examining  the  actual 
environmental  and  health  risks  of  power  lines  and  informing  the  public.  Recognising  and 
addressing the population's concerns seriously was also named as a measure to foster trust and 
a higher acceptance in the long run. 

Respondents  were  very  clear  that  the  main  responsibility  of  communication  should  be  with 
the project developer but many stakeholders also advocated more direct political support for 
grid expansion to further stress the necessity of the measure. This was particularly mentioned 
for  the  European  level,  but  also  local  and  regional  support  for  individual  projects  was 
considered helpful and relevant. 

Question 4:  Requirements for compensation mechanisms: In your opinion, could minimum 
or harmonised requirements on compensation of affected populations, targeted 
at  individual  or  community  level,  help  to  increase  public  acceptance?  Which 

62

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
compensation schemes would you deem useful, and who should provide for the 
compensation? 

Compensation mechanisms were broadly seen as helpful or necessary, if fair and transparent. 
Industry  responses  stressed  that  the  additional  costs  connected  to  compensation  measures 
were to be included in higher tariffs and hence carried by the consumer. A question that arose 
is an acceptable method to calculate compensation for intangible negative effects (e.g. visual 
impediment). 

Respondents  believed  that  compensation  should  be  exclusively  a  national  decision  and 
opposed  any  standardization  due  to  diverging  circumstances  (e.g.  land  prices,  public 
involvement, specific projects) in the Member States. This rejection was the clearest among 
Member  States.  It  was  also  mentioned  several  times  that  compensation  measures  should 
remain  exceptions  and  thus  dealt  with  case  by  case  in  cooperation  with  local  authorities. 
Individual  industry  responses  on  the  other  hand  were  favourable  toward  some  form  of 
minimum standards and guidelines. 

Compensation  targeted  at  individuals  and  communities  were  seen  differently.  Individual 
compensation  measures  for  landowners  were  perceived  as  unavoidable  in  order  to  have  the 
right  to  use  one's  property.  If  community  compensation  proved  to  be  beneficial  to  public 
acceptance,  it  was  seen  as  a  fair  and  good  approach  to  reimburse  communities  for  negative 
impacts.  A  majority  of  respondents  preferred  a  case  by  case  approach  –  with  local  and 
regional  authorities  playing  a  major  role  in  agreements  –  and  were  opposed  to  any 
automatism. Concerns of not creating some sort of business were also expressed. 

The  issue  of  adequate  compensation  for  environmental  impact,  though  addressed  by 
environmental directives, was raised by several respondents. 

Question 5:   Have  you  encountered  any  national  best-practices  which  have  helped  to 
facilitate the permit granting process? Which measures were taken in view of 
administrative procedures, transparency and communication with citizens, and 
how has the public responded? 

A wide array of examples was named, pointing to approaches in different Member States that 
proved  to  be  successful  in  alleviating  challenges  in  the  administrative  procedures, 
transparency  and  communication.  These  examples  included  national  "one-stop-shop" 
approaches  as  well  as  a  transparent  central  planning  strategy.  They  underlined  beneficial 
results  of  introducing  time-limits  and  other  streamlining  measures  (e.g.  a  thorough  pre-
application  process).  Furthermore  they  also  pointed  to  successful  efforts  to  better 
communicate benefits to the public and better integrate their concerns via a transparent public 
debate.  Examples  showed  that  certain  measures  can  improve  public  acceptance  of 
infrastructure development. These best practices will be studied and taken into account.  

Not completely accounting for every measure mentioned, a few of the submitted examples are 
briefly presented in the following:  

- 

In the Netherlands the RCR ("Programma Rijkscoordinatieregeling") makes the Dutch 
Ministry  of  Economic  Affairs,  Agriculture  and  Innovation  the  central  coordination 

63

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
body  for  projects  of  national  interest.  Permits  are  still  granted  by  local  and  regional 
authorities but the ministry sets deadlines and publication dates. In certain cases, the 
ministry  can  grant  the  permit  on  behalf  of  the  local  or  regional  authorities.  Besides 
coordinating the permit granting process it takes the decision on the spatial planning. 
This  coordinated  process  allows  for  the  publication  of  all  information  at  the  same 
time,  enabling  transparency  and  providing  citizens  the  opportunity  to  engage  at  a 
central  point  of  the  process.  One-stop-shop  approaches  in  other  countries  were  also 
praised for facilitating the permit granting process (e.g. Greece, Ireland and Austria). 

-  The  National  Policy Statements (NPS) in the United Kingdom are  an  example  of  an 
overarching infrastructure development strategy setting out the Government’s energy 
policy.  It  explains  the  need  for  new  energy  infrastructure  and  contains  further 
instruction  on  how  to  assess  project  applications  and  the  impacts  of  energy 
infrastructure projects. The NPSs thus increase the transparency and predictability of 
the permit granting process by defining the main issues and objectives considered for 
granting  the  permit.  Setting  a  clear  and  long-term  oriented  energy  policy  is  also 
described as a facilitating measure in Slovakia. 

-  Organised public debates by a national commission gives the general public in France 
the opportunity to voice their opinion and influence major planning and construction 
projects in advance of any decision being taken. Although it prolongs the process up-
front  it  can  prove  beneficial  for  public  acceptance  and  help  to  avoid  subsequent 
appeals  and  other  hold-ups.  The  Swedish  experience  similarly  shows  that  spending 
more time and attention in the pre-application phase – consulting with all stakeholders 
concerned  by  the  project  and  making  all  documents  relevant  to  the  decision  process 
public – can speed up the overall process. 

- 

In  Portugal  a  cooperation  between  environmental  NGOs,  the  national  conservation 
agency  (ICNB)  and  power  line  construction  companies  agreed  to  include  rules  for 
mitigation  of  impacts  on  bird  populations  in  their  planning  and  construction 
guidelines. 

-  To change the fact that the broader population is often unaware of the TSOs activities 
and  goals,  the  Belgian  TSO,  ELIA,  launched  several  successful  media  campaigns. 
They inform the general public about its activities, policy goals and ongoing projects 
and explained the reasoning and benefits of further infrastructure development. 

64

 
 
 
 
 
 
 
ANNEX 4 
OUTCOME OF STAKEHOLDER CONSULTATION AMONG TRANSMISSION SYSTEM OPERATORS 

1.  ENTSO-E 

ENTSO-E  carried  out  a  survey  among  41  European  TSOs  in  34  countries.  Six  main  barriers  to 
investments are considered by TSOs: social acceptance, planning delays, few investment incentives (in 
particular  for  R&D  and  innovation),  and  the  lack  of  stable  return  on  investment  as  well  as  the 
uncertainty  about  future  regulatory  regime  change.  Cross-border  projects  require  a  reinforcement  of 
the national grids. Public funding should be targeted to address specific project/country risks and with 
a competitive approach to the label and support. 

More detailed responses were provided by: 

•  Amprion (Germany) 
•  Eirgrid (Ireland) 
•  Elia (Belgium) 
•  EMS (Serbia) 
•  50 hertz (Germany) 
•  HTSO (Greece) 
•  MAVIR (Hungary) 
•  REE (Spain) 
•  RTE (France) 
•  Statnett (Norway) 
•  Swissgrid (Switzerland) 
•  Terna (Italy) 
•  Transelectrica (Romania) 

Financing of infrastructure in the past 

For past investment mainly corporate financing was used and projects were implemented together with 
adjacent TSOs, investment expenditure being covered in the CAPEX of the TSOs concerned. Next to 
debt and equity financing, auction revenues from cross-border capacity allocation are used to fully or 
partially  finance  interconnectors  (only one  TSO  referred  to  this financing).  Upfront pre-construction 
investments are mainly financed by 100% equity. Debt capital can hardly be attracted for this type of 
investment. Among the main constraints to investment, TSOs raised the following issues: 
−  Time-lag in the remuneration of invested capital during the construction phase (pre-financing and 
start-up  losses,  of  particular  importance  when  projects  are  delayed  by  permitting  or  acceptance 
problems) 

−  Transmission fees do not cover all costs linked to the internal reinforcement of the grid linked to 

connection of new RES generation (shallow transmission fees, 1 TSO), 
−  Lack of incentives for technology innovation and R&D or other risks,  
−  Projects that  will face particular challenges relate to  offshore developments or  submarine cables 

and for some countries interconnector investments. 

Recommendations for future financing and EU support 

In  the  light  of  the  new  and  urgent  investment  challenges,  TSOs  will  need  to  attract  equity  and  debt 
financing and new investors. Asked about the added value of EU support, TSOs recommend financial 
support  to  the  construction  phase.  Some  TSOs  note  that  the  most  effective  measure  is  to  ensure 
sufficient rate of returns for all projects and rate of return markups for projects of major importance 
and to align the RORs to the risks faced by project owners. 

65

 
 
 
 
 
 
 
 
 
 
2.  ENTSO-G 

The consultation of TSOs among ENTSO-G included detailed responses by: 

•  GAZ SYSTEM 
•  Gasunie 
•  National Grid 
•  Thyssengas 
•  GEOPLIN PLINOVODI 
•  RAG 
•  DESFA 
•  ENGAS 
•  GRTgaz 
•  OMV 
•  Wingas 
•  Fluxys 
•  FGSZ 
•  NET4GAS 

Financing of infrastructure in the past 

Past investments were financed on the basis of corporate financing within the structure of the parent 
company  on  the  basis  of  equity  and  shareholder  loans  complemented  by  EU  direct  grants  and  EIB 
loans. Depending on the degree of ownership unbundling and international expansion, the experience 
with  credit  ratings,  corporate  bonds,  project  financing  and  direct  exposure  to  capital  markets  differs 
widely.  Project  financing  was  mainly  used  for  new  LNG  terminals  and  new  interconnectors  in 
Western Europe.  Project bonds and project financing via special project vehicles are being examined 
for future investment by TSOs outside of the national network. The attractiveness of these bonds will 
largely depend on the costs.  

Recommendations for future financing and EU support 

ENTSOG Members underlined that new gas projects aiming to increase diversification, competition, 
market integration and security of supply, thus removing market Imperfections, will not come forward 
by  relying  on  market  (shippers)  commitments  alone.  While  volume  risk  is  covered  in  regulated  gas 
networks, fluctuating utilization, the short-term tariff setting and capacity allocation do not fit to the 
long-tem investment cycles. 

Future  EU  support  should  minimize  investment  lead  times  and  construction  risks,  reduce  the 
administrative  burden  on  project  promoters,  offer  coordinated  political  support  to  decrease  country 
risks in geopolitically difficult regions, enhance cross-border cooperation and the coordination of open 
seasons. The EU should support should be targeted to the entire investment cycle including feasibility 
and routing studies, environmental impact assessments (EIA), land and building permit design as well 
as the construction of projects.  

Cost  allocation  should  be  enhanced  by  multilateral  negotiations  of  investment  projects  at  regional 
level between operators and regulators with strategic guidance by ACER and ENTSOG. In practical 
terms, TSOs in the respective Member States could book the capacities needed for security of supply 
and  include  these  costs  in  their  respective  transmission  tariffs.  Other  options  include  settlements 
through direct cash transfers between TSOs or through netting system using EU funds granted to the 
Member States concerned. 

While ENTSOG members unanimously call for instruments to make projects bankable along the long 
term  investment  cycle,  they  consider  various  instruments  depending  on  the  particular  needs  of  the 
TSOs.  These  range  from  credit  enhancement,  to  public/private  guarantees  (for  example  through  the 

66

 
 
 
 
 
 
 
 
EIB), European public private investment funds, harmonized investment conditions and performance-
related incentives as well as direct EU grants and a dedicated EU fund for infrastructure.  

3.  Gas Infrastructure Europe (GIE) 

Investment  in  regulated  and  non-regulated  infrastructure  in  the  gas  sector  requires  a  long-term 
commitment either by regulators or users. Given the regulatory and market trends towards short-term 
capacity,  GIE  underlines  that  tariffs  and  investment  regulation  should  give  long-term  signals  for 
investment.  New  financing  instruments  should  be  beneficial  to  all  projects.  Costs  of  stranded  assets 
remain with consumer in the case of regulated networks. Risk profiles change as gas TSOs are about 
to unbundle or restructure the ownership. Gas TSOs will need to invest in IT and human resources to 
handle the growing capacity and congestion management with short- and long-term products.  
Among the measures suggested by GIE are the following: 
−  Cost-allocation  mechanism  is  mentioned  in  cases,  where  the  lack  of  user  commitment  could  be 

substituted by cross-border compensation. 

−  Adequate risk/reward ratios and tariff to ensure long-term signal and not only short-term low rates 

− 

of return 
Incentives  for  operators  –  performance-related  rewards  for 
implementation  of  network 
development  measures,  independent  of  and  on  top  of  the  allowed  revenues,  including  shortened 
amortization period in order to limit risks.  GIE sees higher risks for cross-border projects due to 
inconsistent regulatory frameworks on two sides of the border and higher complexity. 

67

 
 
 
 
ANNEX 5 
ENERGY INFRASTRUCTURES PRIORITIES 

The priorities for the period up to 2020 are the following: 

a)  In electricity: 

•  Developing  an  offshore  grid  in  the  North  Sea,  the  Irish  Sea,  the  English  Channel  and  the 
Baltic Sea and reinforcing and building new onshore North-South interconnections in Central 
Europe; 

•  Developing interconnections in South-Western Europe; 
•  Strengthening the electricity networks in Central Eastern Europe and South Eastern Europe in 

North-South and East-West electricity flow directions; 

•  Developing  interconnections  between  the  Baltic  Member  States  and  their  Union  neighbours 

and reinforcing internal grid infrastructures accordingly; 
Implementing the deployment of smart grid technologies across the Union; 

• 

b)  In gas: 

•  Developing the transmission of gas in the Southern gas corridor; 
•  Developing  interconnections  between  the  Baltic  Member  States  and  their  Union  neighbours 
and  by  developing  interconnections  in  Central  Eastern  and  South  Eastern  Europe  in  North-
South direction; 
Increasing interconnection capacities for North-South gas flows in Western Europe; 

• 

c)  In oil: 

•  Reinforcing the interoperability of the oil pipeline network in Central Eastern Europe. 

The  two  longer-term  priorities  are  the  development  of  electricity  highways  and  CO2  transport 
networks. 

68

 
 
 
 
 
 
 
 
 
ANNEX 6 
TYPICAL PROJECT DEVELOPMENT PROCESS FOR AN ENERGY INFRASTRUCTURE PROJECT 
AND EXAMPLES OF PROJECTS HAVING FACED PERMIT GRANTING DELAYS 

Figure 1: Typical project development process 

Table 7: Projects having faced permit granting problems 

Member State 

Project 

Austria 

Steiermarkleitung, 380 
kV electricity line 

Duration of the 
permitting procedure
1982-2007* 

Salzburgleitung, part 
St- Peter – Salzburg, 
380 kV electricity line 

1995-2010* 

Estonia – Finland 

Ulvila, Kangasala, 400 
kV electricity line 

2003-2008 

Estlink  

2001-2006 

Problems 
encountered 
Lengthy 
administrative 
procedures, public 
opposition 

Introduction of EIA 
requirement 
throughout the 
procedure, delays in 
administrative and 
litigation procedures 
Public opposition and 
lengthy litigation 
procedures 
n/a 

69

 
 
 
 
 
 
 
 
 
 
Member State 

Project 

France 

France-Spain 

Germany 

Nantere – Nourottes, 
225 kV electricity line 

France – Lyon – 
Chambery connection, 
400 kV electricity line 
French-Spanish 
interconnector, 380 
kV electricity line 

Interconnector 
Halle/Saale-
Schweinfurt, 380 kV 
electricity line 

Windcollectionline 
Mecklenburg 
Vorpommern – 
Schleswig Holstein, 
380 kV electricity line 

Duration of the 
permitting procedure
2001-2009 

1999-2006 

1970s-2014* 
(expected, including 
construction) 

2006-2013 (expected) 

Problems 
encountered 
Lengthy 
administrative 
procedures 

Lengthy 
administrative 
procedures 
Lengthy 
administrative 
procedures for some 
parts of the project, 
strong public 
opposition 

Public opposition, 
lengthy administrative 
procedures, 
environmental 
requirements 

2005-2013 (expected)  Lengthy 

administrative 
proceedings with 
differences across 
federal state borders – 
one part of the project 
is constructed, the 
other part waiting for 
permission 
Delays due to cross-
border issues in 
planning procedures 
(cross-border point not 
fixed in NL – 
necessary to start the 
procedure in DE) 

administrative 
procedures, 
environmental 
requirements, lack of 
resources 
Land acquisition 
issues, including 
administrative 
formalities 

due to environmental 
requirements 
Public opposition due 
to environmental 
concerns 

Germany/ Netherlands  Niederrhein – 

Doetinchem, 380 kV 
electricity line 

2009-2014+ 
(expected, including 
construction) 

Greece 

High pressure gas 
pipeline to Aliveri 

2006-2011 (expected)  Lengthy 

Hungary/Romania 

Hungarian-Romanian 
400 kV electricity line 

2003-2009 

Hungary/Slovenia 

Hungarian-Slovenian 
400kV electricity line 

2000-2012 (expected)  Lengthy procedures 

Italy 

Sorgente-Rizziconi, 
380 kV electricity line 

2004-2009 

70

 
 
Member State 

Project 

Turbigo-Rho, 380 kV 
electricity line 

Duration of the 
permitting procedure
1994-2004 

Spain 

Sweden 

UK 

Martorell-Figueras 
high pressure gas 
pipeline 

2006-2011 

Stenkullen Lindome 
400kV electricity line 

2004-2010 

Beauly-Denny, 400kV 
electricity line 

2005-2010 

Second Yorkshire 
Line Project, 400 kV 
electricity line 

1991-1998 

Problems 
encountered 
Conflicts with regard 
to routing through 
densely populated and 
environmental 
protection areas 

Lengthy procedures, 
particular complexity 
of the projects needing 
consents from several 
regions 
Lengthy 
administrative 
procedures and high 
number of authorities 
involved 

Public opposition, 
environmental 
requirements 

Lengthy 
administrative 
procedures, public 
opposition 

*including planning and pre-application efforts. For all projects where these efforts are not included, an average 
of 2 years for pre-application has to be added. 

71

 
 
 
ANNEX 7 
KEY DATA ON PERMIT GRANTING PROCEDURES IN SELECTED MEMBER STATES 

Country 

AT 

BE 

BG 

CZ 

DE 

DK  

EE 

EL 

ES 

FI 

FR 

HU 

Duration and delays 
time limits for statutory process 
real average duration 

Y 
3 years* 

N
4 years

Authorities and permits 
number of permits 
responsible authorities 

Fast-track procedure existing 

>1 
>1 

Y 

5
na

N

na
na

na
na

na

Y
4 years

partly
8 years

N
10 years

3
na

N

1
>2

Y

2-3
2-3

N

na
na

na
na

na

Y 
5 years

partially
3* years

N
6 years

N 
5.5 years* 

Y 
2 years* 

1
1

Y

>3
>10

Y

3
8-10

N

3 
1-2 

N 

3 
3-10 

N 

Country 

IE 

IT 

LT 

LV 

NL 

PL 

PT 

RO 

SE 

SK 

Sl 

UK 

Duration and delays 
time limits for statutory process 

Y  

Y

N

partially

real average duration 

4 years  5 years

4 years*

3 years*

partially
1.5 
years*

partially

4 years*

partially
1.5 
years*

N
3.5 
years

N

N

N 

Y 

9.5 years

4 years*

7.5 years 

4 years 

Authorities and permits 
number of permits 
responsible authorities 

Fast-track procedure existing 

1  
1 

Y 

1
1

Y

3
several

N

3
>5

N

1
1

Y

>3
>3 

Y

2
>1

N

>4
25

Y

2
>2

N

4
>2

N

4 
4 

N 

1 
1 

Y 

*pre-application efforts to be added (average 2 years) 

SUMMARY:  

Time limits  (partially or entire procedure) 
1 responsible authority at national level 
Fast track schemes 

13 MS 
5 MS 
10 MS 

Sources: Consultation of TSOs, Roland Berger study on permitting, individual interviews 

72

 
 
  
  
 
 
 
 
 
 
 
 
 
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
  
 
 
 
 
 
 
 
 
 
  
  
 
  
  
 
 
 
 
 
 
 
 
 
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
 
 
 
 
 
 
 
 
 
  
  
  
  
 
 
 
 
 
 
 
 
 
  
  
ANNEX 8 
MAIN REASONS FOR PUBLIC OPPOSITION TO ENERGY INFRASTRUCTURE PROJECTS 

•  Unclarity about the added value of a project: The public generally questions the necessity of a 
project.  Usually,  it  is  up  to  the  promoter  to  communicate  the  benefits  and  costs  of  a  project, 
without  support  from  authorities.  The  efforts  needed  to  communicate  and  convince  the  public 
about the necessity and the benefits of a project can lead to major delays of up to one year. 

• 

Impacts on the environment and landscape, health and safety concerns: Public opposition is 
particularly  strong  for  electricity  overhead  lines,  because  of  the  (at  times  perceived)  impact  of 
power lines on the environment, and landscape (the notion of the "Not in my Backyard" (NIMBY) 
phenomenon has in the past been frequently quoted, where citizens agree to the general objective 
of  a  project  but  refuse  its  construction  in  their  vicinity),  as  well  as  safety  and  health  concerns, 
especially  with  regard  to  electro-magnetic  fields.  Additional  resistance  arises  as  cross-border 
projects are perceived as mere "transit lines" without local benefits. Gas installations are usually 
less affected by public resistance, but difficulties have occurred with some LNG and storage sites 
and gas pipelines. 

•  Late and insufficient involvement of the public and stakeholders: An effective dialogue with 
the  public,  i.e.  landowners/citizens  and  stakeholder  organisations,  is  essential  to  gain  public 
acceptance.  However,  in  many  cases,  the  public  is  not  consulted  at  the  very  beginning  of  the 
project and is hence not adequately involved in the decision-making process. The perception to be 
confronted with precooked decisions has in many cases provoked substantial opposition. Further, 
due to the complexity of the process it is often unclear for citizens at what stage and how they can 
intervene, particularly when public consultations are carried out repeatedly on the same issue but 
within different procedures. 

73

 
 
 
 
 
S
o
u
r
c
e
:
E
N
T
S
O
-
E

,
2
0
1
1

Austria

Belgium

Bosnia and Herzegovina

Bulgaria

Croatia

Czech Republic

O
t
h
e
r

l

r
e
g
u
a
t
o
r
y

c
h
a
r
g
e
s

L
o
s
s
e
s

S
y
s
t
e
m
S
e
r
v
i
c
e
s

I

n
f
r
a
s
t
r
u
c
t
u
r
e

Denmark

Estonia

Finland

France

Germany

Great Britain

Greece

Hungary

Ireland

Italy

Latvia

Lithuania

Luxembourg

FYROM

Netherlands

Northern Ireland

Norway

Poland

Portugal

Romania

Serbia

Slovak Rep

Slovenia

Spain

Sweden

Switzerland

7
4

0

5

1
0

1
5

2
0

2
5

3
0

   F
i
g
u
r
e

3
:

I
n
f
r
a
s
t
r
u
c
t
u
r
e

c
o
m
p
o
n
e
n
t
s

o
f

e
l
e
c
t
r
i
c
i
t
y

t
r
a
n
s
m

i
s
s
i
o
n
t
a
r
i
f
f
s

(
i

n

/

M
W
h
)

S
o
u
r
c
e
:
E
N
T
S
O
-
E

,
2
0
1
1

(
T
h
o
s
e

c
o
u
n
t
r
i
e
s
,

f
o
r

w
h
i
c
h

c
e
r
t
a
i
n

e
l
e
m
e
n
t
s
o
f

t
h
e
2
0
1
0

t
r
a
n
s
m
i
s
s
i
o
n

t
a
r
i
f
f
s

a
r
e

e
s
t
i

m
a
t
e
s

a
r
e
m
a
r
k
e
d

i
n

r
e
d
.
)

0

5

1
0

1
5

2
0

2
5

Austria

Belgium

Bosnia and Herz.

Bosnia and …

Bulgaria

Croatia

Czech Republic

Denmark
Denmark

Estonia

Finland

France
France

Germany

Great Britain

Greece
Grecce

Hungary

Ireland

Italy
Italy

Latvia

Lithuania

Luxembourg

FYROM

Netherlands

4
0
0
-
3
8
0
k
V

2
2
0
-
1
5
0
k
V

1
3
2
-
5
0
k
V

Northern Ireland

Norway
Norway

Poland

Portugal

Romania
Romania

Serbia

Slovak Rep

Slovenia

Spain
Spain

Sweden
Sweden

Switzerland

F
i
g
u
r
e

2
:

E
l
e
c
t
r
i
c
i
t
y

t
r
a
n
s
m

i
s
s
i
o
n
t
a
r
i
f
f
s

–

s
u
m
o
f

g
e
n
e
r
a
t
i
o
n
a
n
d

l
o
a
d
f
e
e
s

(
i

n

/

M
W
h
)

N
A
T
I
O
N
A
L
E
L
E
C
T
R
I
C
I
T
Y
A
N
D
G
A
S
M
A
R
K
E
T
S
T
A
T
I
S
T
I
C
S

A
N
N
E
X
9

 
 
 
 
 
 
 
 
 
 
  
 
 
 
 
 
 
 
 
 
 
 
 
 
€
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
€
 
 
 
 
 
 
 
 
 
Figure 4: Electricity prices for household customers, 2nd semester 2010 / 2010s2 (in €/kWh) 

0,300

0,250

0,200

0,150

0,100

0,050

0,000

BA BG EE

LV RO HR EL

LT

FR

FI

TR PL

CZ

SI

UK HU SK

PT

NL MT EU-
27

LU EA

ES

IE

NO IT

AT

SE

BE CY DE DK

Source: Eurostat (data for Italy provisional). EA designates the euro area. 

Without taxes Other taxes VAT

Figure 5: Electricity prices for household customers, 2010s2 (in PPP/kWh) 

0,300

0,250

0,200

0,150

0,100

0,050

0,000

FR

FI

EL

NO UK LU EE NL

SE

IE

LV

EU-
27

HR BE

SI

AT BG IT

DK CZ

LT

ES

PT RO TR CY

PL MT DE SK HU

Source: Eurostat (not available for Bosnia and Herzegovina) 

75

 
 
 
 
 
 
 
Figure 6: Percentage change in electricity prices for household consumers, 2010s2-2009s2 

35%

30%

25%

20%

15%

10%

5%

0%

-5%

-10%

L
N

T
U I
L

Z
C

U
H

K
U

R
H

E
V I
L

T
A

G
B

L
P

T
P

A
E

K
S

7
2
-

U
E

R
T

E
B

K
D

I

E F
D

I

S

E
S

R
F

O
R

E
E

S
E

T
M

O
N

L
E

Y
C

T
L

Source: Eurostat 

Figure 7: Share of network costs in electricity price for household consumers, without taxes, 
2010s2 (in %) 

100%

80%

60%

40%

20%

0%

RO CZ NO EE LT DK LU BE

SI AT LV SK SE PL ES

FI

PT HU HR DE NL

IT

BG EL UK CY TR MT

Energy and supply Network cost

Source: Eurostat 2011 (data for Italy provisional, no disaggregated price data for Ireland, France and Bosnia 
and Herzegovina) 

76

 
 
 
 
 
 
 
Figure 8: Electricity prices for households in Europe (December 2010) 

Source: DG Energy, Market Observatory, 2011 

77

 
 
 
 
Figure 9: Electricity prices for industrial consumers in Europe (December 2010) 

Source: DG Energy, Market Observatory, 2011 

78

 
 
 
Figure 10: Natural gas prices for household consumers, 2010s2 (€/GJ)  

35

30

25

20

15

10

5

0

RO TR HR

EE

LV

UK

BG SK

BA

LT

LU

PL

CZ

IE

ES HU

DE EU-
27

FR AT

BE

PT

EA

SI

NL

IT

DK

SE

Source: Eurostat (data for Italy provisional) 

Without taxes Other taxes VAT

Figure 11: Gas average quarterly wholesale prices (Q4 2010) 

Source: DG Energy, Market Observatory, 2011 

79

 
 
 
 
 
 
 
ANNEX 10 
ELEMENTS OF NATIONAL REGULATORY FRAMEWORKS FOR ELECTRICITY AND GAS 
INFRASTRUCTURE 

Table 8: Remuneration of electricity infrastructure investments in selected Member States 

Country 

Type of remuneration 

Calculation 

Austria 

WACC  

pre-tax nominal 

WACC  

pre-tax nominal 

Czech 
Republic  
Germany 

RoE (pre 2006) 
RoE (post 2006) 
WACC 
Greece 
WACC 
Spain 
WACC (electricity)  
Finland 
WACC (electricity) 
France 
RoE 
Hungary 
WACC 
Ireland 
Italy  
WACC (electricity) 
Lithuania  WACC (electricity) 
Netherlands  WACC (electricity) 

WACC (electricity) 
WACC 

Portugal 
Great 
Britain  
Source: Roland Berger, 2011 

WACC: Weighted Average Cost of Capital 
RoE: Return on Equity 

pre-tax real 
pre-tax nominal 
pre-tax  
post-tax  
pre-tax, status 2006 
pre-tax 

pre-tax 
pre-tax 
Pre-tax nominal 
Pre-tax nominal 
Pre-tax real 

post tax cost of equity 

Rate 

6.32% 

7.65% 

9.29% 
7.56% 
8% 
7.6% 
6.5% 
7.25% 
4.5% 
5.95% 
6.9% 
5% 
6.9%-8.4% 
5.3%-6.7% 
7.8% 
5.05% 

Table 9: Overview on investment related aspects of the national regulatory frameworks for gas 

Country 

Type  

Length  of 
regulatory 
period 

TOTEX 
approach 

Investment 
allowances 

CAPEX 
time  shift 
gap 

RAB 
based on 
replac-
ement 
cost 

RAB 
based  on 
historic 
costs 

RAB 
based  on 
indexed 
historic 
costs 

Austria 

Belgium 
Bulgaria 

Czech 
Republic 
Denmark 

Estonia 
Finland 
France 
Germany 

Rate-of-
Return 
Revenue cap 
Rate-of-
Return 

4 years 

Revenue cap 

5 years 

Rate-of-
Return 
Price cap 
Revenue cap 
Revenue cap 
Revenue cap 

4 years 
5 years 
5  years  (as 
of 2013) 

x 

x 

x 

x 

x 

x 

x 

x 

x 

x 
x 
depending 
of 

the  

x 
x 

x 
x 

80

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Country 

Type  

Length  of 
regulatory 
period 

TOTEX 
approach 

Investment 
allowances 

Great Britain 
Greece 
Hungary 
Ireland 
Italy 
Lithuania 

Revenue cap 
Revenue cap 
Revenue cap 
Revenue cap 
Revenue cap 
Price cap 

5 years 

4 years 
4 years 
5 years 
5 years 

Luxemburg 

Netherlands 

Portugal 

Rate-of-
Return 
Price  cap 
yardstick  
Rate-of-
return 

/ 

4 years 

x 

x 

Romania 
Slovakia 

Revenue cap 
Price cap 

5 years 
3 years 

Slovenia 

Price cap 

Spain 

Price cap 

Source: KEMA study 2009. 

1  year  (3 
years in the 
future) 
4 years 

CAPEX 
time  shift 
gap 

RAB 
based on 
replac-
ement 
cost 

RAB 
based  on 
historic 
costs 

RAB 
based  on 
indexed 
historic 
costs 
year 
purchase 
x 
x 

of 

x 

x 

x 

x 

x 
X 
financial 
accounts 

– 

x 
standard 
cost 

x 
on 

price 

based 

Tariffs 
benchmarking 
x 

x 

x 

x 

x 

x 

Table 10: Remuneration of gas infrastructure investments in selected Member States 

Country 

Type of remuneration 

Calculation 

Percentage 

Austria 

WACC 

Belgium 
Czech 
Republic 
Germany 

Finland 

France 
Greece 

WACC 
WACC  

RoE (pre 2006) 
RoE (post 2006) 
WACC  

WACC  
WACC 

Great Britain  WACC  
WACC 
Hungary 
WACC 
Ireland 
WACC  
Italy 
Lithuania 
WACC  
Luxemburg  WACC 
Netherlands  WACC  
WACC  
Portugal 
WACC 
Romania 
WACC  
Slovenia 
WACC 
Spain 
Source: KEMA study 2009 

post-tax  
(pre-tax  
pre-tax real 
(pre-tax nominal) 
post-tax nominal 
pre-tax real 
pre-tax nominal 
pre-tax nominal  
status 2006 
pre-tax real 
(pre-tax nominal) 
pre-tax real 
pre-tax real 
pre-tax real 
pre-tax real 
pre-tax real 
pre-tax real 
pre-tax nominal 
pre-tax real 
pre-tax real 
pre-tax real 
pre-tax real 
post-tax nominal 

81

6.97% 
(8.3%) 
6.21% 
(8.289%) 
6.13% 
9.29% 
7.56% 
9-10% 

7.25% 
(10.06%) 
6.56% 
6.25% 
6.9% 
5.2% 
6.7% 
6.87% 
8.5% 
5.5% 
8.0% 
7.88% 
5.87% 
5.48-5.68% 

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
ANNEX 11 
PROJECT CASE STUDIES CONCERNING REGULATORY AND FINANCING ISSUES 

1.  ELECTRICITY 

1.1.  Offshore grid 

The development of an offshore grid in the Northern Seas poses specific challenges by combining the 
connection of offshore wind (or other) energy sources and cross-border interconnection for electricity 
trade107.  The  benefits  of  such  a  grid  can  be  measured  e.g.  according  to  installed  wind  generation 
capacity  in  each  country  or  electricity  flows  to  coastal  countries,  with  both  methodologies  yielding 
very  different  results  in  terms  of  cost  allocation.  Existing  national  regulatory  frameworks  do  not 
provide adequate rules for such allocation and realising synergies by combining connection projects or 
connection  and  interconnection  projects.  Nor  do  they  regulate  appropriately  onshore  connection, 
prioritisation between electricity in-feed and trade flows or the offshore grid’s added value in ensuring 
onshore system security and ancillary services. 

• 
According  to  the  OffshoreGrid  study,  a  total  of  about  320  offshore  wind  projects  are 
forecasted to be online by 2030, totalling about 150 GW in Northern Europe. Based on its analysis of 
optimal  connection  solutions  for  offshore  wind  farms  depending  on  their  distance  to  shore, 
concentration and size, the OffshoreGrid study concludes that more than one third or almost 55 GW 
should  be  connected  via  hubs  rather  than  radially  as  is  the  case  today  (cf.  Figure  12),  mostly  in  the 
North  Sea  and,  to  a  lesser  extent,  the  Baltic  Sea108.  Moreover,  opportunities  for  T-connections  of 
offshore wind parks to interconnectors have been identified for the following development areas: 

−  North  and  Irish  Seas:  BorWin,  HelWin  and  SylWin  (DE);  Idunn  and  Sorlige  Nordsjoen  (NO); 

Irish Sea R9, Firth of Forth and Dogger Bank (UK) for a total of about 30 GW; 

−  Baltic  Sea:  Baltic  1  (DE);  Kriegers  Flak  (DE,  DK  and  SE);  Blekinge  Taggen  and  Södra 

Midsjöbanken (SE); several wind farms in Polish waters for a total of about 6 GW. 

Figure 12: Projects connected radially and via hubs in 2030 (Source: OffshoreGrid study) 

Projects with radial connections 

Projects in hubs

70 

60 

50 

40 

30 

20 

10 

0

j

s
t
c
e
o
r
p
o
r
e
b
m
u
N

0 20  40 60  80  100 120 140 160 180 200 220 240 260 280  300  320 Mor
e 

Project distance to connection point (km)

107  
108  

See Annex 4 of SEC(2010) 1395 for a more detailed description. 
While  Germany  would  host  by  far  the  biggest  number  of  these  hubs  (about  60),  Member  States  benefiting  from 
such a solution could include Belgium, Denmark, Finland, Netherlands, Poland, Sweden and the United Kingdom. 

82

 
 
 
 
 
 
 
                                                 
 
 
Already for the period up to 2020, the study has identified about 30 offshore wind projects in Germany 
and the Netherlands, but also Finland – totalling about 9 GW –, for which a hub connection would be 
the  optimal  socio-economic  solution.  These  numbers  can  be  compared  with  those  of  national 
regulators  of  the  North  Seas  Countries  Offshore  Grid  Initiative  who  foresee  installed  offshore  wind 
generation capacity to increase from about 4 GW to 40 GW by 2020, of which about 22GW should be 
further out to sea. As regards offshore interconnectors – most of which are or would be regulated –, 
new  projects  to  be  implemented  by  2020  total  15  GW,  compared  to  current  total  interconnection 
capacities of about 7 GW in the region109. 

As  stated  by  the  NSCOGI  working  group  on  regulatory  and  market  aspects:  "Typically,  at  present, 
new interconnectors or shared lines are developed on a 50:50 shared cost basis between the connected 
TSOs. While this traditional approach works at present while lines are between two countries, it may 
be more challenging to develop appropriate and fair cost allocation rules when lines begin to connect 
more than two countries or are connected to offshore generation. This issue is not specific to offshore 
grid  development,  but  will  arise  more  generally  as  more  cross-border  infrastructure  is  built  on  land 
across Europe." 

The  Kriegers  Flak  project  is  an  excellent  example  of  the  concrete  difficulties  encountered  when 
trying to develop offshore transmission infrastructure in an integrated manner. It initially envisioned 
the  development  of  three  wind  farms  within  German,  Swedish  and  Danish  waters,  linked  by  a 
combined offshore grid connection, which would also serve as an interconnection between the three 
countries. The three-country solution has in the meantime been abandoned with Sweden's withdrawal, 
and the development of the project has been delayed because of regulatory challenges, despite EUR 
150 million of EU funding received in the context of the European Energy Program for Recovery. 

Three different TSOs were involved (Vattenfall, Energinet.dk and Svenska Kraftnätt), as well as two 
market  systems  and  two  synchronous  zones,  posing a  huge  challenge  regarding  regulation on  cross-
border  infrastructure.  The  feasibility  study,  published  in  a  joint  report  of  the  three  TSOs,  concluded 
that  the  combined  solution  would  generate  positive  net  benefits  compared  to  the  separate  solution 
(reduced price differentials between  markets, spot market development, security of supply), but also 
imply higher upfront costs (EUR 1.36 bn compared to EUR 1.29 bn for a smaller solution) and more 
risks  and  require  close  coordination  between  the  transmission  companies  in  the  area.  The  current 
regulatory  framework  does  not  incentivise  this,  as  it  is  mainly  national  in  scope  and  targeting  the 
improvement  of  internal  services  and  cost  savings  instead  of  promoting  a  regional  approach. 
Additionally,  there  are  other  regulations  that  might  also  distort  the  incentives  to  cooperate,  such  as 
different rules for renewables connection, balancing or renewables support in the three countries110. 

1.2.  Lithuania-Poland interconnection (LitPol link) 

The planned 150 km DC interconnection between Lithuania and Poland aims at connecting the Baltic 
States  to  the  EU  continental  system  with  a  capacity  of  2x500  MW.  Total  investment  costs  are 
estimated at EUR 237 m. 100 km of this DC line will run through Polish territory while 50 km will be 
on Lithuanian territory. The participating TSOs have set up a special purpose vehicle, LitPol Link. 

The interconnection will considerably enhance the security of supply of the Baltic States and end the 
isolation  of  the  entire  region.  The  link  is  essential  for  the  integration  of  the  Baltic  States  to  the  EU 
electricity market. 

Major  obstacles  for  the  LitPol  link  are  related  to  the  difficult  discussions  with  land  owners  on  the 
Polish side, where on average 50 to 80 owners are involved per km on average, and to the potential 
environmental impacts of an overhead line. The business case of the project is also closely linked to 
the Polish participation in the NPP project in Lithuania. 

109  
110  

NSCOGI Working group 2, "Report to the Steering Committee", June 2011. 
Meeus et al., 2010 

83

 
 
 
 
 
 
 
 
 
                                                 
1.3.  Smart grids 

For the deployment of smart grid technologies, distribution system operators could in many Member 
States bear the major part of costs for a the corresponding investments, while not necessarily being the 
only or even main beneficiaries. Smart metering has developed most in those Member States, where 
the  benefits  arising  from  two-way  communication  are  clear  and  go  directly  to  the  party  bearing  the 
investment  cost111.  The  deployment  of  smart  networks  on  a  larger  scale  however  has  proven  to  be 
difficult,  as  the  benefits  they  provide  are  spread  among  multiple  actors  of  the  system.  According  to 
analysis  of  demand  response  schemes  in  the  United  States,  about  80%  of  the  value  created  by  such 
schemes go the savings in generation capacity costs, 10% to savings in energy costs and 10% to the 
reduction of transmission and distribution costs (through e.g. the delayed need for new investments)112. 
This  translates  cost-benefit  asymmetries  among  the  actors  concerned  by  smart  grid  developments. 
Eurelectric  estimates  that  distribution  system  operators  who  will  pay  for  the  vast  majority  of 
investments  needed,  might  only  reap  around  60%  of  the  benefits.  As  long  as  no  cost  allocation 
solution can be found, which includes other beneficiaries such as final consumers or generators, rapid 
deployment of smart grids will be seriously impaired. 

2.  GAS 

2.1.  MidCat Pipeline – North-South Gas corridor in Western Europe 

MidCat  is  a  800  km  natural  gas  interconnector  linking  the  French  and  Spanish  gas  markets  from 
Barbaira (France) to Catalonia (Spain) including bi-directional flow (ES-FR 7.2 bcm/y and FR-ES 5.6 
bcm/y).  MidCat  promoters  TIGF  (France)  and  Enagas  (Spain)  decided  to  build  a  fully  regulated 
interconnector  on  a  corporate  financing  basis  involving  a  total  investment  volume  of  1,550  million 
Euros. The connection consists of a 600 km pipeline in France and 200 km in Spain which results in 
an investment volume for TIGF of 1,300 million Euros and 250 million Euros for Enagas. 

The  project  development  and  investment  decision  were  conditioned  by  two  main  factors:  the  open 
season  process  and  the  agreement  between  the  Spanish  and  French  regulator  on  the  cost/benefit 
allocation. The economic test via an open season procedure caused delays in the process as well as the 
lengthy regulatory negotiations. The France-Spain 2015 open season, involving four operators from 2 
countries  on  6  interconnection  points,  showed  a  lack  of  interest  by  shippers  to  commit  to  long-term 
capacity.  The  cost  allocation  process  faced  a  number  of  difficulties  linked  to  the  cost  allocation, 
including differences in the accreditation, recovery and valuation of costs and the tariff setting. 

The  open  season  failed  to  reflect  the  wider  socio-economic  benefits  of  the  MidCat  pipeline  for  the 
development of the North-South Gas Corridor in Western Europe. The benefits of market integration, 
increased competition in Southern France, the optimised use of developed Iberian LNG infrastructure 
and pipelines from North-Africa as well as greater security of supply for the continent were not taken 
into account by the market participants. 

MidCat  was  also  supported  by  co-financing  totalling  175  765  000  million  Euros  from  the  European 
Energy Programme for Recovery. 

2.2.  Slovakia-Hungary Interconnector – North South Gas Corridor in Eastern Europe 

The  115  km  natural  gas  interconnector  between  Slovakia  and  Hungary  is  to  connect  Velké  Zlievce 
(Slovakia) and Vecsés (Hungary) with an annual capacity of 5 bcm/y. The project promoters Eustream 
and FGSZ decided for a fully regulated interconnector with a total investment volume of 192 million 

111  
112  

Italy's ENEL Distribuzione successfully introduced smart meters to reduce unpaid electricity consumption. 
Ahmad Faruqui et al., 2009 

84

 
 
 
 
 
 
 
 
 
 
 
 
 
                                                 
Euros.  The  interconnector  consists  of  a  21  km  pipeline  in  Slovakia  and  94  km  pipeline  in  Hungary 
with bi-directional capacity. 

Two  open  seasons  were  organised  without  yielding  sufficient  market  demand  through  long-term 
capacity  commitments.  The  first  open  season  did  not  reach  the  threshold  of  10mcm/d,  but  only 
5mcm/d (while total capacity is 14mcm/d). The open season indicated only limited capacity booking 
for short-term contracts (1/3 of capacities for the first 5 years) despite the interest from the Slovakian 
side. 

Key difficulties for the project relate to the cost allocation (based on the length of the pipeline in each 
of  the  country)  which  is  not  sufficiently  taking  into  account  the  wider  benefits.  The  interconnector 
brings  significant  EU  wide  benefits  for  market  integration  in  Central  Eastern  Europe  on  the  North-
South  axis,  but  also  benefits  to  the  Hungarian  gas  market  thanks  to  bringing  in  new  sources  of  gas. 
The project enhances security of supply of Slovakia by providing access to Hungarian gas storages in 
case of emergency. 

The project received support from the European Energy Programme for Recovery totalling 30 million 
Euros. 

85

 
 
 
 
 
ANNEX 12 
EXTERNALITIES FACED BY ENERGY INFRASTRUCTURE PROJECTS 

•  Regional  or  Union-wide  integration  of  shared  electricity  or  gas  resources,  like  large-scale 
renewables  or  gas  from  new  sources  or  an  integrated  offshore  electricity  grid:  The  benefits 
provided have a global public good character, which is not sufficiently reflected in the revenues 
individual operators can earn from the corresponding investments. 

•  Use  of  innovative  technologies:  Projects  can  involve  technological  and  operational  challenges 
and other "first of their kind" and first-mover risks and uncertainties. While the investment costs 
incurred  fall  upon  the  project  promoter  in  the  short  term,  the  benefits  provided  in  terms  of 
technological and operational progress as well as the system benefits and future cost savings for a 
region  or  the  EU  as  a  whole  only  materialise  in  the  medium  to  long  term113.  Examples  include 
high  voltage  direct  current  (HVDC)  electricity  lines,  both  on-  and  offshore,  or  smart  grid 
developments,  but  also  innovative  large-scale  electricity  storage.  Such  projects  are  currently  not 
covered under the public funding available for research, development and deployment, notably at 
EU level (cf. the 7th Framework Programme and the Strategic Energy Technologies Plan). Being 
industrial-scale applications; they are supposed to be paid for by tariffs. In the current regulatory 
environment,  such  innovative  projects  might  be  shelved  and  replaced  by  suboptimal  standard 
solutions, for which the risks and revenues are better known. 

•  Regional  or  Union-wide  security  of  supply  provided  e.g.  through  increased  capacity  of  the 
electricity  or  gas  transmission  network  towards  isolated  or  semi-isolated  systems.  Project 
examples  include  the  Poland-Lithuania  electricity  interconnectors,  the  Estonia-Finland  gas 
pipeline  or  the  projected  common  LNG  terminal  in  the  Baltic  region  aiming  at  ending  their 
isolation,  but  also  many  gas  storage  and  reverse  flow  projects  in  Central  Eastern  Europe.  Such 
projects  can  be  difficult  to  realise,  as  regulators  are  reluctant  to  take  on  costs  for  a  security  of 
supply  benefit,  which  might  only  realise  very  rarely  if  at  all  –  as  is  the  case  for  the  Hungarian-
Slovakia interconnector. 

•  Reduction  of  electricity  loop  flows  through  transit  countries  by  reinforcing  networks  in  the 
transit  countries  or  increasing  transfer  capacities  on  the  direct  route  between  a  generator  and  a 
consumer: As these flows are physical, not commercial, there is not necessarily a natural incentive 
for investments in form of achieving increased cross-border trading capacity. This would typically 
be the case for new transmission lines in Germany to transport wind energy generated in the North 
towards the South of the country and reducing flows through the electricity networks of Poland, 
the  Czech  Republic,  Slovakia,  Hungary  or  Austria  to  the  East  or  the  Netherlands,  Belgium  and 
France to the West. Loop flows occur also in other regions such as Slovenia following commercial 
flows from France to Italy. 

• 

Increased  market  competition  provided  by  adding  new  or  additional  electricity  or  gas 
interconnection capacities and thereby creating the possibility for potential new entrants to access 
markets,  lowering  market  concentration  and  possibly  contributing  to  price  convergence:  Market 
incumbents often resist the implementation of such projects, which makes them difficult to realise. 

•  Long-term optimal capacity (or “advanced capacity”) provided by "oversizing" gas pipelines 
or  offshore  electricity  hubs  and  other  shared  network  components  compared  to  the  short-term 
demand  they  cover:  Infrastructure  in  place  creates  new  opportunities,  stimulates  demand  and 
enables  increased  competition.  According  to  Rious  et  al.  (2010),  proactive  behaviour  of  a  TSO 
that  anticipates  connection  of  new  generators  with  short  construction  durations  compared  to  the 
time needed to reinforce the network is the socially optimal solution. However, due to the risk of 
sunk  costs  in  case  the  generator  never  realises  its  investment  in  electricity  or  the  supplier  never 

113  

Cf. “new wave projects” as defined by Glachant and Kalfallah, 2011 

86

 
 
 
 
 
                                                 
offers  the  quantities  anticipated  in  gas,  the  costs  for  such  advanced  capacity  provision  are 
generally not accepted by national regulators, making such projects impossible to realise. 

• 

Internalisation  of  environmental  externalities:  The  2006  Stern  Review  on  the  Economics  of 
Climate  Change114  report  has  described  climate  change  as  biggest  market  failure  or  externality 
currently  existing,  mainly  due  to  its  supra-regional  nature  and  its  long  time  horizon.  Energy-
related  emissions  constitute  around  80%  of  total  EU  GHG  emissions.  New  or  improved  energy 
infrastructures are necessary to enable the widespread provision of low carbon energy supplies, for 
which demand and supply and costs and benefits will be unevenly distributed across EU Member 
States115.  In  addition,  by  enhancing  the  climate  resilience  of  infrastructures  of  common  interest, 
possible external costs of power outages or network disruptions can be reduced116. 

114  
115  

116  

http://webarchive.nationalarchives.gov.uk/+/http://www.hm-treasury.gov.uk/sternreview_index.htm 
A  first  assessment  of  possible  impacts  from  decarbonisation  of  the  electricity  sector  by  2050  on  the  European 
electricity  network  and  in  particular  interconnectors  and  net  transfer  capacities  between  Member  States  will  be 
published in the Impact Assessment for the Energy Roadmap 2050. 
External costs of transmission system disruptions can exceed several times the impacts to the transmission system 
itself. As investments in reducing the risk of transmission reduction are only made commensurate to the expected 
damage costs incurred by the system's operator, the investment level can be (socially) sub-optimal. 

87

 
 
                                                 
ANNEX 13 
FINANCING CONTEXT FOR GAS AND ELECTRICITY INFRASTRUCTURE 

Table 11: Corporate versus project finance in energy infrastructures 

Source: Roland Berger 

88

 
 
 
 
 
 
 
 
Figure 13: Revenue and size of EU TSOs (based on 2009 revenues in EUR m) 

Source: Roland Berger 

Figure 14: Financial standing of EU TSOs (solvency ratio in %, 2007/2009 average) 

Source: Roland Berger 

89

 
 
 
 
 
 
Figure 15: Ownership structure for EU TSOs in electricity 

Source: Roland Berger 

Figure 16: Ownership structure for EU TSOs in gas 

Source: Roland Berger  

90

 
 
 
 
 
 
Figure 17: Regulated Asset Base increase and funding constraints for EU TSOs 

Source: Rothschild, Presentation “Financing issues for European energy infrastructure”, 10 May 2011 

91

 
 
 
 
ANNEX 14 
THE CURRENT REGULATORY FRAMEWORK FOR INFRASTRUCTURE DELIVERY 

The  2010  impact  assessment  already  presented  the  new  regulatory  framework  of  the  Third  Internal 
Energy Market Package (3rd IEMP)117, applicable as of 3 March 2011, and the regulation on security 
of  gas  supply118  in  terms  of  infrastructure  development  across  borders,  which  will  facilitate  the 
implementation of grid investments in  electricity and gas. Measures provided for by this framework 
would be implemented under the baseline scenario. 

1.  The third internal energy market package 

The  3rd  IEMP  places  the  obligation  on  TSOs  to  operate,  maintain  and  develop  secure,  reliable  and 
efficient transmission. The unbundling rules will provide further incentives for TSOs to operate their 
networks efficiently and to expand them as necessary. As described in the 2010 impact assessment, it 
has become clear that the ten-year network development plans to be developed under this framework 
will not, in the short to medium term, be able to clearly prioritise among their projects to select those, 
which provide the highest European added value in view of implementing the infrastructure priorities 
endorsed by the European Council. 

Internal market legislation also provides a legal basis for implementing network tariffs, which ensure 
the  secure  and  efficient  operation  of  the  network.  NRAs  have  the  obligation  to  provide  for  a  tariff 
framework, which allows for investment to take place to maintain adequate network operation. Article 
37(8) of Directive 2009/72/EC and Article 41(8) of Directive 2009/73/EC in particular stipulate that 
NRAs "in fixing (…) tariffs (…) shall ensure that transmission and distribution system operators are 
granted  appropriate  incentive,  over  the  short  and  long  term,  to  increase  efficiencies,  foster  market 
integration and security of supply and support the related research activities". 
The 3rd IEMP more specifically obliges TSOs to build sufficient cross-border capacity to integrate the 
European  transmission  infrastructure.  Article  16  of  Regulation  714/2009  provides  that  revenues, 
which TSOs collect from marketing scarce cross-border capacities, i.e. congestion revenues, shall be 
primarily  used  for  either  guaranteeing  the  availability  of  the  allocated  capacity  or  investing  in  new 
interconnectors  before  serving  for  reducing  network  tariffs.  The  table  below  shows  past  electricity 
congestion revenues earned by ENTSO-E members in the period 2006-2010. 

Table 12: Electricity congestion revenues 2006-2009 (in EUR m) 

TSO 

Country 

2006 

2007 

2008 

2009 

2010 

Variation 
first data 
year to 2010 
(%) 

APG 

Elia 

NOS BiH 

ESO 
HEP-OPS  

CEPS 

Energinet 
Elering OU 
Fingrid 

Austria 

Belgium 

Bosnia 
Herzegovina 

Bulgaria 
Croatia 

Czech 
Republic 

Denmark  
Estonia 
Finland 

AT 

BE 

BA 

BG 
HR 

26,25 

58,13 

N/A 

0,00 
N/A 

44,46 

40,33 

N/A 

2,32 
N/A 

63,20 

29,24 

49,45 

28,61 

32,54 

23,73 

0,38 

0,20 

0,78 

23,60 
5,86 

19,13 
4,91 

19,55 
12,87 

CZ 

101,96 

59,78 

34,62 

26,18 

18,52 

DK 
EE 
FI 

79,46 
0,00 
11,87 

95,15 
0,00 
22,60 

129,89 
0,00 
23,20 

58,25 
0,00 
4,86 

90,78 
0,22 
9,05 

24% 

-59% 

105% 

742% 
120% 

-82% 

14% 
N/A 
-24% 

117 

118  

Including Directives 2009/72 for electricity and 73 for gas and Regulations 713/2009 on ACER, 714 electricity and 
715 gas 
Regulation No 994/2010. 

92

 
 
 
 
 
  
                                                 
TSO 

Country 

2006 

2007 

2008 

2009 

2010 

Variation 
first data 
year to 2010 
(%) 

RTE 
TSO of 
EnBW+Amprion+50 
Hertz+Tennet+TIWAG 
Netz+VKW Netz 
National Grid 
HTSO 
Mavir 
EirGrid 
Terna 

AS Augstsprieguma 
tikls 

MEPSO 
AD Prenos 
Tennet 
Statnett 
PSE Operator 
REN 
Transelectrica 
EMS 

SEPS 

ELES 
REE 
Svenska Krafnät 

France 

FR 

342,00 

376,50 

380,60 

256,98 

260,37 

-24% 

Germany 

DE 

316,30 

220,56 

222,46 

167,90 

141,00 

-55% 

Great Britain  GB 
GR 
Greece 
HU 
Hungary 
IE 
Ireland 
IT 
Italia  

N/A 
22,00 
29,44 
6,20 
89,82 

N/A 
5,06 
47,09 
13,14 
333,82 

106,00 
31,32 
76,44 
0,00 
294,61 

66,10 
35,47 
48,98 
0,00 
187,83 

61,60 
29,29 
15,38 
0,00 
211,65 

-42% 
33% 
-48% 
-100% 
136% 

Latvia 

LV 

0,00 

0,00 

0,00 

0,00 

0,22 

N/A 

FYROM 
MK 
Montenegro  ME 
NL 
Netherlands 
NO 
Norway 
PL 
Poland 
PT 
Portugal 
RO 
Romania 
RS 
Serbia 

N/A 
N/A 
107,63 
17,96 
70,16 
0,00 
10,68 
N/A 

N/A 
N/A 
53,96 
31,90 
40,92 
23,22 
17,69 
N/A 

1,16 
1,77 
105,90 
112,90 
28,08 
32,30 
36,66 
29,04 

6,71 
3,67 
59,00 
45,60 
13,43 
5,52 
22,09 
18,85 

4,40 
4,32 
34,00 
112,70 
6,43 
6,07 
6,92 
17,22 

Slovak 
Republic 

Slovenia 
Spain 
Sweden 

SK 

22,48 

44,39 

36,17 

27,90 

5,10 

SI 
ES 
SE 

CH 

3,12 
25,79 
35,40 

35,29 

25,91 
61,78 
67,83 

40,05 

32,55 
77,95 
85,30 

78,10 

32,95 
41,58 
28,17 

59,37 

28,51 
33,28 
54,98 

62,02 

Total  1.411,93  1.668,47  2.079,31  1.319,71  1.303,49 

279% 
144% 
-68% 
527% 
-91% 
#DIV/0! 
-35% 
-41% 

-77% 

814% 
29% 
55% 

76% 

-8% 

Swissgrid 

Switzerland 

Note: Countries with no congestion rents are not represented. 

Source: data from national TSOs collated by ENTSO-E, Commission analysis (last column), 2011 

2.  The exemption regime 

In cases where "the level of risk attached to the investment [is] such that the investment would not take 
place  unless  an  exemption  was  granted",  EU  internal  market  legislation  foresees  the  possibility  for 
new cross-border infrastructure projects to be exempted by NRAs from third party access (the owner 
of a grid is obliged to allow any suppliers non-discriminatory access to its grid to supply customers), 
regulated tariffs, unbundling rules and (for electricity) rules on the use of congestion rents119. In cases 
where the NRAs concerned cannot agree on a decision within a given period of time ACER is obliged 
to take their place and issue a decision. The procedures also foresee that the Commission can ask the 
NRAs or ACER to amend or withdraw the exemption granted. 

Such  exemptions  have  e.g.  been  granted  to  large  pan-European  gas  import  pipelines  or  LNG 
infrastructures  and  have  comforted  investors  whose  projects  are  either  very  capital  intensive  and/or 
carry exceptional risks, which could not be accommodated within the standard regulatory framework.  

However,  exemptions  should  only  be  granted  in  cases  where  the  risks  related  to  the  investment  are 
such  that  it  is  not  viable  without  an  exemption  and  when  the  new  infrastructure  will  enhance 
competition.  As  demonstrated  in  Pelkmans  and  Kapff  (2010),  while  contributing  to  cross-border 

119 

Article 36 Directive 2009/73/EC (gas) and Article 17 Regulation (EC) No 714/2009: The exemption regime applies 
to all direct current electricity lines and certain alternating current lines and to major new gas infrastructure, i.e. 
interconnectors, LNG and storage facilities. 

93

 
 
  
 
                                                 
network  development,  exempted  (merchant)  interconnector  investments  financed  through  congestion 
rents alone yield suboptimal results in terms of socially desirable levels of interconnection capacity. In 
addition,  broad  exemptions  from  the  regulated  regime  without  additional  conditions  may  weaken 
competition, hinder reinvestment of profits in grid reinforcements and undermine the application of a 
harmonized regulatory framework across the EU. To this end, the Commission has regularly asked for 
substantial  amendments  of  national  exemption  decisions  with  the  view  to  alleviate  potential 
competition concerns and support network investment. 

Under the baseline scenario, the Commission would therefore continue to push national regulators to 
establish appropriate incentives through regulated tariffs and to grant exemptions only where justified 
and  with  regulatory  conditions  that  ensure  third  party  access  and  support  the  development  of 
infrastructures.  Such  an  approach  is  likely  to  deliver  the  types  of  projects  targeted  under  the  third 
package, i.e. gas and electricity projects enhancing competition and security of supply. The exemption 
regime  does  not  specifically  address  electricity  projects  aiming  at  the  integration  of  renewables  or 
greater system reliability. Nor does it solve the problem faced by projects with asymmetric cost and 
benefit allocation, as any exemption is subject to a national regulatory authority assessing the request 
made by an operator. It can hence be concluded that the exemption regime would allow certain riskier 
investments to be delivered, without addressing the underlying problems related to cost allocation and 
broader investment incentives. 

3.  The target model 

The Commission has worked over the last few years with regulators, TSOs and all other stakeholders 
to develop an electricity target model based on market coupling for linking electricity markets. For gas 
a target model is currently being developed. The process of implementing the 3rd IEMP by developing 
guidelines, framework guidelines and network codes to reach the necessary level of harmonisation has 
already  been  started.  Currently  these  guidelines,  framework  guidelines  and  network  codes  are  being 
prepared  for  electricity  and  gas  to  achieve  common  and  coordinated  congestion  management120  and 
capacity allocation procedures on all interconnectors. For the years 2012 and onwards, the priorities 
for gas will notably include framework guidelines or guidelines on tariffs. The Commission could also 
propose additional guidelines on investment incentives to TSOs in electricity. All these new rules shall 
be in place by 2014. 

Aligning  procedures  for  trading  on  interconnectors  will  help  to  align  national  markets  and  provide 
more  harmonised  signals  across  the  EU  for  investment  in  new  interconnection  capacity.  These 
regulatory  efforts  will  considerably  improve  investment  signals,  including  for  cross-border 
infrastructure, once they are fully operational. 

4.  The regulation on security of gas supply 

The  regulation  on  security  of  gas  supply  for  the  first  time  proposes  two  clear  and  binding 
infrastructure standards: 

−  Member  States121  shall  ensure  that  gas  demand  can  be  met  even  at  the  loss  of  their  largest 
infrastructure  (N-1  criterium).  They  have  until  2014  to  comply  with  this  rule.  Preliminary 
calculations  of  compliance  with  the  n-1  standard  with  and  without  projects  to  be  financed 
under the EEPR can be found in the figure and the table below; 

−  TSOs  have  to  install  physical  reverse  flows  at  all  cross-border  interconnections  between 

Member States by end 2013, where they are beneficial for security of supply122. 

120  

121 
122 

It should be noted that the measures proposed by the Commission on congestion management for gas only address 
contractual congestion at interconnection points and not physical congestion; nor do they address problems faced in 
the  absence  of  interconnections  (see  draft  impact  assessment  accompanying  the  Commission  guidelines  on 
congestion management procedures and replacing existing guidelines annexed to Regulation (EC) 715/2009). 
Except Luxemburg, Slovenia, and Sweden. 
Exemptions are possible and Member States can opt for a regional approach to fulfill these standards. 

94

 
 
                                                 
Figure 18: Compliance with the N-1 standard (2009) 

300%

250%

200%

N-1

150%

100%

50%

0%

DK GR DE BE SK AT PL NL LV CZ EE ES IT HU FR UK RO SE LU PT BG SI

LT IE FI EU

Normal

EERP

Table 7: Compliance with the N-1 standard (2009) 

Production 
withdrawal 
capacity 
12,16 
0,00 
0,30 
0,00 
0,30 
45,00 
29,90 
0,00 
0,00 
0,00 
2,40 
0,00 
9,00 
1,00 
24,00 
0,00 
0,00 
0,00 
0,00 
440,00 
6,48 
0,00 
34,30 
0,00 
0,00 
0,30 
231,00 

Maximal 
Consumption* 
49,41 
139,20 
15,60 
0,00 
67,60 
400,00 
25,70 
4,30 
160,20 
1,00 
370,00 
14,00 
92,50 
20,30 
425,00 
16,00 
5,98 
9,00 
0,00 
235,00 
59,71 
19,30 
75,00 
6,00 
5,80 
29,90 
536,00 

Storage 
Withdrawal 
capacity 
48,00 
22,80 
4,20 
0,00 
55,01 
463,32 
18,80 
0,00 
10,54 
0,00 
231,00 
0,00 
47,50 
2,60 
295,85 
0,00 
0,00 
14,69 
0,00 
153,02 
34,20 
7,00 
25,80 
0,60 
0,00 
34,87 
126,57 

LNG 
send-out 
capacity 
0,00 
24,70 
0,00 
0,00 
0,00 
0,00 
0,00 
0,00 
160,90 
0,00 
42,44 
13,69 
0,00 
0,00 
35,00 
0,00 
0,00 
0,00 
0,00 
0,00 
0,00 
14,20 
0,00 
0,00 
0,00 
0,00 
84,56 

Incoming 
Pipeline 
Capacity 
137,52 
321,61 
72,00 
0,00 
185,98 
579,44 
0,00 
22,99 
67,01 
20,68 
156,28 
38,36 
58,04 
30,00 
284,80 
39,11 
11,30 
24,64 
0,00 
95,62 
147,56 
13,21 
113,00 
8,49 
14,53 
301,00 
241,34 

Single Largest 
Infrastructure 
125,94 
94,43 
72,00 
0,00 
141,94 
105,96 
29,90 
16,80 
39,70 

20,68 
50,00 

19,20 
39,80 
30,00 
114,60 
30,00 
4,93 
24,64 
0,00 
300,00 
108,00 
14,20 
102,00 
8,49 
10,13 
301,00 
73,70 

N-1 
145% 
197% 
29% 
- 
147% 
245% 
73% 
144% 
124% 

0% 
103% 
235% 
81% 
18% 
124% 

57% 
107% 
163% 
- 
165% 
134% 
105% 
95% 
10% 
76% 
118% 
114% 

Mcm/day 
AT 
BE 
BG 
CY 
CZ 
DE 
DK 
EE 
ES 
FI 
FR 
GR 
HU 
IE 
IT 
LT 
LU 
LV 
MT 
NL 
PL 
PT 
RO 
SE 
SI 
SK 
UK 

*(1-in-20 winter case) 
Source: SEC(2009)979; IHS and Gas Coordination Group 

95

 
 
 
 
According  to  Regulation  994/2010  and  the  Commission  preliminary  analysis  (Annex  X),  Bulgaria, 
Lithuania, Ireland, Finland, Hungary, Denmark, Romania, Sweden and Slovenia did not fulfill the N-1 
rule  in  2009.  Over  the  last  years,  the  EEPR  programme  accelerated  a  number  of  gas  infrastructure 
projects  that  will  help  those  countries  to  meet  the  N-1  standard  by  the  deadline.  However,  it  is 
expected  that  further  measures  will  be  needed  for  Bulgaria,  Lithuania,  Finland,  and  Ireland.  The 
Regulation allows Sweden, Slovenia and Luxembourg to have a longer timeframe to meet  N-1. The 
Regulation  allows  the  Member  States  flexibility  in  meeting  the  N-1  rule  -  through  demand-side 
measures  or  regional  N-1  rule.  While  the  N-1  standard  ensures  the  security  of  gas  supply  mainly  at 
national  and  partially  at  regional  level,  it  does  not  automatically  ensure  the  infrastructure  needed  to 
enhance market integration or competition in a wider European gas market.123 

5.  Other regulatory measures 

Furthermore,  tariff  setting  would  remain  the  exclusive  competence  of  NRAs.  Investments  in  cross-
border  infrastructure  would  continue  to  be  subject  to  the  same  rules,  which  also  govern  domestic 
infrastructure investments. This framework will ensure that cross-border investments go ahead, with 
TSOs sharing costs according to individual agreements (usually covering all investment cost in their 
own  service  area)  with  congestion  revenues  often  split  on  a  50:50  basis,  although  other  ratios  have 
been seen as well124. 

Projects  with  asymmetric  benefits  and  costs  across  border  however  will  continue  to  suffer  from  the 
absence of a transparent cost-benefit analysis125 and an effective cost allocation mechanism covering 
all  investments  beyond  those  covered  under  the  security  of  gas  supply  regulation  with  regard  to 
benefits oriented cost allocation126. Even if multilateral cost sharing agreements could be developed, 
which  would  be  burdensome  and  on  a  case-by-case  basis  only,  this  would  significantly  hamper  the 
development of infrastructures of common interest. 

In gas, the open season procedure to assess market demand would continue to be used, although, when 
designed along national rules, it will tend to shield incumbents against competition and fail to deliver 
in  regions  which  lack  a  competitive  gas  market  structure.  Today,  open  seasons  are  governed  by 
voluntary  CEER  guidelines  on  best  practices,  which  are  currently  under  revision.  The  CEER  public 
consultation carried out in 2010 concluded that the open season procedures lack transparency and do 
not provide for sufficient efficiency in getting binding commitments127. 

In  electricity,  the  inter-transmission  system  operator  compensation  (ITC)  mechanism,  which 
compensates  TSOs  for  the  cost  of  hosting  transit  flows  caused  by  other  Member  States,  would 
continue to be the only existing pan-European cost allocation mechanism128. Several limitations to this 
mechanism have however been identified by operators and regulators. First, the ITC is not designed 
for incentivising new large scale investments in the transmission network, which are needed to meet 
the  infrastructure  needs  identified.  Second,  the  corresponding  fund  is  capped  at  100  million  euros, 
constraining  its  ability  for  significant  redistribution129.  Third,  the  ITC  only  serves  to  transfer  funds 
from import or export countries to transit countries, not for more complex constellations. 

123  

124  

125 

126 

127  

128 
129 

It will become fully clear how many Member States require additional investment to fulfill N-1 in December 2011 
when the risk assessments under Article 9 of the Regulation are presented by the Competent Authorities. 
The Ireland-UK electricity interconnector will be fully paid by the Irish TSO Eirgrid. France and Luxemburg have 
also agreed on an asymmetric allocation of costs for new gas interconnection capacities at their border. 
See  Proost  et  al.,  2010,  on  the merits  of  cost-benefit  analysis  for  projects  of  European  relevance  in  the  transport 
sector. 
Article 6(8) of the security of gas supply regulation already allows for cost-benefit allocations in case of reverse 
flow investments. 
CEER  position paper  on  cost  allocation:  CEER consulted  in  2009  on  the  revision  of  the  ERGEG  GGP  on  Open 
Season procedures (GGPOS). The ERGEG Guidelines for Good Practice on Open Season Procedures (GGPOS), 21 
May 2007. 
Regulation 714/2009, article 13 and Commission Regulation 838/2010 
Based  on  load  data  for  2009  and  costs  of  losses  for  2011,  the  main  contributors  to  this  fund  are  Italy,  Norway, 
Great Britain, France and the Czech Republic, while the main beneficiaries are Germany, Switzerland, Sweden and 
Austria (Source: ENTSO-E). 

96

 
 
 
                                                 
6.  Permit granting framework 

Permit granting for energy infrastructure projects is a Member State competence, with varying rules 
and practices across the EU. Only a few countries have so far passed legislation to address problems 
related to administrative permit granting procedures and resulting delays. Reforms to introduce "one-
stop shops" and time limits were recently passed in Ireland, the Netherlands and the United Kingdom, 
resulting  in  significant  reductions  in  the  duration  of  the  process130.  In  July  2011,  the  German 
government passed a law for the acceleration of network expansion, which also foresees the creation 
of  a  "one-stop  shop"  for  planning  and  permit  granting  of  important  electricity  infrastructures,  to  be 
managed by the national regulatory authority. The latter would also be in charge of fixing time limits 
for each project submitted to the one-stop shop. As of today, time limits for the entire statutory process 
of granting permits exist in 5 Member States (Austria, Czech Republic, Greece, Ireland, Italy), while 
10 Member States (Austria, Germany, Greece, Ireland, Italy, the Netherlands, Poland, Romania, Spain 
and  the  United  Kingdom)  have  fast-track  schemes  for  certain  types  of  infrastructure  (see  details  in 
Annex 7). 

It  is  expected  that  such  legislation  will  deliver  improvements  in  the  Member  States  where  it  is 
implemented, though leaving untouched problems faced in the remaining Member States. 

130  

Results from a consultation carried out amongst members of ENTSO-E in March 2011. 

97

 
 
 
                                                 
ANNEX 15 
PAST AND FUTURE INFRASTRUCTURE DEVELOPMENT IN THE EU 

Table 13: New EU cross-border electricity projects realised between 2000 and 2011 

Project 

Sub-section / routing / 
specification 

Estimated 
total cost 
(M€) 

Indicative 
start of 
operations 

EU grants 1995-
2010 (M€, TEN-E, if 
not otherwise 
stated) 

Vigy (FR) - Uchtelfangen 
(DE) line 

Western Pyrenean 
interconnection FR - ES 

Cantegrit - Mougerre (220kV) 
- (Arkale, ES) 

Ipiros (GR) - Puglia (IT) 

Lindoso II (PT) - Cartelle (ES) 

N/A 

2004 

San Fiorano (IT) - Robbia 
(CH) 

N/A 

N/A 

N/A 

N/A 

2002 

2002 

2002 

2002 

39 

77 

2004 

2005 

21,5 

2005 

35 

2006 

110 

2006 

5 (for the 
GR side) 

2007 

Kardia (GR) – Elbasan 
(AL) line 

New connections for the 
Mediterranean Electricity 
Ring 

North-East PT - North-
West ES line 

Sines (PT) - Alqueva (PT) 
- Balboa (ES) line 

IT - CH line 

Avelin (FR) - Avelgem 
(BE) line 

Reinforcement of the 
connections DK - SE 

Meliti (GR) - Bitola 
(Former Yugoslav 
Republic Of Macedonia) 
line 
Eemshaven (NL) - Feda 
(NO) link  

Submarine cable to link FI 
and EE 

Estlink cable 

NorNed cable 

565 

2008 

Békéscsaba (HU) - 
Oradea (RO) 

Békéscsaba (HU) - Nadab 
(RO) - Arad (HU) 

18,5 

2008 

Philippi (GR) - Hamidabad 
(TR) line 

Dürnrohr (AT) - Slavetice 
(CZ) line 

New connections between 
GR, AL, BG and FYROM 

Stip (FYROM) – C. Mogila 
(BG) 

New connections for the 
Mediterranean Electricity 
Ring 

Pécs (HU) - Ernestinovo 
(HR) 

New connection mid SE - 
mid NO 

Moulaine (FR) - Aubange 
(BE) line 

70 

9 

50 

55 

2008 

2008 

2009 

2009 

43,6 

2010 

66 

2010 

11  (FR) 

2010 

98

0,23 

0,68 

0,25 

1,01 

0,67 

0,13 

8,72 

2,02 

0,55 

2,24 

0,06 

0,50 

 
 
 
 
 
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
  
South PT - South-West 
ES 

Portimão (PT) - Tavira (PT) - 
P. Gusman (ES) - Guillena 
(ES) line and Tavira facilities 

90,9 

2011 

50 (EEPR) 

Connection between IE 
and Northern Ireland (UK) 

400 kV North South 
Interconnector 
(Tyrone – Cavan) 

N/A 

2011 

0,60 

Valdigem (PT) - Douro 
Internacional (PT) - 
Aldeadavila (ES) line and 
facilities 

400 kV Douro interconnection 
Aldeadávila (ES) - Lagoaça 
(PT) 

Submarine cable South-
Eastern UK - central NL 

BritNed cable (Isle of Grain in 
Kent (UK) - Maasvlakte (NL)) 

Connection north of the 
Gulf of Bothnia (FI) - SE 

Fennoscan cable 

88 

2011 

51,808 (of which 
50 EEPR) 

600 

300 

2011 

2011 

12,75 

0,75 

Source: ENTSO-E, European Commission DG Energy, 2011 

Table  14:  Planned  transboundary  electricity  projects  (new  lines  and  upgrades)  in  the  2010 
TYNDP for the period 2011-2025 

Important  disclaimer:  This  list  is  a  compilation  of  projects  as  provided  by  ENTSO-E  members  and 
provided  for  information  purposes  only.  It  does  not  prejudge  any  future  selection  of  projects  of 
common interest. 

Border 

AL-ME 

AL-RS 

AT-HU 

AT-IT 

AT-IT 

AT-IT 

AT-IT 

BA-HR 

BA-HR 

BA-HR 

BA-ME 
BG-GR 
BG-RO 

Project characteristics 

New 400kV line Tirana (AL)-Podgorica (ME) with length 157km (128.5km 
on Albanian side, 76km of which with double circuit and 28.5km on the 
Montenegrin side). 
New 238km 400kV OHL; on 78km the circuit will be installed on the same 
towers as the Tirana-Podgorica OHL currently in construction (see project 
233); the rest will be built as single circuit line. 
Installation of the 2nd circuit on the existing interconnection from Wien SO 
(AT, APG) to the border (both circuits have already been installed on the 
Hungarian side, one is connected to Györ and the 2nd circuit to 
Szombathely). Line length: 63km. 
New double circuit 400kV interconnection through the pilot tunnel of the 
planned Brenner Base Tunnel. Total line length: 65km. 
The project foresees the reconstruction of the existing 220kV-
interconnection line as 380kV-line on an optimized route to minimize the 
environmental impact.Total length should be in the range of 100-150km. 
New 380/220kV substation in AT directly located near the border ; erection 
of a 24km single circuit 220kV-connection via OHL and underground cable 
till Graun (IT) and upgrade of the existing line Graun (IT) – Glorenza (IT).  
 Upgrade of  the existing 44km Prati di Vizze (IT) – Steinach (AT) single 
circuit 110/132kV OHL, currently operated at medium voltage and installing 
a 110kV/132kV PST in Steinach (AT). 
New 400kV interconnection line between existing stations. 
Connection of new generator on existing line 220kV Mraclin (HR) - Prijedor 
(BA) via a new double circuit OHL. Line length: 12km. 

Re-establishment of previously existing 220kV double circuit 
interconnection Trebinje(BA)-Plat(HR); Total length 10km. 

New 400kV transmission line between existing stations. Line length: 70km. 
 New interconnection line BG-GR by a 130km single circuit 400kV OHL. 
New 400kV double circuit OHL to accommodate RES generation. Line 

Connection 
type 

Length of 
Infrastructure 
line [km] 

new lines 

157 

new lines 

238 

new lines 

new lines 

upgrade of 
existing 
lines 
upgrade of 
existing 
lines 
upgrade of 
existing 
lines 
new lines 

new lines 

upgrade of 
existing 
lines 
new lines 
new lines 
new lines 

63 

65 

125 

24 

44 

50* 

12 

10 

70 
130 
10 

99

 
 
 
 
 
 
 
Border 

CH-IT 

CZ-AT 

CZ-DE 

DE-AT 

DE-AT-
CH 

DE-BE 

DE-FR 

DE-NL 

DE-PL 

DE-PL 

DK-DE 

DK-DE 

DK-DE 

DK-NL 

DK-NO 

EE-FI 

EE-LT 

Project characteristics 

length: 2x10km. 

New 400kV tie line between Italy and Switzerland. 
Possible increase of interconnection capacity between CEPS and 50Hertz 
Transmission is under consideration: either a new 400kV tie-line (OHL on 
new route) or a reinforcement of the existing 400kV tie-line Hradec (CEPS) 
– Röhrsdorf (50Hertz Transmission).  
New 400kV single circuit tie-line between new (CZ) substation and existing 
(DE) substation. Length: 70km. 
New 400kV double circuit OHL Isar - St. Peter including new 400kV 
switchgears Altheim, Simbach and St. Peter and one new 400/230kV 
transformer in substation Altheim. Line length: 90km. 

Construction of new lines, extension of existing ones and erection of 
400/220/110kV-substation.  

Connection 
type 

Length of 
Infrastructure 
line [km] 

new lines 

70* 

upgrade of 
existing 
lines 

new lines 

new lines 

upgrade of 
existing 
lines 

120* 

70 

90 

100* 

Connection between Germany and Belgium including new 100km 
underground cable and extension of existing 380kV-substations.  

new lines 

100 

Change of conductors on the German part of this single circuit 225kV line 
(9km) and installation of a phase-shifter in Ensdorf (DE) 225kV substation. 

New 400kV line double circuit DE-NL interconnection linew. Length: 60km. 
This project is the 3rd 400kV double circuit OHL interconnection between 
Poland (Plewiska) and Germany (Eisenhüttenstadt) with reinforcement of the 
Polish internal grid. Total length is 252km, 242km of which being in Poland. 
This project is the conversion of existing 220kV double circuit line Krajnik 
(PSE Operator) - Vierraden (50Hertz Transmission) into a 400kV line 
together with installation of phase shifting transformers in Krajnik (PSE 
Operator) and Mikułowa (PSE Operator). 
The Kriegers Flak project is the new subsea cable multiterminal connection 
between Denmark, Sweden and Germany used for both grid connection of 
offshore wind farms Kriegers Flak and interconnection. Technical features 
still have to be determined. 
Installation of two PSTs. This project is in the framework of step 2 in the 
Danish-German agreement to upgrade the Jutland-DE transfer capacity; This 
step includes also planed strengthening of existing 380kV lines in the grid of 
TPS and Energinet.dk . 
Step 3 in the Danish-German agreement to upgrade the Jutland-DE transfer 
capacity. It consists of partially an upgrade of existing 400kV line and 
partially a new 400kV route in Denmark. In Germany new 400kV line 
mainly in the trace of a existing 220kV line. The total length of this OHL is 
114km. 
COBRA: New single circuit HVDC connection between Jutland and the 
Netherlands via 350km subsea cable; the DC voltage will be up to 450kVand 
the capacity 600-700MW. 
Skagerak 4: 4th HVDC connection between Southern Norway and Western 
Danmark, built in parallel with the existing 3 HVDC cables; new 700MW 
including 230km 500kV DC subsea cable. 
A new HVDC (450kV) connection will be built between Estonia and 
Finland. On the Finnish side, a 14km DC overhead line will be built to a new 
substation Anttila where the converter station will be placed. On the Estonian 
side, a 11km DC cable line will be built to a existing substation Püssi where 
the converter station will be placed. Length of marine cable is 140km. 
Expected capacity: 650MW. 
Latvian-Estonian third interconnection will consist of OHL Harku-Sindi-
Lihula in Estonian part, OHL Imanta-Tume-Dundaga-Ventspils in Latvian 
part, and sea cable between cross-border DC ar AC cable. Final 
interconnection type and final interconnection and transmission line route 
will be selected in middle of 2010. At present three alternative route variants 
researched. Final interconnection length, DC voltage and transmission 
capacity will be selected in feasibility and technical study in the middle of 
2010. The connection would be as a new single circuit line mixed 
(OHL+subsea cable) up to 500kV. 

upgrade of 
existing 
lines 
new lines 

9 

60 

new lines 

252 

upgrade of 
existing 
lines 

600* 

new lines 

160* 

upgrade of 
existing 
lines 

upgrade of 
existing 
lines 

40* 

114 

new lines 

350 

new lines 

230 

new lines 

165 

new lines 

380* 

100

 
 
Border 

ES-FR 

ES-FR 

ES-PT 

ES-PT 

ES-PT 

FI-SE 

FI-SE 

FR-BE 

Project characteristics 

New HVDC (VSC) bipolar interconnection in the Eastern part of the border, 
via +/- 320kV DC underground cable using existing infrastructures corridors 
and converters in both ending points. The thermal capacity is expected in the 
range 2x825-2x1000MW. Total line length: 60km. 
New cross-border line - not in the French department "Pyrenees Orientales" 
nor in the Spanish region of Cataluña. 
New Duero Interconnection 400kVNew 400kV OHL interconnection line 
Aldeadávila (ES) - Lagoaça (PT) , including new Lagoaça substation (PT). 
Also associated, the lines Lagoaça-Armamar-Recarei 400kV in PT and the 
Armamar (PT) 400/220kV substation.On a first phase (2009) a new 
400/220kV substation (Lagoaça - PT) will be created with only 220kV level 
installed, and there will be some rearrangements and reinforcements on the 
local 220kV network structure. On river crossing a new 220kV double line 
with separated circuits, firstly Aldeadavila (ES) - Lagoaça (PT) 1 & 2 and 
changing later to Aldeadavila (ES) - Pocinho (PT) 1 & 2, will substitute the 
existing two 220kV lines Aldeadavila (ES) – Bemposta (PT) and 
Aldeadavila (ES)-Pocinho (PT). Total length: 1km (ES)+105km (PT). 
New Southern Interconnection  
New 400kV OHL double-circuit line between Guillena (ES)-Puebla de 
Guzman (ES) - Tavira (PT) - Portimão (PT), including new Tavira (PT) and 
P.Guzman (ES) 400kV substations. On the interconnection section 
P.Guzmán (ES) –Tavira(PT), initially only one circuit will be placed. Total 
length: 153km (ES)+110km(PT). 
New double circuit 400kV OHL between O Boboras (ES) -O Covelo (ES) - 
Vila Fria (PT) - Vila do Conde (PT) - Recarei (PT), including new 400kV 
subestations O Covelo (ES), Boboras (ES), Vila Fria (PT) and Vila do Conde 
(PT). 
On the section O Covelo (ES) – Vila do Conde (PT), only one circuit will be 
placed.           Total length: 43km (ES)+112km (PT).  
A new 500kV HVDC connection will be built in parallel with the existing 
one between Finland and Sweden. On the Swedish side, a 70km direct 
current overhead line will be built to a new substation Finnböle where the 
converter station will be placed. Total length of line: 300km and capacity: 
800MW. 
Third single circuit 400kV AC OHL between Sweden and Finland. Expected 
capacity: 1850 MVA. 
to be determined. 

FR-BE 

Installation of a second circuit on the existing 225kV cross-border OHL. 

FR-CH 

Reinforcement of the interconnection in the area of Geneva's lake. 

"Savoie - Piémont" Project : 
New 190km HVDC (VSC) interconnection FR-IT via underground cable and 
converter stations at both ends (two poles, each of them with 500MW 
capacity). The cables will be laid in the security gallery of the Frejus 
motorway tunnel and possibly also along the existing motorways' right-of-
way. 
Replacement of conductors (by ACCS) on Albertville (FR) - Montagny (FR) 
- Cornier (FR) and Albertville (FR) - La Coche (FR) - La Praz (FR) single 
circuit 400kV OHLs. Overcoming of constraints of Villarodin (FR) - Venaus 
(IT) - Piossasco (IT) single circuit 400kV OHLs. In addition, change of 
conductors and operation at 400kV of an existing single circuit OHL 
between Grande Ile and Albertville (FR) currently operated at lower voltage, 
and associated works in Albertville (FR) 400kV substation. (Total length of 
lines: 257km : French side 66+95+41 Italian side 55). 
Connection of SOTEL (industrial grid in LU) to RTE network by mixed 
(underground cable & OHL) single circuit 225kV line. 
Parts of the new line use existing ones. 
New subsea DC link, between GB and FR, possibly with a capacity of 
1000MW (still to be determined). 

FR-IT 

FR-IT 

FR-LU 

FR-UK 

Connection 
type 

Length of 
Infrastructure 
line [km] 

new lines 

60 

new lines 

60* 

new lines 

106 

new lines 

263 

new lines 

155 

new lines 

300 

new lines 

new lines 
upgrade of 
existing 
lines 
upgrade of 
existing 
lines 

100* 

50 

30* 

60* 

new lines 

190 

upgrade of 
existing 
lines 

new lines 

new lines 

459 

30* 

90* 

316 

GR-IT 

Second 500MW HVDC link between Greece and Italy via 316km 400kVDC 

new lines 

101

 
 
Border 

Project characteristics 

subsea cable and converters stations at both ends.  

IE-UK 

IE-UK 

A new 260km HVDC (380kV DC) underground and subsea connection 
between Ireland and Britain with 500MW capacity. On the Irish side, a 45km 
direct current underground cable will be built to the Woodland substation 
where the VSC converter station will be placed. The link will consist of two 
identical circuits. 
A new 80km single circuit 400kV 1500MVA OHL from a new Moyhill 
400/220kV substation in Ireland to a new Turleenan 400/275kV substation in 
Northern Ireland. This project is an integral part of the new interconnection 
project Moyhill- Wooodland between Ireland and Northern Ireland.  

IE-UK 

Strengthening of EHV networks (partial uprate and new) into Donegal and 
West of Northern Ireland and enhanced links between the two systems.  

 500MW single pole HVDC Merchant Line between Italy and Albania via 
290km 400kV DC subsea cable and converter staitons at both ends. On the 
Italian side, the new line will be connected to the existing substation of 
Brindisi South. 
New 1000MW HVDC interconnection line between Italy and Croatia via 
280km 500kVDC subsea cable and converters stations at both ending points. 
New 1000MW HVDC interconnection line between Italy and Montenegro 
via 375km 500kV DC subsea cable and converter stations at both ending 
points. 

Upgrade single circuit OHL (943 MVA, 50km). 

(NordBalt) A new 300kV HVDC VSC partly subsea and partly undergroud 
cable between Lithuania and Sweden. (440km). 
New interconnection between Creos grid in LU and ELIA grid in BE via a 
16km double circuit 225kV underground cable with a capacity of 1000 
MVA. 
New 200km cross-border single circuit 400kV OHL between existing 
substations. 
Installation of an additional transformer + replacement of an existing one 
(400/110kV and 220/110kV) and shunt reactors in substations, upgrading 
and decommissioning of substations. 
Nord.Link: A new HVDC connection between Southern Norway and 
Northern Germany. Estimated subsea cable length: 520 - 600km. Capacity: 
700 - 1400MW. 
New single circuit 400kV OHL (500km, 1850 MVA). 
NorNed 2: a 2nd HVDC connection between Norway and The Netherlands 
via 570km 450kV DC subsea cable with 700 - 1400MW capacity. 
"South West link" 
consisting of three main parts: 
1) New 400kV line between Hallsberg and Barkeryd 
2) New double HVDC VSC underground cable line between Barkeryd and 
Hurva 
3) New HVDC VSC line between Barkeryd and Tveiten/Norway.  
The project also include new substations and converter stations in the 
connection points line  
double circuit new OHL Hallsberg - Barkeryd 170km, underground VSC 
Barkeryd - Hurva 250km and VSC Barkeryd - Tveiten with 103km on the 
Norwegian side. Expected capacity: 1200MW. 

Connection 
type 

Length of 
Infrastructure 
line [km] 

new lines 

260 

new lines 

80 

upgrade of 
existing 
lines 

50* 

new lines 

290 

new lines 

new lines 

upgrade of 
existing 
lines 

280 

375 

50 

new lines 

440 

new lines 

16 

new lines 

200 

substation 
ugrade  

new lines 

new lines 

new lines 

1 

560 

500 

570 

new lines 

523 

 A joint Stattnett & Svenska Kraftnat study north - south reinforcement (AC 
or VSC), expected length: 400 - 500km under study. 

A new 1400MW HVDC bipolar installation connecting Western Norway and 
the UK via 800km subsea cable; DC voltage is to be determined. 
Construction of a new 400kV OHL Ełk to PL-LT border. (2x1870 MVA, 
108km). 
Construction of Back-to-Back convertor station near Alytus 330kV 
substation. Construction of double circuit 400kV OHL between Alytus and 
PL-LT border. Construction of 330kV AC line Alytus-Kruonis. Length of 

upgrade of 
existing 
lines 

new lines 

new lines 

new lines 

450 

800 

108 

46 

102

IT-AL 

IT-HR 

IT-ME 

LT-LV 

LT-SE 

LU-BE 

MK-AL 

n.a. 

NO-DE 

NO-FI 

NO-NL 

NO-SE 

NO-SE 

NO-UK 

PL-LT 

PL-LT 

 
 
Border 

Project characteristics 

line: 46km. 

Connection 
type 

Length of 
Infrastructure 
line [km] 

Establish existing 750kV interconnection between Poland and Ukraine. 
Mode of operation on border lines (synchronous/asynchronous) depends on 
results of future study concerning possibility of synchronous connection of 
Ukraine and Moldova to continental part of ENTSO-E and bilateral Polish - 
Ukrainian agreement. 
New 400kV transmission line between existing station in Romania and new 
substation in Moldavia. Line length: 145km.  
New DC link (subsea cable) between existing stations in RO and TR. Line 
length: 400km. 
New 220km 400kV single circuit overhead interconnection between Serbia 
and FYROM. A new 400/110 substation will be built in Serbia between 
connection nodes. 
A new 400kV OHL releavant to planning investment of 2000MW of TPP in 
the area of Kosovo and Metohija. Line length: 85km. 
New 150km double circuit (single wired at the beginning) 400kV OHL 
between existing substations.  
The existing substation of Cirkovce (SI) will be connected to one circuit of 
the existing Heviz (HU) -Zerjavinec (HR) double circuit 400kV OHL by 
erecting a new 80km double circuit 400kV OHL in Slovenia. The project 
will result in two new cross-border circuits: Heviz (HU) - Cirkovce (SI) and 
Cirkovce (SI) - Žerjavenec (HR).  
New 120km double-circuit 400kV OHL with installation of a PST in 
Okroglo. The thermal rating will be 1500 MVA per circuit. 
SEPS and MAVIR consider a new interconnection between SK and HU 
(starting from Gabčíkovo substation - SK) and a connection to the existing 
400kV tie-line Györ/Szombathely (HU) - Vienna/Sarasdorf (AT) on 
Hungarian side.  
New 350km 500MW HVDC line between Tunisia and Italy via Sicily with 
400kV DC subsea cable and converters stations at both ends. 
Nemo project: new DC sea link including 135km of 250kV DC subsea cable 
with 1000MW capacity. 
 New 1290MW HVDC bipolar installation including 260km of 450kV DC 
subsea cable.  

PL-UA 

RO-MO 

RO-TR 

RS-MK 

RS-MK 

RS-RO 

SI-HU-
HR 

SI-IT 

SK-AT-
HU 

TU-IT 

UK-BE 

UK-NL 

* Commission estimation of length 

upgrade of 
existing 
lines 

new lines 

new lines 

new lines 

new lines 

new lines 

430* 

145 

400 

220 

85 

150 

new lines 

80 

new lines 

120 

new lines 

30* 

new lines 

new lines 

new lines 

350 

135 

260 

103

 
 
Table 15: New gas infrastructure realised between 2000 and 2011 

Inauguration / 
start of 
operations 
2006 
2011  
2011 
2010 
2010 

2009 
2010 
2009 
2011 
2005 
2010 
2003 
2003 
2006 
2007 

March 2011 
2011  
2006 
2005 

New interconnectors 

TEN-E / EEPR support (in 
Million Euro) 

BBL (UK-BE)*  
OPAL DE-CZ* 
PL-CZ 
HU-HR 
RO-HU 
New LNG Terminals 
Dragon LNG Terminal* 
South Hook LNG Terminal* 
North Adriatic LNG Terminal (Rovigo)* 
Gate LNG Terminal Rotterdam* 
Grain LNG Terminal NCG* 
Fos-Cavau 
Sines 
Bilbao 
Sagunto 
Mugardos 
New import pipelines 
Medgaz (Algeria-Spain) 
Nord Stream (Russia-Germany) 
Langeled (Norway-UK) 
Greenstream (Libya-Italy) 

Storages developed since 2008 

- 
- 
14 
20 
16.6 

- 
- 
- 
- 
- 
- 
0.9 
- 
- 
- 

2  
- 
- 
- 

TEN-E support not specified 
as country approach 

AT 
AT, DK, FR, DE, IT, ES 

January 2007 
June 2008  
February 2009  AT, DK, FR, DE, IT, ES, UK 
January 2010 
* Exemption obtained 

AT, BE, CZ, DK, FR, DE, HU, IT, ES, UK 

Source: GLE Investment database 2010; GSE Investment database 2008-2010; ENTSOG TYNDP 
2011; European Commission DG Energy, 2011. 

104

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure 19: Gas storage investments in selected Member States between 2007 and 2010 

20000

15000

m
c
M

10000

5000

0

AUSTRIA

BELGIUM

CZECH REPUBLIC
BULGARIA
DENMARK

FRANCE

GERMANY

HUNGARY

ITALY

LATVIA
NETHERLANDS
LITHUANIA

POLAND

PORTUGAL

ROMANIA

Source: GSE 

Figure 20: Gas storages developed in selected Member States since 2008 

m
c
M

1800

1600

1400

1200

1000

800

600

400

200

0

SERBIA

SPAIN UK

Jul-07
Jan-08
Jun-08
Feb-09
Jan-10

Jan-08
Jun-08
Feb-09
Jan-10

AUSTRIA

BELGIUM

CZECH REPUBLIC
BULGARIA

DENMARK

Source: GSE 

POLAND

PORTUGAL

ROMANIA

SERBIA

SPAIN UK

FRANCE

GERMANY

HUNGARY

ITALY

LATVIA

NETHERLANDS
LITHUANIA

105

 
 
 
 
 
 
Table 16: Aggregates of cost estimates for gas TYNDP 2011-2020 

Infrastructure type 

Number of 
projects 

Aggregate Cost 
Estimate for 
infrastructure 
investment (in €10^6) 

Remarks 

Some projects missing 
from the estimate, see 
below for more detailed 
information 

Some projects missing 
from the estimate, see 
below for more detailed 
information 

Some projects missing 
from the estimate, see 
below for more detailed 
information 

Transmission projects – 
FID 

62 

Storage projects – FID 

26 

LNG projects – FID 

Transmission projects – 
Non-FID 

Storage projects – Non-
FID 

LNG projects – Non-
FID 

11 

97 

22 

20 

Subtotal FID projects 

Subtotal Non-FID 
projects 

TOTAL 

99 

139 

238 

Source: ENTSOG TYNDP 2011 

13,711 

4,260  

3,570 

58,556 

2,593 

6,614 

21,514  

67,763 

89,304 

106

 
 
 
 
 
 
 
 
 
 
 
 
 
 
Figure  21:  Past  (2005-2009)  and  planned  future  (2010-2020)  TSO  investments:  operators' 
perspective 

Source: Roland Berger, 2011 

Figure 22: Past (1995-2009) and planned future (2010-2020) investments for selected electricity 
TSOs in Europe (EUR bn per year) 

Source: Roland Berger, 2011 

107

 
 
 
 
 
 
Figure 23: Past (2005-2009) and planned future (2010-2020) investments for natural gas 
TSOs in Europe by region (EUR bn per year) 

Source: Roland Berger 

108

 
 
 
Figure 24: ENTSO-E analysis of main electricity transmission bottlenecks up to 2020 

Source: ENTSO-E 2011 (preliminary analysis) 

NB.: Arrows do not represent any projects, but only show the direction of main power flows. 

109

 
 
 
 
 
 
Figure 25: Main gas transmission capacity reinforcement needs for 2015 and 2020 as identified 
by ENTSOG (scenario analysis "security of supply") 

Source: ENTSO-G, TYNDP 2011 

110

 
 
 
 
ANNEX 16 
EVALUATION OF SUBOPTIONS WITH REGARD TO PERMIT GRANTING AND PUBLIC 
CONSULTATION 

Element A.2.1 Organisation of the permit granting process 

Suboption  A.2.1.a:  Leading  Authority  without  decision-making  power  at  national  level  (“light 
one-stop shop”) 

Assessment of effectiveness 
Since the Leading Authority is not entitled to take the final administrative decision it is expected that 
the lack of managerial authority and final responsibility will not allow the Leading Authority to drive 
the entire process significantly forward. Effectiveness is expected to be limited as multiple procedures 
and permits implying double work and friction losses would continue to exist. In some countries with 
federal structures, such as Germany and Austria, the Leading Authority would constitute an additional 
layer,  as  coordination  (and  decision-making)  competence  would  remain  with  multiple  institutions  at 
federal state level. 

Assessment of feasibility – legal implications in MS 
A slight adaptation of national legislation may be necessary in MS where a “one-stop shop”-approach 
is  not  in  place,  as  coordination  tasks  may  have  to  be  (re)assigned.    However,  the  overall  permitting 
framework would not need to be modified and the competences of other authorities concerned would 
not be affected by these measures. 

Assessment of proportionality 
This  suboption  is  considered  to  be  in  line  with  the  principle  of  proportionality  as  planning  and 
decision-making  competence  would  be  entirely  left  to  the  MS  concerned,  and  MS  would  not  be 
obliged to adapt their existing permitting framework. 

Suboption A.2.1.b: Leading Authority with decision-making power at national level (“full one-
stop shop”) 

Assessment of effectiveness 
Effectiveness  is  expected  to  be  significant  if  a  full  one-stop  shop  with  decision-making  power  is 
established  at  national  level  in  each  MS.  The  Leading  Authority  would  through  its  responsibility  to 
take the final decision have the managerial power to effectively streamline and reduce the complexity 
of the process. The number of interfaces would be reduced for the project promoter and concentrated 
within  one  authority,  such  that  information  losses  and  double  work  can  be  prevented.  Since  the 
Leading Authority has been involved in the operational handling of the procedure it would be able to 
take an informed decision if required, if needed with support of external expertise. This is expected to 
have positive effects on the duration of the overall permitting process. In the Netherlands for instance, 
the  one-stop  shop  as  main  feature  of  the  new  permitting  regime  has  resulted  in  the  reduction  of  the 
entire  process  from  an  average  of  10-15  years  to  6  years  (including  realisation  of  about  2  years), 
whereas  in  some  other  countries  where  loose  coordination  mechanisms  such  as  under  suboption 
A.2.1.b exist, procedures take on average more than 8 years. Table 17 shows that in countries where a 
full  one-stop  shop  exists,  the  duration  of  the  permitting  process  tends  to  be  shorter.  In  terms  of 
compliance  and  administrative  costs,  this  suboption  is  expected  to  be  more  cost-effective  than 
suboption A.2.1.a, if a coordinated approach is chosen. The administrative structures and thus the need 
for adaptation of national legislation, i.e. compliance costs, would be similar under both suboptions, in 
that  responsibility  would  have  to  be  allocated  to  the  Leading  Authority.  However,  under  this 
suboption,  the  Leading  Authority  could  take  a  final  decision,  avoid  delays,  and  thereby  reduce 
administrative  costs  spent  on  handling  the  procedures.  It  would  not  only  have  an  impact  on 
administrative costs, but also reduce the foregone losses due to the missing infrastructure. In general, it 

111

 
 
 
 
 
 
 
 
 
should be noted that the costs related to the introduction of these measures are minor compared to the 
costs imposed on society as a whole if the infrastructure is not built on time. 

Assessment of feasibility – legal implications in MS 
Adaptation  of  national  legislation  may  be  extensive  for  this  suboption  if  full  responsibility  for 
decision-making is chosen to be (re)assigned, and a wide range of laws can, depending on the MS and 
the  legislation  in  place,  be  concerned.  The  more  fragmented  the  process  is,  the  more  adaptation  of 
national legislation is expected to be necessary. However, the need for adaption is expected to be less 
significant  if authorities  involved in  the  process  retain  their  competences  and  the  Leading Authority 
only steps in case of duly justified reasons. Feasibility of this suboption has been proved in those MS 
where full-one-stops with integrated procedures have been established, such as in the Netherlands, the 
UK, Italy etc. as legal requirements in terms of environmental and other procedures are fully respected 
in these MS. Respect of requirements in place is inherent to the permit granting process as authorities 
have to ensure that permits can withstand judicial reviews. 

Assessment of proportionality 
This suboption is considered to be in line with the principle of proportionality, as MS would be free to 
choose and establish their competent authority by a target date, and as decision-making and planning 
competence would be entirely left to the MS concerned. Further, since this suboption leaves flexibility 
to  the  MS  to  decide  whether  competent  authorities  retain  their  competences,  the  requirements  to 
modify  the  permitting  process  are  limited.  These  measures  are  broad  in  nature,  establishing  a 
framework within which MS can carry out the procedures according to the national specificities. 

Suboption  A.2.1.c:  Cross-border  Leading  Authority  ("light  one-stop  shop")  with  European 
Authority of Last Resort and European permitting procedure 

Assessment of effectiveness 
This suboption is not considered viable. A cross-border Coordinating Authority will have difficulties 
in reaching the “critical mass” and develop the expertise needed, as for most individual cross-border 
projects a new authority would have to be established (each cross-border project may involve different 
countries),  and  new  staff  of  each  of  the  MS  involved  would  have  to  be  assigned  each  time  as  staff 
from  one  MS  may  not  be  familiar  with  language  and  procedures  of  another  MS.  For  a  European 
Authority of Last Resort, an entirely new procedure would need to be established, and EU staff does 
currently not have the necessary expertise. Although this expertise may be developed and/or possibly 
subcontracted,  in  accordance  with  a  new  European  permitting  procedure,  suboption  A.2.1.b  is 
expected to deliver at least the same or better results in a more timely fashion. 

Assessment of feasibility – legal implications in MS 
Adaptation  of  national  legislation  is  expected  to  be  necessary.  Coordination  competences  for  PCI 
would  have  to  be  assigned  to  a  new  authority.  However,  adaptation  is  expected  to  be  limited  as 
national  authorities  would  keep  their  decision-making  competences  if  the  time  limit  is  respected.  In 
order to establish the Authority of Last Resort at European level and a European permitting procedure, 
adaptation of national legislation is not expected to be necessary. 

Assessment of proportionality 
Both elements of this suboption – the cross-border Leading Authority and the European Authority of 
Last Resort – do not leave competences at most appropriate level. It is expected this suboption would 
exceed  what  is  necessary  to  achieve  the  objectives,  such  that  this  provision  is  not  in  line  with  the 
principle of proportionality. 

Resulting from this analysis, A.2.1.b is the most preferred suboption. 

112

 
 
 
 
 
 
 
 
 
 
 
 
Element A.2.2 Limitation in time of the permit granting process  

Suboption A.2.2.a: Requirement for Member States to establish time limits for each individual 
PCI 

Assessment of effectiveness 
Effectiveness of this suboption is expected to be limited in most Member States. Although individual 
time limits would make it possible to take into account the national specificities of the varying permit 
granting processes, and the different degrees of complexity of projects, experience has shown that time 
limits without legal consequences in case of their expiry are relatively ineffective. In the context of the 
public consultations carried out, Member States were generally supporting the idea of individual time 
limits, however respondents across stakeholder groups, including Member States, raised the issue of 
consequences in case of expiry. Time limits would only be effective in Member States where certain 
sanction mechanisms exist, such as the deferral of the decision to a higher level. The EU would not 
have any means to apply any sanctions, as the legal grounds to do so would not exist. 

Assessment of feasibility – legal implications in MS 
This  option  would  have  limited  implications  on  Member  States’  procedural  law.  In  some  Member 
States,  legislation  would need  to  be  adapted  to  allow  the  Competent  Authority  to  set  time  limits,  or 
general time frames could be introduced by law, based on which the Competent Authority would act. 

Assessment of subsidiarity and proportionality 
As this option leaves substantial flexibility to Member States in defining time limits, it is considered to 
be in line with the principle of subsidiarity and proportionality.   

Suboption A.2.2.b: Legally-binding time limits established by stakeholders in the framework of 
the regional fora 

Assessment of effectiveness 
Effectiveness  of  this  suboption  is  expected  to  be  limited  as  implementation  would  be  difficult. 
Although the "ownership" of the decision on a legally-binding time limit is expected to have positive 
effects  on  its  acceptance  and  could  accommodate  the  complexities  of  each  individual  project, 
experience  with  working  groups  in  regional  fora  and  consultation  of  MS  involved  have  shown  that 
discussions  within  these  groups  are  lengthy  and  consensus  difficult  to  achieve.  Although  some 
Member States have expressed their support to such idea, those which have been involved in existing 
regional  fora  opposed  this  option  as  too  cumbersome.  Even  if  consensus  is  found,  a  legally-binding 
time limit can only be established through an intergovernmental agreement, whose signature by Heads 
of State would require additional resources and time. 

Assessment of feasibility – legal implications in MS 
Adaptation of national legislation would not be necessary under this suboption as intergovernmental 
agreements as the legal basis would be elaborated for a given PCI. 

Assessment of subsidiarity and proportionality 
As this suboption leaves the definition of legally-binding time limits to the MS affected, this suboption 
is considered to be in line with the principle of proportionality. 

Suboption A.2.2.c: Legally-binding time limit established by the EU legislative act 

Assessment of effectiveness 
This suboption is considered to have significant effects on the duration of the permit granting process. 
Legally-binding time limits are crucial to incentivise promoters and authorities to complete the permit 
granting process in a timely fashion, and for sanction mechanisms to kick in at EU level if considered 
appropriate and justified. As mentioned above, an issue raised in the context of the public consultation 
carried  out  was  the  consequences  if  a  time  limit  expires.  Possibilities  identified  were  the  automatic 

113

 
 
 
 
 
 
 
 
 
 
 
approval or rejection of the project. However, this is considered as a non-viable option, such that other 
mechanisms to sanction the expiry of a time limit should apply. The definition of time limits under the 
legislative  act  would  create  the  legal  grounds  for  the  EU  to  apply  sanctions,  which  are,  across 
stakeholder  groups,  considered  as  crucial  to  enforce  time  limits.  This  suboption  would  be  without 
prejudice  to  the  time  limits  established  for  the  statutory  permit  granting  process  in  some  MS  which 
are, according to the analysis carried out, shorter in duration, thus not creating any adverse incentives. 
Further, Leading Authorities are free to identify individual time limits for the different stages of the 
project by elaborating a permit granting schedule for a given PCI. The Leading Authority's decision-
making  power  at  national  level  constitutes  an  additional  effective  enforcement  mechanism  if  other 
competent authorities involved in the process do not issue the required permits on time. 

A  two-step  approach  has  been  identified  as  most  effective  to  achieve  the  timely  delivery  of 
infrastructure investments, addressing both promoters and authorities. A one year time limit would be 
established for the statutory permitting procedure for which the competent authorities are responsible, 
notably  from  the  acceptance  of  the  submitted  documents  until  the  final  administrative  decision  is 
taken. However, this one year time limit would not take into account the significant efforts needed for 
the  preparation  of  application  documents  for  which  the  project  promoter  is  responsible  nor 
administrative  procedures  which  do  not  result  in  a  legally-binding  permit  (such  as  spatial  planning 
procedures  and  public  debates).  Further,  it  would  not  incentivise  the  authorities  to  reduce  delays 
between the submission of application documents by the promoter and the acceptance of these by the 
authorities,  which  is  a  challenge  in  some  MS  where  time  limits  for  (part  of)  the  official  permitting 
procedure  are  defined,  but  where  authorities  postpone  the  acceptance  of  documents  to  gain  time.  A 
three years time limit would therefore be established to accommodate time consuming pre-application 
efforts.  Respecting  the  fact  that  delays  may  be  caused  by  promoters  and/or  authorities  and  that 
unforeseen external factors may influence the process, discretionary margin is left to the Commission 
at  what  point  and  in  which  form  sanction  mechanisms  (reporting,  withdrawal  of  financial  support, 
infringement procedures) are applied. 

Assessment of feasibility – legal implications in MS 
Under  this  suboption,  no  major  adaptation  of  national  legislation  is  expected  to  be  necessary. 
According to the analysis carried out, a one year time limit for the statutory administrative procedure 
exceeds  the  time  limit  established  by  legislation  (in  MS  where  these  are  defined).  Legally-binding 
time  limits  for  pre-application  efforts  are  usually  only  established  for  individual  steps  of  the 
procedure, such that these can be well-accommodated by the overall time limit. 

Assessment of subsidiarity and proportionality 
During  public  and  stakeholder  consultations  (mainly)  Member  States  were  raising  the  issue  of 
subsidiarity and advocated that time limits should be set at national level. Some Member States stated 
that EU measures should not prevent them to take more ambitious action. 
This suboptions would take account of the concerns raised by the Member States, as they may define 
their  individual  time  limits  for  the  overall  procedure,  whose  ambitions  may  exceed  those  set  by  the 
legislative act, and establish individual target durations for the different steps of the procedure, thereby 
respecting the principle of setting broad measures, leaving the individual steps in the procedure to the 
MS.  The  time  limit  set  by  the  legislative  act  would  well  accommodate  the  time  needed  to  carry  out 
public consultations, which usually have a duration of 4-8 weeks. The time needed for environmental 
assessments can also be well integrated. As concluded by a study, an EIA decision takes less than one 
year from the moment of notification of the project until the final decision is taken. No major changes 
of procedural law are, as explained above, considered necessary, such that this option is considered in 
line with the principle of proportionality and subsidiarity. 

Resulting from this analysis, A.2.2.b is the most preferred suboption. 

114

 
 
 
 
 
 
Table 17: Summary of impacts 

Suboption 

Effectiveness 

Legal implications 

Proportionality 

Overall 
evaluation

A.2.1.a – light 
one-stop shop 

A.2.1.b – full 
one-stop shop 

A.2.1.c – 
Cross-border 
coordination 
with 
European 
ALR 

0 limited 
effectiveness as no 
decision-making 
competence 

++ strong 
effectiveness as 
decision-making 
competence can drive 
procedure forward, 
reduced complexity 

- low effectiveness 
due to insufficient 
expertise cross-border 
and at EU level 

+ light adaptation of 
national legislation if 
assigned to existing 
institution 
0 moderate adaptation 
of national legislation 
if authorities continue 
to issue draft permits 
and if responsibilities 
are assigned to an 
existing institution 

0 moderate adaptation 
of national legislation 
for cross-border 
component, for ALR 
EU legislation 

Y coordination and 
decision-making 
competence at MS 
level 

Y coordination and 
decision-making at 
MS level 

N coordination and 
decision making at 
regional/EU level 

Suboption 

Effectiveness 

Legal implications 

Proportionality 

0 

++ 

- -  

Overall 
evaluation 
- 

intergovernmental 
be 

0 
agreements 
signed 

to 

Y  MS  are  free  to 
on 
agree 
individual 
time 
limits 

time 

A.2.2.a: 
Legally-
binding 
limits 
established  by 
stakeholders  in 
the  framework 
of  the  regional 
initiatives 
Suboption 
A.2.2.b: 
Legally-
time 
binding 
limit  of  4  years 
established  by 
the 
EU 
legislative act 

-  limited  effectiveness  
as joint agreements on 
legally-binding 
target 
durations  are  difficult 
to  achieve  and  entail 
additional procedures 

++ 
strong 
effectiveness  with  full 
one-stop 
shop. 
Precondition  to  apply 
adequate 
sanction 
mechanisms  at  EU 
level. 

++  no 
expected 
necessary 

adaptations 
be 

to 

++ 

Y  MS  are  free  to 
set more ambitious 
time  limits  for  the 
overall  procedure 
as  well 
to 
define  time  limits 
individual 
for 
the 
in 
steps 
process 

as 

115

 
 
 
 
ANNEX 17 
CHALLENGES AND CORRESPONDING MEASURES PROPOSED 
FOR PERMIT GRANTING AND PUBLIC INVOLVEMENT 

Problems related to different phases of the process 

Phase B 
Complex and fragmented process 

Phase C 

Phase D 

Lack 
coordination 

of 

upfront 

planning 

and 

Lack of time limits/ long duration 

Unclear 
documentation 
standards  and  lack 
of quality 
Flexibility of environmental legislation 

Objections of citizens 

s
s
e
c
o
r
p
e
v
i
t
a
r
t
s
i
n
i
m
d
a

t
n
e
i
c
i
f
f
e
n
I

n
o
i
t
a
l

u
p
o
p
d
e
t
c
e
f
f
a

f
o
n
o
i
t
i
s
o
p
p
O

Proposed solutions 
 for improvement 

the 

shop, 

activities 

including 
to  coordinate  and 

One-stop 
obligation 
control the process 
One-stop  shop,  particularly  the 
obligation to elaborate a  permit 
granting  schedule,  to  handle 
consultation procedures, and to 
carry out scoping activities 
Legally-binding  overall 
time 
together  with  sanction 
limit, 
mechanisms 
time 
to  enforce 
limits  (infringements,  reporting), 
and  the  obligation  of  the  one-
stop shop to control the process, 
based  on  a  permit  granting 
schedule 
to  carry  out 
One-stop  shop 
and 
scoping 
coordinate  with  other  authorities 
concerned 
Granting  of 
status  of 
imperative  public  overriding 
the 
to  ensure 
interest 
decision  about  the  necessity  to 
build  a  project,  decided  by 
Member  States 
the 
selection  process,  cannot  be 
reversed  by  an  authority  later  in 
the process 
One-stop  shop  responsible  to 
handle  consultation  procedures 
according to principles set by the 
legislative  act,  including  early 
consultation  before  submission 
of  application  files,  and  to  issue 
transparency  guidelines.  Time 
frame 
3+1 
as 
leave  substantial 
approach 
and 
promoters 
time 
authorities  to  consult  the  public 
before decisions are taken. To be 
accompanied  by  best-practice 
sharing  and  communication 
campaigns.  

established 

during 

that 

for 

to 

Appeals to courts  Early 

consultation 

before 

116

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Lengthy negotiations with landowners 

submission  of  application  for 
better  consensus  with  citizens. 
No  legal  measure  with  regard  to 
judicial  procedures  proposed,  as 
line  with 
not  considered 
in 
subsidiarity. 
Best-practice 
sharing  and  communication 
campaigns. 
before 
consultation 
Early 
submission  of  application  for 
consensus  with  landowners.  No 
legal  measure  proposed,  as  not 
line  with 
in 
considered 
subsidiarity. 
Best-practice 
sharing  and  communication 
campaigns. 

117

 
 
 
 
 
ANNEX 18 
ADMINISTRATIVE COST ASSESSMENT 

Introduction 

This administrative cost assessment analyses the most important changes under each policy option. In 
line  with  the  principle  of  proportionate  analysis,  a  quantitative  analysis  was  carried  out  for  the 
measures entailing relatively significant impacts on administrative costs, notably the establishment of 
a  regime  of  common  European  Interest,  as  well  as  the  introduction  of  a  one-stop  shop  approach.  It 
should  however  be  noted  that  the  policy  proposal  does  not  aim  at  the  reduction  of  administrative 
burden as such, but at making the realisation of energy infrastructure happen by increasing certainty 
for  investors,  with  all  consequences  this  entails  on  security  of  supply,  market  integration  and  the 
deployment of renewable energy.  

Methodology 

In  a  first  step,  a  number  of  Member  States  was  identified  in  which  a  reorganisation  of  the  permit 
granting regime similar to the proposal subject to this impact assessment has been carried out, notably 
the Netherlands, Germany (at federal state level), the UK, and Ireland. 
In a second step, a detailed questionnaire was elaborated, aiming at 

a)  Identifying the different activities related to the main stages of the permitting process, 
b)  Capturing the resources spent on these activities based on a reference project, 
c)  Comparing  the  results  of  a)  and  b)  before  and  after  the  reorganisation  of  the  permitting 

process. 

The questionnaires and/or a request for any other information available, such  as impact assessments 
carried out at national level, were sent to the "one-stop shop" authority as well as to the TSO(s) in the 
respective MS. 

However, most of the respondents answered that the due to the complexity of such processes, the fact 
that projects vary widely with regard to their complexity, and that several projects are handled at the 
same time by a large number of people, it was not possible to give such detailed information. Partial 
data was made available by a German TSO as well as a German authority at federal state level on the 
existing  regimes,  and  individual  interviews  were  subsequently  held  with  some  TSOs  to  give  some 
rough estimations on potential savings through the establishment  of a national one-stop shop. These 
were  used  as  assumptions  in  the  below  calculations,  which  give  a  relatively  good  estimate  on  the 
administrative  costs  incurred  in  a  permit  granting  process  for  a  large-scale  energy  infrastructure 
project. It should be noted that due to the lack of complete and detailed data, only some features of the 
EU Standard Cost Model131 could be applied. 

Assumptions 

-  Measures proposed are implemented by none of the MS. 
-  Two  responsible  authorities132  are  involved  in  the  permit  granting  process  (conservative 
assumption).  Coordinating  and  decision-making  competence  would  be  allocated  to  one  of 
these. 

-  No impacts on the other authorities involved at local or technical level, as it is assumed that 
they  will  continue  to  issue  permits/opinions  such  that  these  impacts  are  not  taken  into 
account133. 

-  Policy option A.1: acceleration of procedures by three months. Staff subsequently working for 
1,5 months on the procedures at promoters' and on authorities' side, with equal distribution of 

132  

133  

Authority  responsible  to  issue  a  legally-binding  permit,  concentrating  parts  of  the  procedure  regionally  or 
technically 
Exception Austria where one-stop shops at federal state level exist – not specifically taken into account. 

118

 
 
 
 
 
 
 
                                                 
 
work  load  over  the  project,  and  50%  impact  on  authorities'  side  (calculations  based  on  data 
sent  by  respondents:  on  promoters'  side  savings  of  820  person-hours;  on  authorities'  side 
savings  of  725  person-hours).  Possible  impacts  on  litigation  processes  are  not  taken  into 
account in these calculations, as these will not be subject to the legislative act. 

-  Policy option A.2: 25% reduction of resources for the TSO if a one-stop shop at national level 
was established (interviews with TSOs and Impact Assessment UK134), and 34% reduction of 
resources  on 
(Commission's  calculations  based  on  activities 
communicated). 

the  authorities'  side 

-  Labour  costs:  simple  average  of  labour  costs  for  the  category  "professionals"  based  on 
standardised  ESTAT  data  (four-yearly  Labour  cost  survey  and  the  annual  updates  of  labour 
costs  statistics,  covering  both  wages  and  non-wage  labour  costs,  reflecting  2006  prices  and 
25% overhead costs)135. 

134  

135  

UK  Department  for  Communities  and  Local  Government,  "Localism  Bill:  major  infrastructure  projects,  Impact 
assessment", 2011. 
Source: 
20earnings%20per%20hour%20in%2027%20MS.xls  

http://adminburden.sg.cec.eu.int/Manuals%20and%20documentation/080115_FINAL%20tariffs_gross% 

119

 
 
 
                                                 
Table 18: Results of the administrative cost assessment 

Business as usual 

Policy options A.1 - A.3 

Time 
spent 
(hours) 

Labour 
costs (€ 
per 
hour)* 

Number 
of 
projects 
(2014-
2010)** 

Total 
adminis-
trative costs 
in € (BAU) 

Total 
adminis-
trative costs 
(PO A.1) 

Change 
in 
percent 
(compa
red to 
BAU)  

Total 
adminis-
trative costs 
(PO A.2)  

Reduction in 
percent 
(compared to 
BAU)  

Total 
adminis-
trative costs 
(PO A.3) 

Reduction 
in percent 
(compared 
to BAU) 

111.367.476 

-0,03 

85.889.975 

-0,25 

82.737.485 

-0,28 

19.508 

25,63 

150 

74.998.506 

10.280 

25,63 

150 

39.521.460 

29.788 

114.519.966 

64 

96 

25,63 

25,63 

150 

150 

246.048 

369.072 

240 

25,63 

150 

922.680 

112 

25,63 

150 

430.584 

19.787.642 

-0,12 

15.012.311 

-0,34 

12.225.049 

-0,46 

2.480 

25,63 

150 

9.534.360 

2.880 

25,63 

150 

11.072.160 

5.872 

137.094.870 

22.574.904 

131.155.118 

-0,05 

100.902.286 

-0,26 

94.962.533 

-0,31 

Target 
group 

Type of 
obligation 

Promoter 

Securing 
necessary 
permits 

Authority 

Issuing 
necessary 
permits 

Total 
(2014-20) 
*Figures are not discounted

Description 
of activity 
Preparation 
of 
application  
Other 
related 
activities 
Total 
Pre-planning 
activities 
Scoping 

Checking of 
submitted 
documents 
Coordinatio
n with other 
authorities 
involved 

Public 
consultation 

Elaboration 
of the permit 
Total  

120

 
 
 
 
 
 
 
 
 
Remarks on results 

It  should  be  noted  that  these  results  are  based  on  the  relatively  conservative  assumption  that  two 
authorities are responsible for the permit granting process under BAU, which are coordinating other 
technical, regional and/or local authorities and stakeholders involved. However, this is only one type 
of permitting regime existing in the different MS. Impacts would be greater if there were, as it is in 
many  MS  the  case,  more  responsible  authorities,  or  if  the  responsible  authority  was  not  or  only 
partially  coordinating  other  authorities  and  stakeholders  involved.  In  the  latter  case,  a  shift  of 
administrative  costs  from  promoter  towards  authority  is  expected.  However,  according  to  the  data 
available,  in  terms  of  pure  coordinative  activities  such  as  telephone  conversations,  e-mails  and 
meetings,  this  shift  would  not  account  for  more  than  2%,  as  more  inefficiences  are  related  to  the 
duplication  of  efforts  in  the  preparation  and  assessment  of  application  files,  and  as  half  of  these 
coordinative activities would still have to be pursued by the promoter, given that technical details need 
to be discussed directly. Shifts of administrative costs are also expected towards the Leading Authority 
from other responsible authorities. These are expected to be limited if the MS chooses to implement 
the coordinated approach.  

In order to compare the numbers with the figures available in MS, where such an approach has already 
been implemented, the below table shows the reduction in full time equivalents (FTE) per year. 

Running  costs  promoter  (per 
project) 
Running  costs  authority  (per 
project) 

Old regime (BAU) 
14.9 

New regime (PO A.3)  
10.7 

2.9 

1.6 

On the promoters' side, figures are in line with estimations made by one promoter where a one-stop 
shop approach has been introduced: 11 employees are working on one project (external contracts not 
taken into account). On the authorities' side, the UK with an integrated permit granting regime, where 
all  necessary  expertise  and  decision-making  power  is  with  the  Leading  Authority,  has  a  ratio  of  1.9 
employees per project (94 employees for 50 projects), in line with the Commission's estimations. In 
the Netherlands however, a ratio of 0.5 employees per project has been estimated. Here, a coordinated 
approach  has  been  implemented,  where  expertise  and  decision-making  power  is  mainly  left  to  the 
other authorities involved, such that less resources at the level of the Leading Authority (20 people, 44 
projects) is needed. 

121

 
 
 
 
 
 
 
ANNEX 19 
IMPACT OF A 2% EQUITY ADDER ON TRANSMISSION TARIFFS 

transmission cost as
% of electricity tariff

Selected Countries

Denmark

Lithuania

Poland

France

Sweden

Greece

15%

10%

5%

Time

14,6%

11,5%

10,0%

7,4%

3,6%

2,1%

now

Source: Roland Berger, European Commission 

+ 0,5% / 0,07 c/kWh

+ 0,9 % / 0,07 c/kWh

+ 0,2 % / 0,02 c/kWh

+ 0,2 % / 0,02 c/kWh

+ 0,1 % / 0,01 c/kWh

+ 0,3 % / 0,03 c/kWh

15,1%

12,4%

10,2%

7,6%

3,7%

2,4%

After 10
years

equity share of 30 % for future investments 

Main assumptions: 
− 
−  2 % additional annual revenue on equity 
−  other costs constant 
− 

transmission tariff averaged for households and industry (excluding VAT). 

122