COMMISSION STAFF WORKING DOCUMENT   IMPACT ASSESSMENT Accompanying document to the   COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL COMMITTEE AND THE COMMITTEE OF THE REGIONS   Energy infrastructure priorities for 2020 and beyond -  A Blueprint for an integrated European energy network    {COM(2010) 677 final} {SEC(2010) 1396 final}
Date: 2010-11-17
Institutions: European Commission
Subjects: energy policy, energy supply, environmental protection, security of supply, trans-European network

EN 

EN 

EN 

 
 
EUROPEAN COMMISSION 

Brussels, 17.11.2010 
SEC(2010) 1395 final 

COMMISSION STAFF WORKING DOCUMENT 

IMPACT ASSESSMENT  

Accompanying document to the 

COMMUNICATION FROM THE COMMISSION TO THE EUROPEAN 
PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL 
COMMITTEE AND THE COMMITTEE OF THE REGIONS 

Energy infrastructure priorities for 2020 and beyond -  
A Blueprint for an integrated European energy network 

{COM(2010) 677 final} 
{SEC(2010) 1396 final} 

EN 

EN 

 
 
 
  
 
 
 
 
 
 
 
 
 
 
TABLE OF CONTENTS 

Table of contents......................................................................................................................0 

Glossary ...................................................................................................................................3 

1.  Procedural issues and consultation of interested parties .................................................5 

1.1.  Green paper and public consultation ........................................................................6 
1.2.  Stakeholder consultations.........................................................................................7 

2.  Problem definition.............................................................................................................8 

2.1.  A dramatically changed policy context......................................................................8 
2.2.  Current TEN-E framework and European Energy Plan for Recovery.......................9 
2.3.  Main problems ........................................................................................................10 
2.4.  Baseline scenario ...................................................................................................14 
Energy trends and infrastructure needs..........................................................17 
Infrastructure delivery under current market, regulatory and financing 
conditions........................................................................................................22 
2.5.  Main geographical bottlenecks ...............................................................................24 
2.6.  Key players and affected population.......................................................................26 
2.7.  EU right to act .........................................................................................................26 

2.4.1. 
2.4.2. 

3.  Objectives.......................................................................................................................27 

4.  Policy options .................................................................................................................28 

4.1.  Policy area A: Scope of policy instrument ..............................................................29 
4.2.  Policy area B: Design of policy instrument .............................................................29 
4.3.  Policy area C: Coordination ....................................................................................30 
4.4.  Policy area D: Permitting ........................................................................................31 

5.  Analysis of impacts.........................................................................................................32 

5.1.  Baseline ("business as usual") ...............................................................................32 
5.2.  Policy area A: Scope of policy instrument ..............................................................38 
5.3.  Policy area B: Design of policy instrument .............................................................38 
5.4.  Policy area C: Coordination ....................................................................................39 
5.5.  Policy area D: Permitting ........................................................................................39 

6.  Comparison of policy options and conclusion ................................................................41 

7.  Monitoring and evaluation ..............................................................................................44 

Annex 1: Electricity transmission capacity increases for the period 2010-2015 and 2015-2025
...............................................................................................................................................46 

Annex 2: Current financing of TEN-E projects .......................................................................47 

Annex 3: E3ME modelling scenarios and results ...................................................................48 

Annex 4: Design options for an integrated offshore grid ........................................................53 

2

 
 
 
 
GLOSSARY 

Alternating Current 

Agency for the Cooperation of Energy Regulators 

Business As Usual 

Baltic Energy Market Interconnection Plan 

Carbon Capture and Storage 

Compressed Natural Gas 

Commission de Régulation de l'Energie (National Regulatory Authority 

in France) 

Direct Current 

European Bank for Reconstruction and Development 

Environmental Impact Assessment 

European Energy Plan for Recovery 

European Energy Security and Infrastructure Instrument 

European Investment Bank 

Energy Infrastructure Package 

European Neighbourhood and Partnership Instrument 

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 

European Union 

Gross Domestic Product 

Giga Watt 

Information and Communication Technology 

AC 

ACER  

BAU 

BEMIP 

CCS 

CNG 

CRE 

DC 

EBRD  

EIA 

EEPR   

EESII   

EIB 

EIP 

ENPI 

ENTSO-E 

ENTSOG 

ERGEG 

ETS 

EU 

GDP 

GW 

ICT  

INOGATE 

European Union programme supporting international cooperation 

between the EU, the littoral states of the Black and Caspian Seas and 

IPA 

LNG 

Mtoe 

NGO 

their neighbouring countries 

Instrument for Pre-Accession Assistance 

Liquefied Natural Gas 

Million tons of oil equivalent 

Non-Governmental Organisation 

3

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
NIF 

NSCOGI 

OFGEM 

PEI 

RES 

SME 

TEN-E  

TFEU   

TSO 

TWh 

TYNDP 

UPS 

Neighbourhood Investment Facility 

North Sea Countries Offshore Grid Initiative 

Office of Gas and Electricity Markets (National Regulatory Authority 

in the UK) 

Project of European Interest 

Renewable Energy Sources 

Small and Medium Enterprises 

Trans-European Networks for Energy 

Treaty on the Functioning of the European Union 

Transmission System Operators 

Tera Watt hour 

Ten-Year Network Development Plan 

Unified Power System (synchronised power system currently covering 

Russia and the three Baltic States) 

VSC 

Voltage Source Converter (technology to improve overall system 

performance for both high voltage alternating current and direct current 

transmission) 

4

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
1. 

PROCEDURAL ISSUES AND CONSULTATION OF INTERESTED PARTIES 

Lead DG: ENER 

Services  involved  in  the  Interservice  Group:  AGRI,  AIDCO,  BEPA,  BUDG,  CLIMA,  COMP, 
DEV,  ECFIN,  ELARG,  ENTR,  ENV,  ESTAT,  INFSO,  JLS,  JRC,  MARE,  MARKT,  MOVE 
REGIO, RELEX, RTD, SANCO, SJ, SG, TRADE, TAXUD 

Reference to Roadmap: 

http://ec.europa.eu/governance/impact/planned_ia/docs/19_ener_energy_infrastructure_package_en.pdf 

Background: 

Europe's  future  economic  growth  and  stability  depend  on  the  availability  of  appropriate 
energy  infrastructure  ensuring  the  achievement  of  the  EU  energy  and  climate  goals,  cost-
efficient functioning of the internal energy market and security of supply. In 1996, as part of 
EU  moves  to  complete  the  single  market,  the  Trans-European  Energy  Networks  (TEN-E) 
policy  was  developed.  Its  purpose  was  to  provide  a  more  political  impulse  to  energy 
infrastructure  development  from  the  European  perspective,  by  focussing  on  the  feasibility 
stage  for  gas  and  electricity  network  projects,  notably  those  crossing  borders,  which 
contribute to the working of the internal market. At that time, the EU had no common energy 
policy  and  no  functioning  internal  energy  market.  In  most  Member  States,  state-run 
companies managed network investments, which were mainly driven by national security of 
supply  considerations.  Later  revisions  to  TEN-E  incorporated  sustainability  and  supply 
security  criteria.  It  was  assumed  throughout  that  EU  intervention  in  the  implementation 
phases  of  such  projects  would  not  be  necessary,  as  commercial  interests  would  drive 
projects  forward.  The  TEN-E  budget  consequently  remained  very  low  –  some  €  22  million 
annually  in  the  period  2007-2013.  The  currently  valid  TEN-E  Guidelines  were  adopted  in 
September 2006 replacing those of 19961 and 20032. 

This impact assessment was prepared to support the forthcoming communication on energy 
infrastructure priorities (phase 1 of the so called "Energy Infrastructure Package") for a new 
policy to promote the development of TEN-E to enable adequate and timely development of 
energy  infrastructures.  This  impact  assessment  covers  the  development  of  energy 
infrastructure  for  the  period  2010-2020,  with  a  view  beyond  to  2030  -  having  in  mind  the 
energy  challenges  for  the  century  -  and  assesses  investment  needs  for  new  transmission 
infrastructure, evaluates the current TEN-E framework and financing possibilities, compares 
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 and thereby examines 
the possibility of integrating CCS and oil transport networks in the future policy. 

Building on the present document, a separate assessment will be carried out to prepare the 
legislative proposal for a new European energy security and infrastructure instrument, which 
is  to  be  presented  in  2011  (phase  2  of  the  Energy  Infrastructure  Package).  Therefore,  the 
present  impact  assessment  does  neither  include  a  detailed  analysis  of  the  way,  in  which 
infrastructure  investments  are  currently  financed,  nor  possible  solutions  in  terms  of  tariff 
regulation  or  financing  to  address  the  identified  investment  gap  or  other  financing 
shortcomings. 

The  detailed  list  of  documents  and  studies  that  have  been  used  for  the  preparation  of  this 
impact assessment can be found in Annex 5. 

1 Decision No 96/391/EC 
2 Decision No 1229/2003/EC 

5

 
 
 
 
 
 
 
 
 
                                                 
1.1.  Green paper and public consultation 

The main consultation for this impact assessment took place in the framework of the green 
paper  "Towards  a  secure,  sustainable  and  competitive  European  Energy  Network",  which 
was  endorsed  by  the  European  Council  and  Parliament  and  published  with  the  Second 
Strategic  Energy  review3.  The  green  paper  pointed  out  that  the  current  EU  network  policy 
was not able to deal with global security of supply challenges, to effectively diversify the EU's 
energy sources, to ensure solidarity in the case of an energy crisis or to draw on the benefit 
of new technologies. It also stressed the direct link between energy import infrastructure and 
the  EU's  external  relations.  The  Green  Paper  recommended  that  energy  infrastructure 
development should be driven by the energy policy goals: the "20-20-20" objectives4, security 
of  supply  and  solidarity,  sustainability  and  innovation,  as  well  as  competitiveness.  The 
implications  of  climate  change  for  Europe's  energy  networks,  concerning  for  example  the 
location  of  power  plants,  electricity  lines  and  pipelines,  were  identified  as  an  important 
element to be taken into account for infrastructure projects. It moreover recommended: 

• 

• 

• 

• 

• 

• 

to  extend  the  scope  beyond  electricity  and  gas  transport  infrastructures  (including 
liquefied natural gas terminals and storage) to oil and CO2 transport infrastructure; 
to  let  the  market  drive  planning  with  a  clear  remit  for  the  European  Network  of 
Transmission  System  Operators  and  the  Agency  for  the  Cooperation  of  Energy 
Regulators, as well as the EU as active facilitator and mediator; 
to  narrow  down  the  number  of  priorities  to  a  limited  number  of  European  strategic 
projects, to be incorporated in national infrastructure plans; 
to  build  up  accompanying  measures  to  disseminate  information  and  exchange  best 
practices; 
to  consider,  in  exceptional  cases,  the  appointment  of  a  European  Coordinator, 
building on the experience of the past/current coordinators; 
to improve the effectiveness of the TEN-E instrument within existing means through 
better coordination with other EU financial instruments, while also considering ways of 
increasing  the  TEN-E  budget,  notably  to  support  investments  with  a  public  good 
character. 

Questions at the end of the Green Paper addressed the main barriers to the development of 
a European electricity and gas network and the role the EU should play in overcoming these 
barriers.  Concerning  TEN-E,  the  questions  asked  advice  on  the  main  recommendations 
listed  above  and  additional  measures 
to  secure  sustainable 
infrastructures. 

the  EU  could 

take 

During  the  four  month  consultation  exercise,  ending  on  31  March  2009,  The  Commission 
received  91  written  replies  to  the  questions  raised  in  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. 
The  energy  sector  dominated  the  industrial  responses.  Contributions  were  received  from 
system operators, the upstream sector, the energy equipment sector, and cogeneration and 
district  heating  companies  as  well  as  shippers,  traders  and  firms  involved  in  infrastructure 
construction.  The  renewable  industry  was  mainly  represented  by  wind  and  solar  industry 
players. 

A clear message from the public consultations was that there is a strong need to better align 
the  energy  network  policies  of  the  EU  and  the  EU  energy  and  climate  targets.  There  was 
also general support for a fundamental review  of the TEN-E framework. The Commission's 
concern  to  give  more  attention  to  energy  infrastructure  as  a  factor  of  energy  security  was 

3 COM (2008) 781 "An EU energy security and solidarity action plan" endorsed by the Council in its March 2009 
summit conclusions 
4 20% reduction in greenhouse gas emissions, 20% share of renewable energy in EU final energy consumption 
and 20% improvement in energy efficiency by 2020 

6

 
 
 
 
 
                                                 
also  vindicated.  The  possibility  to  also  cover  transport  infrastructure  for  carbon  dioxide 
capture and storage (CCS) was generally supported, while the replies were more hesitant on 
oil  transport  networks.  A  specific  area  where  a  broad  consensus  emerged  was  in  the 
relevance  of  energy  networks  to  EU  external  energy  relations.  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. 

Stakeholder consultations 

1.2. 
Stakeholder  consultation  included  discussions  in  the  Gas  Coordination  Group5  (March  and 
June  2010)  comprising  representatives  of  27  Member  States  and  gas  industry  and  gas 
consumers'  associations,  in  the  different  working  group  meetings  (Sustainable  Fossil  Fuel 
and Security of Supply working groups) of the Berlin Fossil Fuels Forum (May 2010). Regular 
exchange of information took place with the two European Networks of Transmission System 
Operators  (ENTSO)  for  gas  and  for  electricity  and  the  European  Regulators'  Group  for 
Electricity  and  Gas  (ERGEG).  The  10  year  network  development  plans  developed  by  the 
ENTSOs served as an important input for the infrastructure needs assessment. A high level 
conference  was  organised  under  the  Spanish  Presidency  on  28  May  2010.  Regarding  the 
development of offshore grids, inputs from the so-called "Adamowitsch working group6" and 
the workshop organised by the North Seas Countries' Offshore Grid Initiative (March 2010) 
have been incorporated.  

Several  bilateral  meetings  with  industry  representatives  and  stakeholder  organisations  took 
place  providing  similar  results  to  the  public  consultation.  The  electricity  industry  expressed 
particular  concern  about  lengthy  and  uncertain  permitting  procedures  and  supported  the 
Commission's intention to tackle those. A further concern was the need for better regulation 
of grid investment financing and cost sharing. The industry also pleaded for the definition of 
priority  infrastructure  corridors  rather  than  pre-defined  project  lists.  The  gas  industry 
generally emphasised the environmental advantages of gas in terms of lower CO2 emissions 
in comparison to other fossil fuels. The CCS sector was strongly in favour of the inclusion of 
CO2 transportation infrastructure in the trans-European networks policy, while there was no 
common  position  concerning  the  inclusion  of  oil  pipelines  within  the  oil  industry  (generally, 
Eastern  EU  oil  companies  supported  the  idea,  while  Western  European  companies  did  not 
have a position). 

Regarding  smart  grids,  this  impact  assessment  has  benefited  from  the  input  given  by  the 
European  Technology  Platform  smart  grids  for  the  preparation  of  the  Strategic  Energy 
Technologies plan (June 2007) and by the three experts groups of the European Task Force 
for smart grids, which presented their intermediate reports in June 2010. 

Following  the  recommendations  for  improvement  included  in  the  opinion  of  the  Impact 
Assessment  Board  on  the  27th  September  2010,  a  better  explanation  is  provided  on  the 
issues, which will be tackled in the forthcoming Communication and are thus included in this 
impact  analysis,  and  on  the  issues,  which  would  need  to  be  further  explored  for  the 
legislative  proposal  and  its  accompanying  Impact  Assessment,  to  be  prepared  next  year. 
Chapters 2.3 and 3 have been amended accordingly. To provide more transparency on the 
underlying  modelling,  its  assumptions  and  investment  estimates,  specific  boxes  have  been 
inserted in Chapters 2.4 and 5.1. Chapter 2.4 has generally been amended to better highlight 
what  the  expected  impact  of  the  implementation  of  the  3rd  Package  on  the  internal  energy 
market will be in the baseline scenario. In these chapters, the current tariff setting rules and 
their  shortcomings  as  well  as  the  definition  of  "commercial  viability"  are  better  explained; 
however, an in-depth analysis of these issues is foreseen for the IA report accompanying the 

5 Commission Decision 2006/791/EC 
6 Consultative group set-up by the EU Coordinator for off-shore wind, Mr. Georg-Wilhelm Adamowitsch 

7

 
 
 
 
 
 
                                                 
legislative  proposal.  Concerning  the  issue  of  permitting  Chapters  4.4  and  5.5  have  been 
amended,  including  clearer  explanations  and  indications  on  the  further  analysis  to  be 
undertaken  to  provide  a  more  thorough  assessment  of  the  options  aiming  at  accelerating 
permitting – i.a. the assessment of the compatibility of the options with national legal systems 
and  their  costs  –  and  included  in  the  Impact  Assessment  for  the  legislative  instrument.  
Finally, the options and impacts for the policy areas of coordination and design of new policy 
instrument have been clarified in Chapter 4.2, 4.3, 5.3 and 5.4. Following the second opinion 
of the Board (18th October 2010), further improvements have been included with reference to 
the estimates on the investment needs and in the conclusions. 

2. 

PROBLEM DEFINITION 

2.1.  A dramatically changed policy context 

This chapter summarises the current energy policy context which has changed dramatically 
since the TEN-E policy was last revised in 2006. More details on existing legislation and its 
impact on future infrastructure development will be given in chapter 2.4 (Baseline scenario). 

The  EU  Energy  Policy7  and  its  implementing  legislation,  pursuing  the  objectives  of 
sustainability,  competitiveness  and  security  of  energy  supply,  set  ambitious  goals  and 
binding  targets  for  2020  on  greenhouse  gas  emissions8  (-20%%;  -30%  if  a  satisfactory 
international  agreement  is  reached),  energy  from  renewable  sources9  (20%  of  final  energy 
consumption)  and  energy  efficiency  (20%  reduction  in  energy  consumption  compared  to 
business  as  usual).  This  legislation  includes  the  energy  and  climate  package  (Renewable 
energy  directive10  and  CCS  directive11),  the  third  internal  energy  market  package12  and  the 
recently agreed regulation on security of gas supply13. 

Adequate, reliable energy networks are a prerequisite to meet all these objectives. Europe's 
networks will have to undergo important evolutions to meet this challenge – evolving from a 
patchwork  of  national  networks  to  a  truly  integrated  EU-wide  network.  At  the  same  time, 
these  networks  are  aging  and  urgently  need  refurbishment  and  modernisation.  Therefore, 
massive  investments  in  network  infrastructure  will  be  needed  in  the  coming  decades, 
challenging  the  TEN-E  policy  framework  as  a  whole  and  the  existing  regulatory  model  for 
electricity and gas infrastructure development in Europe. 

The  regulatory  framework  itself  has  evolved  with  the  adoption  of  the  third  internal  energy 
market  package  in  July  2009.  It  introduces  several  new  rules  for  infrastructure  planning, 
coordination  and  investment,  which  address  many  of  the  weaknesses  (detailed  in  chapter 
2.4.2).  Transmission  System  Operators  (TSOs)  are  required  to  establish  national  10-year 
network development plans and to co-operate and elaborate regional and European 10-year 
network  development  plans  (TYNDP)  for  electricity  and  gas  with  a  focus  on  cross-border 
interconnections,  in  the  framework  of  the  European  Network  of  TSOs  (ENTSO).  The 
package also establishes an Agency for the Co-operation of Energy Regulators (ACER) that 
–  among  other  tasks  –  will  have  to  monitor  the  implementation  of  European  TYNDPs.  The 

7 COM (2007) 1 endorsed by the Council on 15 February 2007 (C/07/24) 
8  Directive  2009/29/EC  amending  Directive  2003/87/EC  so  as  to  improve  and  extend  the  greenhouse  gas 
emission allowance trading scheme of the Community, Decision No 406/2009/EC on the effort of Member States 
to  reduce  their  greenhouse  gas  emissions  to  meet  the  Community’s  greenhouse  gas  emission  reduction 
commitments up to 2020 
9 Directive 2009/28/EC on the promotion of the use of energy from renewable sources 
10 Directive 2009/28/EC OJ L140 of 5.06.2009 p. 16 
11 Directive 2009/31/EC establishes a legal framework for safe geological storage of carbon dioxide (CO2). 
12 http://ec.europa.eu/energy/gas_electricity/third_legislative_package_en.htm: see notably Directives 2009/72/EC 
and 2009/73/EC and Regulations (EC) 713/2009, 714/2009 and 715/2009 
13 http://www.europarl.europa.eu/oeil/FindByProcnum.do?lang=2&procnum=COD/2009/0108 

8

 
 
 
 
 
 
 
                                                 
third package finally sets the target, where possible, to equip at least 80% of consumers with 
smart meters by 202014 as a first step towards the implementation of smart grids. 

Furthermore,  the  European  Council15  has  set  as  an  EU  objective  an  80-95%  reduction  in 
greenhouse  gas  emissions  by  2050  compared  to  1990  levels,  in  the  context  of  necessary 
reductions by developed countries as a group. The Europe 2020 strategy therefore includes 
the establishment of a vision of changes required to move to a low carbon, resource efficient 
and  climate  resilient  economy  by  2050.  In  this  context,  there  is  work  on-going  within  the 
Commission  to  outline  a  vision  concerning  climate  action  and  possible  roadmaps  for  a 
transition to a low-carbon energy system by 2050. Infrastructure development and planning 
of today has to ensure that investments made in the next two decades are compatible with 
the long term vision. 

2.2.  Current TEN-E framework and European Energy Plan for Recovery 

The  TEN-E  framework  has  been  developed  and  shaped  in  the  1990’s  through  the 
successive  TEN-E  Guidelines  and  the  corresponding  financing  Regulation16.  The  current 
objectives  of  the  TEN-E  policy  are  to  (1)  support  the  completion  of  the  EU  internal  energy 
market  while  encouraging  the  rational  production,  transportation,  distribution  and  use  of 
energy  resources,  (2)  reduce  the  isolation  of  less-favoured  and  island  regions,  (3)  secure 
and  diversify  the  EU's  energy  supplies  also  through  co-operation  with  third  countries,  (4) 
contribute to sustainable development and protection of the environment (including inter alia 
a  greater  use  of  renewable  energy  sources  and  the  reduction  of  environmental  risks 
associated with the transportation of energy). The current TEN-E policy framework includes 
electricity,  gas  and  olefin  transmission  networks,  but  not  CO2  transportation,  neither  oil 
pipeline  infrastructure.  The  guidelines  establish  a  framework  for  closer  cooperation,  for 
example through better exchange of information and coordination between Member States. 
The  guidelines  foresee  that,  when  projects  encounter  significant  delays  or  problems,  a 
European coordinator may be appointed to the project in order to facilitate coordination and 
monitor progress. Four coordinators have been appointed in September 200717, on the basis 
of the Priority Interconnection Plan18. 

The 2006 guidelines for Trans-European Energy Networks listed about 550 projects eligible 
for  Community  support  according  to  the  above-mentioned  objectives,  ranking  them  in  the 
following  three  categories:  projects  of  European  interest  (42  in  total);  priority  projects  and 
projects of common interest. These projects cover only electricity and gas infrastructure, no 
oil, olefin or CO2 transportation infrastructure.  
The report on the implementation of the TEN-E framework in the period 2007-919, published 
in April 2010, concluded that the policy made a positive contribution to selected projects by 
giving  them  political  visibility  and  the  TEN-E  label  facilitates  communication  to  and 
collaboration with third parties. However, there is a lack of focus within the current guidelines 
and  not  enough  clarity  between  the  categorisation  of  projects  (common  interest,  priority 
project,  European  interest).  The  list  of  targeted  projects  is  rigid:  new  projects  and 
technologies  (e.g.  electricity  storage,  CNG  etc.)  cannot  be  included.  The  guidelines  are 
based  on  a  bottom-up  selection  of  existing  projects  but  do  not  leave  space  for  a  top-down 
approach to fill identified infrastructure gaps. There is no mechanism to ensure that Member 
States  grant  projects  of  EU  importance  the  same  priority  as  their  national  projects.  The 

14 Annex 1 of Directive 2009/72/EC 
15 European Council conclusions, 30 October 2009  
16  Decision  No  1364/2006/EC  laying  down  a  series  of  guidelines  for  trans-European  energy  networks  and 
repealing  Decision  96/391/EC  and  Decision  No  1229/2003/EC;  Regulation  (EC)  No  680/2007  laying  down  
general rules for the granting of Community financial aid in the field of the trans-European transport and energy 
networks 
17 http://ec.europa.eu/energy/infrastructure/tent_e/coordinators_en.htm  
18 COM(2006)846 
19 COM(2010)203 and SEC(2010)505 

9

 
 
 
 
                                                 
current  TEN-E  framework  is  not  binding  and  places  no  obligations  on  Member  States  or 
project promoters to really invest and construct infrastructure. TEN-E support may be given 
to  competing  and  –  within  a  given  timeframe  –  mutually  exclusive  infrastructure  projects. 
While  there  is  a  strong  link  between  the  EU's  external  energy  policy  and  infrastructure 
development,  coordination  between  TEN-E  and  external  aid  programmes  has  been 
insufficient. 

The TEN financing Regulation20 adopted on 20 June 2007 sets out the conditions for TEN-E 
funding  and,  in  particular,  states  that  co-financing  can be  granted  for  up  to  50%  of  studies' 
cost  and  10%  of  eligible  works'  cost,  in  particular  to  projects  of  European  interest.  The 
budget  for  the  period  2007-2013  is  155  million  euro  (about  22  mln  €  per  year).  Currently, 
TEN-E plays a particularly important role for immature or risky projects and feasibility studies. 
However,  no  precise  methodology  was  established  to  assess  the  "additionality"  of  EU 
support, i.e. the specific contribution of TEN-E funds to making projects actually bankable. 
The TEN-E Programme's limited financial resources may have been adequate when focused 
on studies for remaining problematic interconnections, but the paradigm shift to a low carbon 
energy  system  and  hence  the  major  evolution  and  investment  needed  in  energy 
infrastructures  in  the  coming  years  call  for  a  reassessment  of  the  TEN-E  instrument  to 
ensure its future effectiveness. The TEN financing Regulation allows only grants and interest 
rate  rebates,  while  the  market  rather  needs  innovative  financial  instruments  such  as 
guarantees or equity participations for risk mitigation. The current financing Regulation does 
not  allow  the  funding  capital  expenditures  outside  the  EU,  while  large  gas  import 
infrastructure and related connection to upstream sources or even electricity interconnections 
with third countries go well beyond EU borders. 

This  demonstrates  that  the  current  TEN-E  policy  and  financing  framework  is  not  effective 
enough given the above described dramatic changes in the wider policy context.  

Set  up  in  the  context  of  the  economic  and  financial  crisis,  the  European  Energy  Plan  for 
Recovery21 has responded to some of the weaknesses identified above by allocating, for the 
first time, significant amounts (around 4 bn€) to a rather limited number of eligible projects in 
the domain of electricity and gas interconnectors, gas reverse flows and storages, off-shore 
wind  and  CCS  demonstration  projects.  The  objective  was  to  help  overcoming  possible 
financial difficulties caused by the economic and financial crisis and thus to contribute to the 
expenditure  for  the  implementation  of  the  most  mature  projects,  in  order  to  speed  up  and 
secure investments and accelerate their construction. 

2.3.  Main problems 

The  challenges  and  drivers  as  well  as  the  obstacles  hampering  energy  infrastructure 
development  and  the  resulting  main  consequences  of  insufficient  infrastructure  are 
summarised below:  

20 Regulation (EC) No 680/2007 
21  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) 

10

 
 
  
 
 
 
 
                                                 
Challenges / drivers for demand growth for 
infrastructure investment: 
- Climate objectives (CO2, RES, efficiency) 
- Security of supply 
- Market integration 
- Evolution of energy generation mix/type 
and location 

Obstacles for delivering infrastructure:  
- Uncertainties concerning technologies 
- Tariff regulation and financing 
- Permitting and social acceptance 
- Imperfect internal market 
- Extra-EU infrastructures 
- Inadequacy of TEN-E policy 

• Insufficient energy (especially cross-
border) infrastructure is delivered 
• Infrastructure design is not optimal 
from an EU point of view

Economic: 
Higher energy prices due to lack, 
unavailability or suboptimal design 
of transmission capacity 

Social: 
Supply 
disruptions / 
black-outs 

Environmental: 
EU climate goals not 
achieved; local impact of 
new infrastructure 

Figure 1 

As pointed out in the introduction, the new policy context triggers substantial needs for new 
energy infrastructure investment in the EU, which is estimated at about 200 billion euros up 
to 2020 (see chapter 0 for details). However, due to the obstacles described in this chapter, 
not  all  the  necessary  investment  will  materialise  under  current  conditions.  The  obstacles  to 
adequate development of infrastructure can be described in detail as follows:  

1)  Huge  uncertainties  concerning  future  technologies  in  terms  of  their  availability, 
possible risks and cost competitiveness, standards for the interoperability and scalability 
of systems (notably for certain renewable energy technologies, offshore grids and smart 
grid infrastructure, but also for electricity storage and CCS, currently not included in the 
TEN-E  framework),  energy  mix  and  geographical  distribution  of  future  plants 
(electricity),  and  new  sources  (unconventional  gas,  green  gas,  LNG/CNG,  new  import 
infrastructure and upstream development in third countries) add to the overall uncertainty 
of future energy market developments and lead to sub-optimal market solutions (from an 
EU point of view). 
The market players and/or regulators do not anticipate future demand / capacity needs if 
it  is  not  commercially  viable  or  would  result  in  higher  tariffs  in  the  short  term.  This  will 
result in increased cost over time (in the long term) and higher environmental impact (for 
example a number of smaller pipelines instead of one large). 

2)  Tariff regulation and financing: Transmission is a regulated business at national level 
and cost allocation to final beneficiaries is difficult or impossible for large trans-European 
infrastructure. In order to keep transmission tariffs as low as possible, tariff regulation in 
most  Member  States  has  been  based  on  the  principle  of  cost-efficiency,  allowing 
recovery  of  costs  only  for  projects  based  on  real  market  needs  or  cheapest  available 
solutions.  There  are  in  particular  three  types  of  projects,  whose  realisation  is  typically 
hindered through this approach: 

a.  Projects with higher regional than national benefit: 

The  higher  the  regional  or  EU  benefit  of  a  project,  i.e.  the  more  Member  States 
are  involved,  the  more  complex  it  often  is  (cross-border  issues  including  e.g. 
different regulatory regimes concerning rates of return or investment amortisation 

11

 
 
 
 
 
 
 
periods,  different  permitting  procedures  etc.)  and  the  more  difficult  cross-border 
coordination  gets,  especially  if  the  costs  and  benefits  of  the  project  are  shared 
asymmetrically  between  Member  States.  This  complexity  increases  the  project 
risks and hence the financial needs, which will not be covered by the market and 
new  third  package  rules  alone.  It  will  result  in  sub-optimal  solutions  in  terms  of 
overall European or regional benefit. 

b.  Projects  using  innovative  technologies22  typically  involve  higher  risks,  as  their 
industrial-scale  applicability  and  business  case  are  not  fully  proven  yet. 
Nevertheless,  market  players  do  often  not  ask  for  and/or  regulators  do  not 
approve  a  higher  rate  of  return  to  make  them  bankable.  Thus,  first-of-their-kind 
projects  that  use  new  technologies  for  generation  (e.g.  carbon  capture  and 
storage)  or  transmission  (e.g.  DC  VSC  offshore  grid  technology,  storage,  smart 
grid applications), and which are necessary for the achievement of the EU energy 
and climate goals, will not be implemented within the set timeframe23. 
Uncertainty  on  the  appropriate  market  model  and  regulatory  approach  for  the 
above mentioned technologies also lead to suboptimal solutions. 
Infrastructure with the objective to enhance security of supply – in pursuit of the 
infrastructure standards included in the new regulation on security of gas supply 
(N-1  and  reverse  flow)  –  is  needed  all  over  the  EU,  but  is  only  rarely  if  ever 
justified by market demand and transported volumes as it is used only in case of 
supply  disruptions  (low  probability  /  high  impact  events),  but  not  under  normal 
market conditions. In many Member States, most of them with relatively low per 
capita GDP levels, there has so far been no regulatory solution on how to recover 
the  costs  of  these  investments,  and  financing  through  tariff  increases  will  be 
difficult to achieve24. 

c. 

In addition, there are externalities concerning the financing of infrastructure: TSO's must 
justify  their  investment  to  the  national  regulator  by  looking  at  future  revenues  only  from 
transmission;  they  cannot  factor  in  revenues  from  business  opportunities  such  as  price 
arbitrage between markets or market contestability (lower prices in a given market due to 
the  threat  of  competition).  For  the  same  reason,  supply  shortage  or  increased  market 
prices (due to lack of infrastructure) have no or little impact on TSO revenues, while they 
have a huge economic impact on commodity markets.  
Finally,  as  a  result  of  the  financial  crisis,  and  the  current  rapid  evolution  of  rules  in  the 
financial sector, access to capital has become more difficult since 2008. Credit ratings of 
many  TSOs  have  deteriorated  and  still  continue  to  do  so.  There  is  also  a  lack  of 
adequate  financing  instruments,  risk  capital  and  loans  at  sufficiently  long  maturity. 
Furthermore, there seems to be a lack of knowledge within the financial sector, notably 
among potentially interested investors (such as private wealth funds), on how to evaluate 
energy infrastructure investments. 

3)  Permitting  and  social  acceptance:  Long  and  uncertain  permitting  procedures  were 
indicated  by  industry  as  one  of  the  main  reasons  for  delays  in  the  implementation  of 
infrastructure  projects,  notably  in  electricity.  This  puts  a  major  additional  risk  on 
investments in power generation and transmission and has slowed down or even stopped 
new  projects.  In  several  Member  States,  public  opinion  is  turning  progressively  against 
new projects and in particular overhead electricity lines, adding to the obstacles faced by 
projects  due  to  inappropriate  authorisation  procedures  and  administrative  practice. 

22 Cf. Impact Assessment of the SET Plan (SEC (2009) 1297) 
23  The  European  Electricity  Grid  Initiative  (EEGI),  launched  in  the  framework  of  the  SET  Plan,  has  identified 
research  and  development  priorities  for  both  electricity  transmission  and  distribution  covering  the  period  up  to 
2018.  The  functional  areas  covered  include  improved  grid  planning,  renewables  integration,  both  on-  and 
  which  about  560  m€  for 
offshore,  and  smart  grid  applications,  with  a  budget  estimated  at  2  bn€,  out  of
transmission activities alone. However, the projects focus on studies only and do not cover industrial-scale works. 
24  Cf.  "Commission  Declaration  on  long  term  security  of  supply  measures"  related  to  Regulation  XXX/2010 
concerning measure to safeguard security of gas supply and repealing Directive 2004/67/EC 

12

 
 
 
                                                 
Therefore, the time between start of planning and final commissioning of a power line is 
frequently more than 10 years, be it a domestic or a cross-border project. With significant 
permitting  obstacles  and  public  opposition,  projects  can  take  up  to  20  years  to  be 
completed25.  Cross-border  projects  often  face  additional  opposition,  as  they  are 
frequently  perceived  as  mere  "transit  lines"  without  local  benefits.  Limited  public 
understanding  for  the  benefits  of  a  given  project  or  technology  might  also  limit  in 
particular the roll-out of smart-grid applications. 

4)  Imperfect  internal  market:  there  is  weak  competition  in  some  Member  States  where 
national  markets  are  still  dominated  by  incumbents  (such  as  Belgium,  France,  Greece, 
Latvia,  Luxembourg  or  Slovakia  in  electricity  and  Finland,  Greece,  Latvia,  Lithuania, 
Luxembourg, Poland, Slovakia and Slovenia in gas)26. Lack of infrastructure constitutes a 
high entry barrier for new entrants, especially in markets, which are dominated by historic 
operators  and  will  most  likely  remain  so  over  the  coming  years,  despite  third  package 
provisions  on  unbundling.  Lack  of  market  development  does  not  allow  TSOs  to  have 
sufficient  firm  capacity  contracts  to  invest  in  an  interconnector  between  two  markets;  at 
the  same  time,  the  market  is  unlikely  to  be  able  to  develop  as  long  as  there  is  no 
interconnector. 

5)  Infrastructures  external  to  the  EU.  For  energy  infrastructures  outside  the  EU  that  will 
be  required  to  meet  the  EU’s  growing  need  for  imported  gas  and  oil  and  to  improve 
security  of  supply  through  diversified  supply  sources  and  routes,  or  to  import  "green 
electricity", there are additional political risks. Beside the need to engage politically with 
third  countries  to  identify  and  ensure  a  mutual  benefit  from  new  energy  infrastructures, 
risks  may  range  from  an  unattractive  or  non-transparent  investment  framework  in  the 
third countries through to the risk of changes in the fiscal/tax or legal environment once 
the investment has been made. 

6)  Inadequacy of the current TEN-E policy as described in chapter 2.2. 

It  clearly  derives  from  the  above  that  the  new  energy  policy  context  has  created  huge 
challenges for EU infrastructure development at a continental scale. Current policies aiming 
at  connecting  national  grids  will  not  be  sufficient,  as  there  is  a  need  to  build  a  fully 
interconnected  European  network  for  electricity  and  gas,  including  through  new  electricity 
super-grids. 
To  meet  the  EU’s  energy  and  climate  goals  for  2020  and  beyond  up  to  2050,  massive 
investments are required in energy networks and particularly in Europe’s electricity grids over 
the next two decades up to 2030 as a necessary condition for change to happen in energy 
generation, supply and demand. Given the problems encountered, these investments will not 
happen quickly enough without strong action both at national and Community level. 

This  Impact  Assessment  aims  at  supporting  the  forthcoming  Communication  with  the 
objective  to  establish  a  broad  policy  direction  for  future  infrastructure  development.  This 
initiative  hence  broadly  addresses  the  above  identified  problems,  in  particular  the 
uncertainties, the issues surrounding permitting, external policy aspects of infrastructure and 
the inadequacy of the current TEN-E, including inter alia the lack of focus and the rigidity of 
the identified project list. 

The proposals included in the Communication and the remaining problems will be addressed 
and  followed  up  next  year  through  the  legislative  proposal  for  an  EU  Energy  Security  and 

25 ENTSO-E 10-year network development plan, June 2010 
26 Benchmarking Report (COM (2010) 84) and technical annexes (SEC (2010) 251) 

13

 
 
 
 
 
 
 
 
 
                                                 
Infrastructure  Instrument,  for  which  a  specific  impact  assessment  will  be  prepared  with 
particular focus on financing, tariff regulation and an in-depth analysis on permitting. 

2.4.  Baseline scenario 

This  chapter  presents  the  likely  evolution  of  networks  and  bottlenecks  in  terms  of 
infrastructure development under the current policy framework. 

Box 1: Methodology used for infrastructure investment needs assessment 

The analytical tools used are the following:  

a) for determining energy balances in 2020 and 2030, the PRIMES model (using the results of GEM-
E3, PROMETHEUS and GAINS modelling as inputs); 
b)  for  evaluating  resulting  infrastructure  needs  in  the  electricity  and  gas  sector,  a  specialized  grid 
modelling framework developed by KEMA and Imperial College London; 
c) for assessing infrastructure needs for CO2 transport, two specialized analysis and modelling tools 
developed by ARUP and JRC. Experience from on-going investments was also analysed. 

a) PRIMES modelling of energy balances 

The  PRIMES  model  is  a  modelling  system  that  simulates  a  market  equilibrium  solution  for  energy 
supply  and  demand.  The  model  is  organized  in  sub-models  (modules),  each  one  representing  the 
behaviour of a specific (or representative) agent, a demander and/or a supplier of energy. Several EU 
baselines and scenarios have been established at different points in time using a framework contract 
with  National  Technical  University  of  Athens  (author  and  owner  of  the  PRIMES  model).  Energy 
modelling is a tool for informed policy making. For instance, the PRIMES 2007 baseline was used to 
analyse impacts of the energy and climate package in 2008. This analysis relies on the 2009 update of 
PRIMES. Two recent scenarios have been developed:  
• 

the Baseline 2009 that takes into account the policies implemented in the Member States up to 
April 2009; 
the  Reference  scenario,  which  includes  policies  up  to  the  end  of  2009  and  assumes  the 
achievement of the legally binding targets on renewables and greenhouse gas reduction. 

• 

The latest update is based on an average GDP growth of 1.7% per year for the period 2005-2030 as 
opposed to 2.2% in the 2007 baseline. The energy projections are based on a relatively high oil price 
environment  compared  with  previous  projections  and  similar  to  reference  projections  from  other 
sources,  with  oil  prices  of  59  $/barrel  in  2005  rising  to  106  $/barrel  in  2030  (in  year  2008-dollars). 
Significant  changes  in  these  assumptions  alter  the  energy  outlook  for  the  next  20  years.    Primary 
energy  consumption  stabilizes  at  today's  level  as  compared  to  rising  consumption  in  2007  baseline. 
Less  electricity  is  projected  but with  more RES  in  the  system (impacts  on  electricity  grid)  as well as 
lower  demand  for  gas  (lower  gas  imports).  More  information  can  be  downloaded  from  the  Europa 
website: 
http://ec.europa.eu/energy/observatory/trends_2030/index_en.htm 

b) Modelling of electricity and gas infrastructure requirements 

Investment  needs  were  assessed  for  electricity  and  gas  infrastructure,  taking  into  account  the 
available  information  in  the  10-year  network  development  plans  prepared  by  the  two  European 
Networks  of  Transmission  System  Operators  (ENTSO,  introduced  by  the  3rd  package),taking  into 
account  also  the  interdependencies  between  the  two  sectors.  It  should  be  noted  that  a  forecasting 
exercise  with  a  time  horizon  of  up  to  two  decades  can  only  give  indicative  results,  given  the 
uncertainties surrounding future supply, demand and price developments. 

Electricity 

14

 
 
 
 
 
 
 
 
 
 
 
 
The  requirements  for  investment  in  electricity  infrastructure  were  estimated  using  a  modelling 
framework  developed  by  KEMA  and  Imperial  College  London  (ICL),  which  divides  the  investment 
requirements into two parts: 
-  an  investment  estimate  for  the  interconnection  requirements  between  Member  States  to  evaluate 
cost-optimal  regional  interconnection  and  generation  capacity  requirements  for  system  security 
purposes, and the annual operating costs of the system; 
-  an  investment  estimation  for  the  cost  of  integration  of  offshore  wind  capacity  based  on  a  separate 
estimation tool. 
The investment model divides the EU27 countries plus Norway and Switzerland into 29 regions. The 
model trades off the various investment elements and optimises based upon input cost assumptions. 
The  scope  of  the  transmission  system  analysis  is  focused  on  incremental  capacity  requirements 
between the regions for each future scenario relative to the current 2010 baseline, but respecting the 
anticipated 2020 transmission capacities contained within the ENTSO-E TYNDP, i.e. all investments in 
the ENTSO-E TYNDP are assumed to happen in all scenarios. 

Three scenarios were modelled, two based on PRIMES 2010 Reference scenario in 2020 and 2030 
and  a  further  High  Renewable  Energy  Source  scenario  (High  RES)  in  2030.  The  modelling  results 
provide  snapshots  of  electricity  transmission  network  investment requirements,  additional  generation 
investments and associated operational costs aligned with the respective time horizon. 

For each scenario, the European electricity system is modelled as a 29-node system with 54 defined 
interconnection  possibilities  between  these  nodes.  The  system  consumption  and  peak  demand 
characteristics  are  common  in  the  two 2030  scenarios and  greater  than  the  overall electrical  energy 
requirement  assumed  in  the  2020  scenario.  The  consumption  data  for  all  scenarios  is  aligned  with 
PRIMES consumption forecasts including the net electricity import/export position. 

The modelling approach relies on a cost estimation methodology. It seeks to provide an indication of 
the  capital  costs  associated  with  expanding  the  interconnection  capacity  between  Member States  to 
maintain  a  power  system  with  security  characteristics  similar  to  those  experienced  today.  The 
modelling  framework  does  not  provide  specific  costs  for  any  particular  circuits  to  form  the  indicated 
transmission capacity. Nor does it assess the investment requirements for connections due to growing 
demand or investment in the distribution network. 

Both  technical  and  cost  assumptions  were  developed  in  the  framework  of  a  previous  extensive 
analysis  of  industry  standards  and  learning  rates  and  vetted  by  key  industry  stakeholders. 
Assumptions and results were also discussed in detail with ENTSO-E experts in charge of the TYNDP 
preparation,  which  have  confirmed  the  validity  of  the  general  modelling  approach  and  the  indicative 
nature of the investment need results. 

It must be underlined that this modelling exercise covers only transmission needs for interconnection 
and offshore connection. Changes in the generation capacity mix (e.g. due to structural variations in 
fossil fuel prices), in energy demand (e.g. due to slower or faster than expected economic growth) or 
in  the  costs  for  certain  specific  transmission  technologies  could  have  a  significant  impact  on  the 
outputs  of  the  model.  While  it  is  assumed  that  assumption  errors  for  the  individual  transmission 
investments will offset each other to some extent, it has been estimated that the aggregate error on 
investment costs could be in the range of +/–15%. 

The  evaluation  of  investment  needs  in  Smart  Grids  has  been  based  on  the  most  recent  available 
literature,  in  particular  the  findings  of  the  High-Level  Advisory  Group  on  ICT  for  Smart  Electricity 
Distribution  Networks.  The  figures  used  are  only  very  first  indications  and  could  vary  significantly, 
depending on future technology cost evolutions. 

Gas 

The requirements for investment in gas infrastructure were based on gas demand projections from the 
PRIMES baseline 2009 and Reference scenario 2010 for 2020. These projections were matched for 
consistency  against  data  coming  from  stakeholders  (preliminary  ENTSOG  estimates,  Eurogas)  and 
analysing  the  most  recent  studies27  and  available  documentation  regarding  gas  infrastructure 

27  "Model-based  Analysis  of  Infrastructure  Projects  and  Market  Integration  in  Europe  with  Special  Focus  on 
Security  of  Supply  Scenarios",  study  by  EWI  Institute  of  Energy  Economics  at  the  University  of  Cologne.  May 

15

 
 
 
 
 
 
 
 
 
                                                 
development  projects,  including  investment  in  LNG  terminals,  natural  gas  storage  and  reverse  flow 
projects.  The  estimation  of  gas  infrastructure  investment  need  is  to  some  extent  dependent  on  the  
assumptions concerning future gas demand, which again depend to a limited extent on assumptions 
concerning  GDP  growth,  but  to  a  far  higher  extent  on  a  series  of  other  factors  such  as  gas  prices 
(partly based on mainly oil-indexed long-term contracts, partly decoupled from oil price and based on 
global supply and demand balance), the role of gas in electricity generation and in particular as back-
up  for  variable  electricity  energy  from  renewable  sources,  the  level  of  market  integration  and  the 
infrastructure  and  supply  standards  for  security  of  gas  supply  and  finally  the  cost  of  infrastructure 
(which can vary highly based on the routing for pipelines, cost of steel, the geological conditions for 
storage  etc.).  This  would  add  an  overall  +-25-30%  range  to  the  identified  figures  (about  +-20%  for 
storage and interconnectors and up to 50% for import infrastructure). 

c) Modelling of CO2 infrastructure requirements 

The  requirements  for  investment  in  CO2  transport  infrastructure  were  determined,  based  on  the 
amount of CO2 indicated as captured under both the PRIMES baseline 2009 and Reference scenario 
2010. Modelling was prepared by JRC, using a dedicated analytical tool (InfraCCS) and the following 
four methodological steps: 
- Identification and clustering of CO2 sources and sinks;  
- Assumptions about the evolution of captured CO2 emissions and storage capacities; 
- Routing of potential pipelines between nodes; 
- Selection of the optimal network and evolution over time. 
Given the fact that the EEPR CCS projects are already under development, the model runs under both 
PRIMES  scenarios  resulted  in  the  same  required  network  length,  with  the  Reference  scenario 
delivering slightly lower investment needs due to the fact the pipelines to be deployed would not have 
to  be  oversized.  Uncertainties  remain  concerning  the  evolution  of  CO2  demand  beyond  2020,  which 
will have to be analysed in more detail to confirm the need for pipeline oversizing. 

ARUP prepared a separate analysis to determine the optimal CO2 transport network in Europe and its 
evolution over time, based on predefined volumes of CO2, identification of suitable storage sites and a 
cost-minimisation  approach.  The  study  analysed  snapshots  for  2030  and  2050.  The  results  can 
therefore  not  be  directly  compared  with  the  results  of  JRC  analysis.  However  important  similarities 
have  been  recorded  in  the  shape  of  the  future  network  proposed  by  both  studies,  confirming  that  a 
regional approach to developing the future network will be essential.. Assumptions of the study were 
discussed  in  detail  with  the  EC  Fossil  Fuels  Forum  (Berlin  Forum)  stakeholders.  Zero  Emission 
Technology Platform (ZEP TP) was also consulted. Moreover, ZEP's Chairman in his letter of 30 June 
2010  addressed  to  the  Energy  Commissioner  stressed  that  the  policy  objective  of  ensuring  the 
development of networks to permit the achievement of the EU’s energy and climate objectives should 
explicitly be extended to include the development of new CO2 pipeline infrastructure. EURELECTRIC 
was  also  consulted.  It  xtended  its  support  to  a  coordinated  approach  to  the  development  of  a  CO2 
pipeline  network  across  Europe  and  recommends  that  CO2  infrastructure  should  be  included  in  the 
upcoming infrastructure instrument. Furthermore,  EURELECTRIC supported assumptions of ARUP's 
study,  in  particular  as  regards  developing  scenarios  outlining  different  transportation  roadmaps.  A 
number of other stakeholders supported Commission's approach. 

It is important to point out that deployment of CCS could have an important contribution to meeting the 
GHG  reduction  targets  as  described  in  the  Energy  and  Climate  package.  The  impact  assessment 
prepared  for  the  Directive  on  the  geological  storage  of  carbon  dioxide  proves  that  without  enabling 
policy  for  CCS  at  EU  level  (that  is,  achievement  of  climate  objectives  without  CCS),  the  costs  of 
meeting  a  reduction  in  the  region  of  30%  GHG  in  2030  could  be  up  to  40%  higher  than  with  CCS. 
Thus not enabling CCS would have substantial negative impacts on Europe’s capacity to meet the 2 
degrees  Celsius  target  and  on  competitiveness,  and  also  for  employment,  and  would  have  a  slight 
negative impact on security of supply. 

2010  and  "The  revision  of  the  trans-European  energy  network  policy  (TEN-E)",  impact  assessment  study  by 
COWI, Cambridge Econometrics and KEMA 

16

 
 
 
 
 
 
                                                                                                                                                         
2.4.1.  Energy trends and infrastructure needs 

The PRIMES reference scenario has been used to estimate future demand for energy up to 
2030, the impact assessment itself being limited to 2020. The results have been compared to 
the  PRIMES  baseline  scenario28  and  other  scenario  results.  It  is  assumed  that  the  two 
binding targets (20% renewables share and -20% greenhouse gas emissions) are achieved 
in  the  Reference  scenario,  implying  that  all  other  necessary  implementing  provisions  (such 
as the energy infrastructure policy) will be completed. In the baseline scenario, based only on 
continuation of already implemented policies, these targets are not achieved. While primary 
energy  consumption  is  projected  to  remain  largely  stable  at  1,800  Mtoe  and  final  energy 
demand  at  1,200  Mtoe  between  2010  and  2030  in  both  the  PRIMES  baseline  and  the 
PRIMES reference case scenario, the use of electricity and in particular renewable energies 
tends  to  increase  significantly  over  the  period,  while  the  use  of  coal,  but  also  oil  and  gas 
decline under both scenarios, however at a substantially different pace. In the following, we 
give a more detailed overview of the likely evolutions by sector. 

The electricity sector is expected to face increasing demand, partly because of a major fuel 
shift  in  the  overall  energy  mix  as  a  result  of  the  greenhouse  gas  reduction  goals,  but  also 
because of its convenient use and the multiplication of applications relying on it as an energy 
vector  (heat  pumps,  electric  vehicles,  information  and  communication  technology  devices 
etc.). EU-27 gross electricity generation is projected to grow from about 3,362 TWh in 2007 
to 4,073 TWh in 2030. At the same time, the electricity generation mix is changing, with less 
fossil  fuels  and  more  renewable  and  variable  energy  sources.  According  to  the  Reference 
scenario,  their  share  in  gross  electricity  generation  is  expected  to  be  around  33%  by  2020 
and 36% in 2030, out of which variable sources (wind and solar) could represent around 16% 
in 2020 and almost 20% in 2030. Significant new renewable capacities will be concentrated 
in  locations  further  away  from  the  major  centres  of  consumption  (offshore  wind  parks, 
ground-mounted solar parks), while decentralised generation will also gain field. This change 
in  the  nature  of  both  generation  and  consumption  patterns  will  require  both  electricity 
transmission  and  distribution  grids  to  play  an  ever  more  important  role  in  flexibly  balancing 
supply and demand over increasing distances, while maintaining the same levels of security 
of  supply.  At  the  same  time,  the  correct  functioning  of  the  internal  electricity  market  will 
require additional cross-border interconnections and reinforcements of domestic grids. Annex 
1  shows  the  major  additional  cross-border  transmission  capacity  needs  until  2015  and 
beyond, as estimated by ENTSO-E.  

All  these  factors  trigger  large-scale  investment  needs  at  a  level  not  seen  over  the  past 
decades, both within Member States and cross-border, including in areas almost not covered 
today by electricity grids such as the Northern and the Baltic Seas. ENTSO-E's first TYNDP 
compiles  a  list  of  about  500  projects  selected  by  national  TSO's  and  identified  as  being  of 
European  significance  because  of  their  contribution  to  market  integration,  integration  of 
renewables or security or supply29. This list amounts to a total of about 42,100 km (35,300 
km  new  connections,  6,900  km  upgraded  connections).  For  new  lines  alone,  this 
corresponds  to  doubling  the  annual  extension  of  the  currently  operational  European 
transmission grid, with a growth rate of about 1.5% between 2010 and 2020, compared to an 
annual average of 0.8% for the EU-15 during the period 1989-200330. This corresponds to an 

28 EU Energy Trends to 2030: Update 2009 (Baseline 2009 and Reference scenario 2009). A detailed description 
of these scenarios and their assumptions is available at http://ec.europa.eu/energy/studies/index_en.htm. 
29 It must be stressed that this list does not include local, regional or national projects, which are not considered to 
be of European significance. As many transmission grids were built in the 1950’s and 1960’s and near the end of 
their lifetime, important additional investment needs will arise from the renewal or refurbishment of existing local, 
regional and national lines. 
30 "Lessons from Liberalised Electricity Markets", OECD/IEA 2005, p.145 

17

 
 
 
 
 
                                                 
annual  investment  of  about  3.3-4.7  bn  €  per  year  for  projects  of  European  significance. 
According  to  ENTSO-E's  own  calculations,  these  projects  correspond  to  an  overall 
investment need of 50-70 bn€ 31 for the period 2010-202532. According to KEMA calculations, 
these projects would need to be operational in 2020 to reach the 20-20-20 targets33. 

As  underlined  by  ENTSO-E,  the  first  TYNDP  does  not  take  full  account  of  needed 
infrastructure  investment  triggered  by  important  new  offshore  wind  generation  capacities  in 
the Northern Seas34. According to the national renewable energy action plans submitted by 
19  Member  States  in  application  of  directive  2009/28/EC35,  2020  installed  capacity  is 
estimated  at  over  40GW,  while  56  GW  are  needed  according  to  the  PRIMES  reference 
scenario. According to calculations done by KEMA, this adds investment needs of about 32 
bn€  for  offshore  connection  infrastructure  by  2020.  In  the  medium  term  up  to  2030,  more 
offshore  wind  and  development  of  solar  energy  generation  capacities  in  Southern  Europe 
and  beyond  will  trigger  further  transmission  grid  development  needs.  According  to  KEMA 
estimates, overall offshore connection and cross-border interconnection needs could amount 
to  an  additional  18  bn€  in  the  period  2021-2030  under  a  PRIMES  reference  scenario  with 
about  36%  of  renewables  in  gross  electricity  generation  in  2030,  or  as  much  as  100  bn€ 
under  a  more  ambitious  High-RES  scenario  developed  by  KEMA  with  about  50%  of 
renewables by 203036. 

Moreover, reaching the EU's energy efficiency and renewable targets might not be possible 
without  more  intelligent  networks,  based  in  particular  on  more  demand  side  management 
and  smart  grid  technologies.  Digitised  electricity  grids  enable  two-way  communication 
between  suppliers  and  consumers  and  feature  an  intelligent  monitoring  system  to  track 
electricity  flows  in  all  directions.  This  will  contribute  to  reducing  network  losses,  increasing 
the  reliability  of  the  grid  and  allowing  large  amounts  of  variable  renewable  power  to  be 
connected to the grid. Moreover, smart grids will enable consumers to control appliances at 
their  homes  to  save  energy,  facilitate  domestic  generation,  reduce  cost  and  increase 
transparency. The investment needs in smart grid technology to make networks "intelligent" 
as a whole and get the expected benefits out of 200 million smart meters has been estimated 
at 40 billion € by 2020 37. By 2030, total additional investment in smart grids deployment in the 
EU could reach 176 bn€, out of which 50 bn€ for smart metering, according to the final High-

31  Note  that  transmission  investment  costs  are  highly  sensitive  to  technology  choices.  The  investment  cost  for 
undergrounding  cables,  e.g.  to  reduce  their  environmental  impact,  is  typically  3  to  10  times  higher  than  the 
investment  cost  for  an  overhead  line  or  even  more  if  specific  structures  are  needed  (Source:  ENTSO-E  and 
Europacable). 
32  By  comparison,  the  average  investment  on  all  transmission  infrastructure  in  the  EU  from  1996  to  2004  has 
been around 3.1 bn € per year. The largest part was devoted to substations (40%), internal lines (33%) and other 
assets  (23%),  such  as  telecommunication,  protection  and  control,  and  special  equipment,  while  only  4%  of  the 
total  has  been  devoted  to  cross-border  lines,  mostly  for  HVDC  interconnections  through  submarine  cables 
(source: TEN-Energy-Invest study). While the resulting increase in annual investment would be significant (up to 
over 50%), it is not expected to overstretch the absorption capacity of the industry. On the one hand, TSOs are 
preparing themselves for this "wave" of investments over the coming years. On the other hand, the supply chain 
is  fully  ready  to  answer  such  increased  demand,  as  it  supplies  already  today  significant  volumes  to  strongly 
growing electricity transmission markets in e.g. China or India. 
33 "The revision of the trans-European energy network policy (TEN-E)", chapter 3 
34 It is expected that the next edition of the TYNDP planned for 2012 will take a more top-down approach, with a 
view beyond 2020, and address these shortcomings. 
35 Plans received and analysed as of 1st of September 2010 
36  It  should  be  noted  that  these  scenarios  also  have  significant  impacts  on  both  back-up  capacity  needs  and 
operating costs. KEMA has calculated that additional generation investment of about 42 bn € would be needed by 
2030  under  PRIMES  reference  to  ensure  current  levels  of  system  reliability.  Under  High-RES,  this  investment 
would  reach  93  bn  €.  This  would  however  be  compensat ed  by  lower  total  annual  generation  operating  costs 
under High-RES 2030 (130 bn €) compared to PRIMES reference 2030 (160 bn €). Note that this calculation does 
not take into account costs for developing the corresponding renewables generation capacity, which should be far 
higher than the related grid or back-up capacity investment. 
37  DG ENER calculations based on DG INFSO report "Impacts of Information and Communication Technologies 
on  Energy  Efficiency".  The  80%  target  of  Directive  2009/72/EC  corresponds  to  equipping  200  million  European 
households with smart meters. The cost for this equipment amounts to another 40 billion €. 

18

 
 
 
 
                                                 
530

480

Gas dem and

involved, 

towards  smart  grids 

Level  Advisory  Group  on  ICT  for  Smart 
Electricity  Distribution  Networks.  The 
evolution 
faces 
multiple  challenges,  given  the  technology 
the  absence  of 
changes 
harmonised  standards and  markets  rules. 
Because  of  the  uncertainties  and  high 
costs, no single one party is able to afford 
transmission 
investment  at 
smart  grid 
level  on  its  own.  Moreover,  even  if  cost-
benefit  analyses  in  Member  States  show 
overall  smart  metering  benefits,  absence 
of appropriate regulation leads to unequal 
allocation  of  cost  and  benefits  to  the 
different  parties  in  the  value  chain.  In  the 
medium 
long 
technologies  and  new 
distance  grid 
electricity  storage  technologies  will  also 
be  necessary.  Uncertainties  remain  today  as  regards  the  potentials  and  risks  of  these 
different technologies. 

term,  new  high-voltage 

Figure 2, in Mtoe

Primes reference

Primes baseline

Eurogas base

Eurogas env

140 

Entsog

2030

2015

2025

2020

95

380

430

The  overall  investment  need  for  electricity  networks  (including  offshore  and  smart  grids)  is 
estimated at 142 bn€ until 2020 38. However, the  attainment of this target is currently highly 
unlikely  because  of  the  delays  observed  for  the  planning  and  authorisation  of  overhead 
electricity  lines,  because  of  uncertainties  concerning  technologies  needed,  planning 
coordination  and  cost-benefit  allocation  for  offshore  grids  deployment,  and  because  of 
uncertainties related to technologies, common standards and appropriate market models and 
incentive regulation for smart grids. It is estimated that only about 30% of the total investment 
needed would be delivered under a business-as-usual scenario. 

Gas demand is highly dependent on energy policy choices. High uncertainty is surrounding 
the  future  of  gas  demand,  as  is  demonstrated  by  the  difference  between  various  demand 
scenarios  presented  in  Figure  2.  While  binding  RES  targets  may  crowd  out  gas  fired 
generation  (37%  of  gas  demand  in  2006)  as  base-load,  they  will  also  increase  its  role  as 
back-up.  At  the  same  time,  the  development  of  new  technologies,  such  as  CCS,  which  is 
highly  dependent  on  the  price  of  emission  allowances  in  the  EU  ETS,  may  increase  the 
importance of gas in power generation. On the other hand, efficiency gains in buildings may 
reduce gas demand. 

The main challenge that gas infrastructure faces is the high and growing dependence on gas 
imports (to reach about 73-79% by 2020 and 81-89% of consumption by 2030) mainly due to 
the depletion of indigenous resources. Based on the different scenarios, the additional import 
need  ranges  from  44  Mtoe  to  148  Mtoe  by  2020  and  from  61  to  221  Mtoe  by  203039 
import 
(compared 
infrastructure from various sources. This development should be closely linked with the EU's 
strategy towards third countries.  

for  sufficient  and  diversified 

Import  dependency  calls 

to  2005). 

38  The  level  of  in-country,  cross-border  and  offshore  grid  infrastructure  also  determines  additional  back-up 
capacity  requirements  in  the  different  Member  States.  According  to  KEMA  calculations  based  on  PRIMES 
reference, additional generation investment based on the cheapest available flexible generation technology would 
amount to 18 bn € by 2020. 
39 For the whole section on gas, the lower figures refer to the PRIMES 2010 reference scenario, while the higher 
figures  are  derived  from  the  Eurogas  Environmental  Scenario  published  in  May  2010,  based  on  a  bottom-up 
collection of the members' estimates. 

19

 
 
 
 
 
 
 
                                                 
In  addition,  the  increase  of  electricity  production  from  variable  renewable  energy  sources 
requires additional flexible back-up generation. A large part of it is expected to be provided 
by gas-fired power plants. Given current interconnection and forecast error levels, Eurelectric 
estimates that 200 GW of installed wind capacity correspond to about 20-30 GW of back-up 
capacity needs. This increases the need for flexibility, such as LNG/CNG, more flexible use 
of  pipelines  and  in  particular  gas  storage  (both  working  volume  as  well  as  injection  and 
withdrawal capacity), moving away from the traditional "injection in the summer, withdrawal in 
the  winter"  patterns.    According  to  some  estimates,  about  30-39  million  cubic  meters  of 
annual  working  volume  are  needed  to  balance  1  GW  of  installed  wind  capacity  in  the 
absence of other measures (such as demand side management). 

Thus  the  investment  need  for  gas  infrastructure  in  the  coming  decade  has  been  estimated 
(according to internal calculations based on conservative gas consumption assumptions) to 
reach  71  bn€ 40,  including  EU  internal  interconnectors  (including  reverse  flows),  new  import 
infrastructure (pipelines and LNG) and storage requirements41. However, given the problems 
faced  by  these  projects  as  outlined  above,  notably  in  terms  of  authorisation  delays, 
insufficient market development, lack of cross-border coordination and economic viability, it 
is estimated that only about 80% of the corresponding projects would be delivered under a 
business-as-usual scenario. More details to the figures are given in Box 2 under chapter 5.1. 

80% of imported crude oil is currently delivered to the EU by tankers. An important feature of 
the  internal  EU  oil  transport  network  is  that  the  Western  part  is  connected  via  pipeline  to 
major  European  ports  while  most  of  the  refineries  in  Central  and  Eastern  Europea  (EU12) 
are  supplied  through  the  Druzhba  oil  pipeline  system  from  Russia  (about  60  million 
tons/year).  There  are  limited  connections  between  the  Western  European  pipeline  network 
and the eastern infrastructures. This is a consequence of the fact that the Eastern European 
pipeline network (an extension of the final part of the Druzhba pipeline) was conceived and 
built  during  the  Cold  War  period  and  had,  at  that  time,  no  pipeline  link  with  the  western 
network.  Moreover,  in  these  countries,  unlike  in  the  EU15,  the  oil  demand  is  expected  to 
grow by 7.8% between 2010 and 2020 (see Error! Reference source not found.). In case 
of supply disruptions in the Druzhba system, the limited alternative supply options would lead 
to a big increase in tanker traffic in the environmentally sensitive Baltic area42, in the Black 
Sea  and  in  the  extremely  busy  Turkish  Straits43,  creating  big  concerns  about  the  potential 
danger of accidents and oil spills. This puts pressure to develop oil pipeline infrastructure to 
ensure security of supply in this region. 

CCS  is  a  novel  technology,  which  comprises  the  capturing  of  CO2  at  emission  points,  its 
transportation  and  underground  storage  in  suitable  geological  formations.  To  date,  the 
implementation  of  CCS  has  been  limited  to  pilot  plants  and  the  first  large-scale 
demonstration  projects  are  under  development  to  be  deployed  around  2015  supported  by 
Community funds, the New Entrants' Reserve of the EU Emissions Trading Scheme (the so 
called "NER300 initiative"44), state aid and contributions from developers. The Commission's 

40 The investment need may range from about 50 to 89 bn € based on various factors described in Box 1.
41 ENTSOG is currently elaborating on the investment need for the coming ten years to be included in their next 
TYNDP  to  be  published  in  December  2010.  To  date,  their  non  exhaustive  analysis  (work  in  progress)  has 
estimated  about  41  bn  €  of  identifi ed  investment  need.  The  above  mentioned  figures  have  been  checked  also 
against available (partial) studies. 
42 The Baltic Sea today is one of the busiest seas in the world, accounting for more than 15% of the world’s cargo 
transportation. Each month 3,500-5,000 ships cross the waters of the Baltic Sea. Approximately 17-25% of these 
ships are tankers transporting approximately 170 million tonnes of oil a year. 
43  The  Turkish  Straits  comprise  the  Bosporus  and  Dardanelles.  Less  than  a  kilometre  wide  at  their  narrowest 
point,  the  Turkish  Straits  are  one  of  the  world's  most  difficult  waterways  to  navigate,  due  to  their  sinuous 
geography. With 50,000 vessels, including 5,500 oil tankers, passing through the straits annually, they are one of 
the world’s busiest and most dangerous chokepoints. 
44 Cf. article 10(a) 8 of the revised Emissions Trading Directive 2009/29/EC 

20

 
 
 
 
 
 
                                                 
 
ambition, supported also by the Council, is to have up to 12 such plants. The demonstration 
projects will include integrated value chains consisting of CO2 capture installations, transport 
and storage infrastructure. The use of pipelines is widely considered to be the most reliable 
for long-term bulk movement of CO2. Whilst storage capacity in Europe is plentiful, it is not 
evenly  distributed  geographically  and  in  some  cases  distant  from  significant  emission 
sources.  Moreover,  some  EU  Member  States,  considering  their  significant  levels  of  CO2 
emissions, have limited potential storage within their state boundaries which calls for cross-
border  transport  infrastructure.  The  development  and  marketability  of  CCS  technologies  – 
and  hence  the  need  for  a  CO2  transportation  network  -  are  highly  dependent  on  the  CO2 
prices.  This  is  shown  in  the  PRIMES  reference  scenario  (lower  CO2  prices  due  to  lower 
demand for emission permits due to higher share of RES and more energy efficiency in the 
system)  where  the  share  of  CCS  use  in  power  generation  is  only  1.4  %  in  2030 
corresponding to 37.6 Mt of captured CO2. The PRIMES baseline with higher carbon prices 
allows for more CCS development reaching 8.7% of power generation in 203045.  

Without  intervention,  CO2  pipelines  installed  during  2014-2020  will  be  relatively  short  in 
length, associated with specific projects and therefore tailored to their needs. They will also 
rather  remain  geographically  remote  (i.e.  unconnected)  from  one  another.  For  the  period 
beyond  2020,  technology  experts  expect  a  commercial  rollout  of  CCS  in  lead  countries 
followed  by  a  global  rollout  of  CCS  after  2025.  Beyond  2030,  the  need  for  CO2  transport 
infrastructure could be even more important due to the expected share of CCS in the energy 
supply mix. This implies a need for early infrastructure development and advanced capacity 
investment, despite current low price of emission allowances due to the economic crisis. As 
the results of recent private sector analysis show, it is still more economical to oversize the 
pipelines  initially  and  wait  around  10  years  until  the  spare  capacity  is  fully  utilised  than  to 
build pipelines fit for one emission point and one CO2 sink46. 

The  CO2  infrastructure  investment  need  has  been  estimated  by  the  JRC  at  about  2.5  bn€ 
until  2020.  Under  a  business-as-usual  scenario,  i.e.  without  creating  the  necessary 
conditions  for  the  early  deployment  of  a  European  CO2  infrastructure  network  adapted  to 
future needs, it is estimated that no significant investment will take place. 

Moreover,  the  increased  interconnection  of  energy  networks  and  the  use  of  advanced 
information  technologies  represent  additional  challenges  in  the  event  of  external  events, 
such  as  those  resulting  from  natural  hazards  and  human-made  malicious  threats.  The 
aspects  of  physical  protection  of  infrastructures,  their  interoperability  under  disrupted 
conditions,  and  coordinated  planning  of  contingencies  will  need  to  be  addressed  with  a 
European  dimension  in  every  future  development  of  energy  infrastructures  as  they  are  key 
factors in the overall resilience of the energy supply system. 

As a result, the overall investment need amounts to 215.5 bn€ (142 bn€ electricity, including 
interconnections, offshore connections and smart grids; 71 bn€ gas, out of which 14 bn€ of 
investment outside the EU; 2.5 bn€ CCS). Taking into account assumptions on business-as-
usual market and regulatory conditions determining the commercial viability of projects (see 
chapter 2.4.2) and delays for project implementation in each sector (electricity, gas and CO2) 
(see  chapter  5.1  and  Annex  3  for  more  details),  one  can  estimate  the  business-as-usual 
investment: it would reach in electricity and gas 102 bn€ over the period 2010-2020 (45 bn€ 
electricity,  57  bn€  gas).  No  significant  investment  would  take  place  for  the  CO2  transport 
infrastructure as identified in the JRC and ARUP studies.. 

45 It must be noted that projections up to 2050 can feature significant changes to these prices, depending on the 
scenario chosen. 
46 Pre-FEED (front end engineering and feasibility) studies on industrial-scale carbon capture and storage (CCS) 
demonstration projects in the United Kingdom (2009) 

21

 
 
 
 
 
 
                                                 
2.4.2. 

Infrastructure delivery under current market, regulatory and financing conditions 

Electricity and gas infrastructure in Europe are regulated sectors, whose business model is 
based on regulated tariffs collected from the users, which allow recovering the investments 
made (“user pays principle”). The regulatory framework for infrastructure (including planning 
and investment) has evolved through the 3rd internal market package for electricity and gas 
that  was  adopted  mid  2009,  to  be  implemented  by  mid  2011.  It  enhances  the  separation 
("unbundling")  between  transmission  and  supply  activities.  On  the  one  hand,  this  may 
translate into more difficulties for TSOs to forecast future demand and no more possibilities 
of  cross-subsidies.  Thus  regulated  tariffs  and  congestion  rents  are  the  only  way  to  recover 
costs.  On  the  other  hand,  effective  unbundling  will  give  them  more  independence  and 
increase  their  incentives  to  better  plan  infrastructure  investment.  The  new  transparency 
guidelines  will  lead  to  better  information  within  the  market,  thus  to  possibly  more  available 
capacity for shippers in the case of gas, more optimal use of infrastructure and better signals 
on  congestions  where  TSOs  should  invest  in  additional  infrastructure.  Generally,  a  more 
efficient  market  should  provide  better  price  signals:  price  differentials  will  indicate  where 
additional or new interconnection capacities are needed within the European network. 

The  third  package  provides  for  new  rules  in  terms  of  infrastructure  development  across 
borders, which will facilitate the implementation of grid investments in electricity and gas: 

•  The third package establishes new rules for national regulatory authorities to cooperate 
on  cross-border  issues,  including  operational  arrangements,  networks  codes  and 
congestion management47. For electricity only, provisions are made as regards an inter-
transmission system operator compensation mechanism for costs incurred as a result of 
hosting  cross-border  flows,  which  should  clarify  the  sharing  of  costs  and  benefits  for  a 
given  cross-border  infrastructure48.  ACER  will  intervene  in  particular  to  establish  and 
monitor  implementation  of  network  codes,  to  coordinate  regulatory  differences  affecting 
cross-border  infrastructure  and  to  monitor  the  implementation  of  interconnection 
projects49. Notably the new rules on inter-TSO compensation, which are in the final stage 
of the comitology procedure, are expected to facilitate the implementation of needed grid 
investments. 

•  The  new  ENTSOs  for  electricity  and  gas  will  facilitate  co-operation  and  co-ordination 
between TSOs, notably for investment planning. The first European TYNDPs are based 
on  a  bottom-up  approach  and  were  successful  in  consolidating  existing  projects  in  one 
single document, thus giving more transparency to network planning. However, they do 
not  provide  a  top-down  vision  suited  to  identify  all  future  infrastructure  gaps  as  a 
consequence of the new energy and climate policy challenges. More top-down oriented 
second  versions  of  the  European  TYNDPs  will  be  published  in  December  2010  for  gas 
and  in  2012  for  electricity,  giving  the  start  for  bi-annual  revisions.  These  plans  are 
ultimately expected to deliver a longer-term vision and setting strategic priorities for future 
development. 

•  While  the  third  package  gives  the  necessary  powers  to  national  regulators  to  ensure 
implementation  of  investments  foreseen  in  the  binding  national  plans50,  no  provision  is 
made to ensure implementation of the European TYNDPs, which are non-binding plans51. 
However,  the  third  package  does  require  that  national  plans  are  consistent  with  the 
European  TYNDP  and  gives  the  Agency  a  monitoring  role  in  this  respect.  Enforcing 

47 Cf. article 38 of Directive 2009/72/EC and article 42 of Directive 2009/73/EC 
48 Cf. article 13 of Regulation (EC) No 714/2009 
49 Cf. articles 6 and 8 of Regulation (EC) No 713/2009 
50 Cf. articles 22 of Directive 2009/72/EC and Directive 2009/73/EC 
51 Cf. articles 8 of Regulation (EC) No 714/2009 and Regulation (EC) No 715/2009 

22

 
 
 
 
 
 
                                                 
realisation  according  to  the  planning  and  timing  foreseen  will  be  impossible  for  certain 
projects listed as being of European interest. 

The third package also asks national regulators to provide appropriate tariff incentives, both 
short and long term, for network operators to increase efficiencies, foster market integration 
and  security  of  supply  and  support  the  related  research  activities52.  Although  regulators 
furthermore will have an obligation to take into account the impact of their decisions on the 
internal EU internal market as a whole,  still, tariff setting remains national competence and 
hence not always conducive to advance European priorities.  
Furthermore,  this  regulatory  approach  is  not  designed  to  address  the  major  technological 
changes, notably in the electricity sector, concerning offshore or Smart Grids.  

As  demonstrated  above,  the  measures  adopted  and,  for  many,  still  to  be  implemented  will 
not be sufficient to ensure full delivery, given the lack of regulatory solutions to allocate costs 
and  cross-border  benefits  and  especially  the  obstacles  identified  in  chapter  2.3.  They  will 
resolve  some  coordination  issues  for  simple  cross-border  projects.  However,  they  may  not 
provide  sufficient  incentives  for  investments  in  public  goods  –  e.g.  gas  reverse  flow  or 
storage  for  security  of  supply  –  or  projects  with  information  asymmetry  –  e.g.  new 
technologies  or  innovative  solutions  (interconnected  offshore  grids,  smart  grid  applications) 
or  cross-border  projects  with  complex  cost  and  benefit  allocations  involving  several 
countries,  notably  in  gas,  where  no  inter-TSO  compensation  or  any  other  mechanism  to 
allocate costs for domestic investment to final beneficiaries outside the domestic territory has 
been established. Moreover, while the energy and climate policy goals adopted at EU level 
and  the  corresponding  support  schemes  for  renewable  energies  do  speed  up  their 
development,  they  have  also  a  distorting  effect,  notably  on  the  internal  electricity  market. 
Finally,  they  are  currently  not  matched  by  corresponding  measures  for  infrastructure 
development to ensure adequate grid integration. 

Finally,  both  the  internal  markets  for  electricity  and  gas  are  still  incomplete,  partly  due  to 
missing infrastructure53. Eastern Europe has inherited East-West gas infrastructures with little 
or no interconnections between neighbours. As the gas crisis in January 2009 showed, lack 
of infrastructure and insufficient transmission capacity were the main barriers to the handling 
of the crisis54. The new regulation on security of gas supply has just introduced a compulsory 
"N-1" rule for infrastructure, meaning that all Member States should be able to compensate 
the  disruption  of  the  single  largest  infrastructure  by  the  remaining  other  infrastructures  to 
ensure that total gas demand is met. An obligation to implement reverse flows was also set. 
In order to meet these standards, additional infrastructure needs to be constructed. However, 
such projects will not always be bankable under a business-as-usual scenario. 

In addition to traditional private financing on the basis of regulated tariffs, EU-funded support 
has  been  granted  to  current  TEN-E  projects  through  a  number  of  instruments,  such  as  the 
TEN-E budget, EEPR, IPA, ENPI (such as NIF or INOGATE) and loans from EIB and EBRD 
(see Annex 2 for more details). Under current rules – valid until 2013 –, EU TEN funding will 
continue to give small grants to finance feasibility studies or riskier projects, which may have 
an important EU-wide benefit. Interest rate rebates figure in the Regulation, but have never 
been  used  as  they  may  have  a  market  distorting  effect.  Projects  that  are  not  commercially 
viable  but  that  may  be  important  for  other  reasons  (security  of  supply,  market  integration, 

52 Cf. article 37 of Directive 2009/72/EC and article 41 of Directive 2009/73/EC 
53  In  electricity,  interconnections  have  historically  been  good  between  Eastern  European  Member  States,  which 
used  to  be  connected  synchronously  among  each  other  and  with  the  Russian  power  system.  Following 
disconnection  from  the  Russian  system  and  connection  to  the  synchronous  grid  of  continental  Europe  (i.e.  the 
grid of the Union for the Co-ordination of Transmission of Electricity / UCTE) in 1995, interconnections between 
East  and  West  have  developed  (e.g.  between  the  Czech  Republic  or  Poland  and  Germany),  but  certain 
bottlenecks remain as of today. 
54 SEC(2009)979 

23

 
 
 
 
 
 
                                                 
new  technology  or  innovative  solution),  would  not  be  constructed.  In  addition,  the  current 
policy  does  not  address  permitting  issues,  market  or  regulatory  failures,  the  mismatch 
between  national  and  European  priorities  and  the  need  for  strong  political  support.  This 
would  lead  to  insufficient  infrastructure  development.  Finally,  oil  and  CCS  infrastructure  as 
well  electricity  storage  and  smart  grid  technologies  would  remain  excluded  from  the  policy. 
No  new  electricity/gas projects  would  be  added  to  the  current  list,  non  feasible  or  outdated 
ones could not be removed. 

Concerning  CCS,  integrated  backbone  pipeline  networks  would  probably  be  the  most 
efficient  long-term  option,  but  the  incremental  cost  of  building  optimized  networks  ahead  of 
point-to-point  pipelines  may  not  satisfy  project-specific  commercial  evaluation  criteria. 
Concerning oil, the current supply situation, in particular with regard to Central and Eastern 
Europe,  is  satisfactory.  If  the  uninterrupted  and  smooth  flows  from  Russia  through  transit 
countries  could  not  be  ensured  in  the  future,  alternative  supply  routes  would  have  to  be 
explored,  either  through  existing  infrastructure  (Odessa-Brody  pipeline  in  Ukraine  or  Adria 
pipeline in Croatia) or through new West-East interconnections. However, the corresponding 
investments, which would then become necessary, are limited55. They are not regulated by 
EU legislation concerning e.g. rates of return or third-party access to infrastructure. 

2.5.  Main geographical bottlenecks 

In  the  business  as  usual  scenario,  the  main  bottlenecks  would  occur  in  the  below  listed 
regions  or  domains,  as  a  result  of  the  observed  future  energy  trends,  infrastructure  needs 
and combination of several of the identified obstacles: 

BEMIP (Baltic Energy Market Interconnection Plan) 

The three Baltic States – and in terms of gas also Finland – are practically isolated from the 
EU energy markets. In electricity, the Baltic energy grids are synchronously connected to the 
Russian  UPS  (Unified  Power  System).  As  of  today,  there  is  only  one  asynchronous 
interconnection to the West between Estonia and Finland. New connections are planned with 
Finland, Sweden and Poland, but not yet all realised. In gas, all four countries depend on a 
single supplier, and in most cases through one import route, which raises security of supply 
concerns.  This  same  supplier  also  has  a  stake  in  the  TSOs  of  the  countries.  With  no  real 
functioning market, cross-border and additional import infrastructure needs (such as LNG) to 
improve  market  integration  and  security  of  supply  cannot  be  met  by  market  demand. 
Coordination  between  Member  States,  TSOs  and  regulators  is  necessary  in  order  to  align 
regulatory  approaches  –  a  barrier  for  further  investments  and  market  opening  –  that  would 
allow a fair distribution of regional infrastructure development costs as well as benefits. 

Offshore grid in the Northern Seas 

Offshore  wind  is  expected  to  be  an  important  means  to  reach  the  EU’s  20%  renewable 
target. Potential for this energy source is mainly in the North Sea and neighbouring waters. 
At  the  same  time,  there  is  also  an  increased  need  for  interconnection  capacities  between 
countries  in  the  North  (e.g.  Norway,  Sweden)  and  Central  Europe  (e.g.  Germany,  the 
Netherlands),  both  for  more  electricity  trade  and  enhanced  security  of  supply.  This  creates 
the  need  for  an  integrated  offshore  grid  solution  both  to  connect  large  amounts  of  offshore 
wind and ocean energy capacities and to function as an international interconnector. 
The  creation  of  such  a  new  grid  is  subject  to  several  important  challenges:  coordination 
among  Member  States  and  entities  in  charge  of  planning  and  execution  (ministries, 

55 Concerning existing infrastructure, the cost for upgrading the Odessa-Brody pipeline capacity from 14.5 to 33 
million tons per year (mta) was estimated at about 450-500 million euros, while upgrading the Adria pipeline from 
9.8 to 14 mta would add another 70 million euros. Concerning new West-East interconnections, the Schwechat-
Bratislava  pipeline  for  example  would  require  about  50  million  euros  investment  for  up  to  a  capacity  of  5  mta. 
(calculations done by ILF and Purvin&Gertz). 

24

 
 
 
 
 
                                                 
regulators, TSOs, developers etc.); designing a new regulatory scheme; defining appropriate 
market  rules  for  multilateral  investments;  developing  appropriate  technical  standards  and 
operational solutions. 
So far, Member States have adopted different approaches to develop their national offshore 
wind potential and the corresponding grid. National regulation encourages radial connections 
of  wind  farms  with  an  onshore  connection  point,  to  maximise  benefits  while  minimising 
project  risks  and  costs  (see    Annex  4  for  more  details).  Under  these  conditions,  projects 
using innovative but riskier technologies (e.g. offshore voltage source conversion) and new 
grid  designs  involving  more  than  two  countries  are  difficult  to  realise,  preventing  further 
cross-border  optimisation.  Moreover, 
farm 
connections makes the anticipation of future development needs difficult, which might lead to 
increased overall cost and environmental impact in the long term. Integrated solutions such 
as a meshed offshore grid, associated with appropriate cost-benefit allocation mechanisms, 
are lacking, preventing the full benefits of both renewables connection and electricity trade to 
realise56. 
Such  a  grid  will  only  be  possible  with  strong  regional  or  even  European  level  coordination 
and  planning  and  the  necessary  technological  developments  (notably  concerning  direct 
current  (DC)  breakers  and  multi  terminal  control  systems).  The  need  for  this  coordinated 
approach  has  been  identified  by  the  countries  that  are  participating  in  the  North  Sea 
Countries Offshore Grid Initiative (NSCOGI)57. It is finally important to note that this offshore 
grid development, together with the onshore wind development near to the coasts, will trigger 
major  interconnection  requirements  with  existing  and  new  generation  and  hydro  pumping 
capacities both in the North (Norway, Sweden) and the Alpine region (Austria, Switzerland). 

individual  planning  and  building  of  wind 

Renewables in Southern Europe and the Mediterranean 

In  the  Southern  countries  of  the  EU,  solar  energy  will  offer  important  new  generation 
capacities, notably in France, Italy, Portugal and Spain. The role of solar electricity could still 
increase,  if  additional  generation  in  Mediterranean  third  countries  is  imported  into  the  EU 
through  interconnections  between  Morocco  and  Spain  or  Tunisia  and  Italy.  As  for  wind 
energy  in  the  North,  these  new  capacities  will  trigger  major  grid  reinforcement  and  new 
interconnection investment needs in this region, especially concerning the Spain-France and 
the  Italy-France,  Italy-Switzerland  and  Italy-Austria  links.  As  recent  experience  has  shown, 
development  of  additional  cross-border  infrastructure  in  the  regions  has  faced  major 
difficulties  in  reaching  public  acceptance,  leading  to  lengthy  authorisation  procedures  and 
costly  solutions.  Concerning  interconnectors  between  the  EU  and  third  countries,  problems 
arise from the often complex political situation. In addition, questions remain concerning the 
applicable regulatory framework. 

New supply sources – Southern Corridor 

The objective of the development of the Southern Corridor is to further diversify sources and 
to bring gas and oil from the Caspian Basin and the Middle East to the EU. The projects in 
the  Southern  Corridor  face  on  one  hand  the  necessity  of  coordination  between  several 
Member States and with non-EU members, the establishment of a legal regime to transport 
gas through these territories and on the other hand the challenge to co-ordinate the timings 
to  develop  the  up-stream  resources  and  necessary  infrastructure  with  the  timings  of  the 
import infrastructure projects. At the same time, this is also the opportunity for the European 
Union to enter closer energy partnership with Central-Asian and Middle-East countries. 

56 Currently the analysis is not done at regional or European level, where these synergies could be identified. An 
integrated  interconnector  /  offshore  wind  connection  solution  might  cause  different  proportion  of  costs  and 
benefits for the different actors. 
57  In  December  2009,  the  Political  Declaration  of  the  NSCOGI  was  signed  by  9  Member  States  (Belgium,  the 
Netherlands, Luxembourg, Germany, France, Denmark, Sweden, the UK and Ireland). Norway joined the initiative 
in early 2010. The 10 countries are aiming at signing a Memorandum of Understanding by the end of 2010. The 
mission  of  the  NSCOGI  is  to  facilitate  coordinated  offshore  electricity  infrastructure  development  with  a  joint 
commitment in view of large offshore wind power development in the region. 

25

 
 
                                                 
Central and South-East European interconnections 

Concerning  gas,  Central  and  Eastern  EU  countries,  as  well  as  South-East  Europe  (Energy 
Community  countries)  often  depend  on  one  single  import  source  and  hence  limited,  weak 
competition. Furthermore, they often depend on one single pipeline infrastructure both for oil 
and  gas.  Practically  all  of  the  problems  identified  in  chapter  2.3  converge  in  this  area:  no 
complete implementation of internal energy market rules, missing infrastructure development 
due  to  lack  of  market  development  and  vice  versa,  the  lower  creditworthiness  of  local 
companies  due  to  their  lower  capitalisation,  the  effects  of  the  economic  crisis  (thus 
deteriorating country risk ratings) and the higher exposure to external transit or supply risks. 
Furthermore, the investment need to meet the infrastructure standards set out in the security 
of gas supply regulation is very high in this region compared to the investment capacity of the 
concerned countries/companies, given current tariff levels and households’ ability-to-pay. 
Concerning  electricity,  challenges  arise  from  the  evolution  of  power  flows  and  the  need  for 
further  market  integration  in  the  countries  of  the  region.  North-South  flows  will  rise  in 
importance  as  new  generation  in  Bulgaria,  Hungary  or  Croatia  will  get  connected  to  the 
network. East-West interconnections could need reinforcement, as new systems (Turkey, but 
also  Moldova  and  Ukraine)  join  the  continental  synchronous  system.  Moreover,  these 
systems will have to be connected to the dominant storage capacities in the Alpine region. 

2.6.  Key players and affected population 

Various 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; 
•  Operators  and  developers  of  existing  and  new  power  plants  (including  CCS)  and 
electricity and gas suppliers, as a new policy will have an impact on the evolution of grid 
capacity; 

•  Member  State  governments,  administrations  and  regulators  who  will  be  in  charge  of 
implementing any new rules related to tariff regulation, financing, planning and permitting; 
•  Energy consumers, as optimised and smarter grids will contribute to better balancing of 

supply and demand and hence to reduced and less volatile energy prices; 

•  Citizens  in  the  neighbourhood  of  new  infrastructure,  that  might  be  affected  temporarily 

(construction) or permanently (local environmental or visual impacts etc.); 

•  EU  citizens  at  large,  as  a  new  policy  will  contribute  to  making  the  energy  system  more 
reliable, competitive and sustainable in terms of environmental and climate impacts. 

2.7.  EU right to act 

Under  Article  194  TFEU,  Union  policy  on  energy  shall  aim  at:  (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. Energy transmission infrastructure 
(including  an  interconnected  off-shore  grid  and  smart  grid  infrastructure)  has  Trans-
European, regional 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.  They  are  therefore  covered  under  Article  170  and  171  TFEU. 
Article 170 specifies that “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”. 

26

 
 
 
 
 
financing).  At 

in  January  2009, 

its  extraordinary  session 

The  Second  Strategic  Energy  Review  proposed  that  a  new  EU  Energy  Security  and 
Infrastructure  Instrument  should  be  tabled  to  replace  the  existing  TEN-E  framework  (policy 
and 
the  Transport, 
Telecommunications and Energy Council invited the Commission to "to carry out a thorough 
assessment  of  network  interconnection,  identify  gaps,  suggest  action  and  to  speed  up  the 
revision  of  the  TEN-E  framework  with  a  view  to  considering  the  development  of  a 
comprehensive  EU  Energy  Security  and  Infrastructure  Instrument  as  suggested  in  the  2nd 
Strategic Energy Review." At its March 2009 summit, the European Council concluded that 
“Energy  infrastructures  and  interconnections  must  be  developed.  To  that  end,  the 
Commission,  in  cooperation  with  Member  States,  is  invited  to  rapidly  present  the  detailed 
actions  required  to  realise  the  priority  areas  identified  in  the  SER.  […]  The  Commission  is 
invited  to  present  […]  its  proposal  for  a  new  EU  Energy  Security  and  Infrastructure 
Instrument.”  This  instrument  will  be  dealt  with  in  a  legislative  proposal  following  a 
communication on energy infrastructure priorities. 

Moreover,  the  Second  Strategic  Energy  Review  stated  that  "a  Blueprint  for  a  North  Sea 
offshore  grid  should  be  developed  to  interconnect  national  electricity  grids  in  North-West 
Europe  together  and  plug-in  the  numerous  planned  offshore  wind  projects."58  In  the 
conclusions  of  the  Energy  Council  on  19  February  2009,  the  plans  for  the  blueprint  were 
endorsed  with  the  small  change  that  the  scope was  changed  from  North  Sea  to  "the  North 
Sea  and  North  West  Offshore  Grid",  thus  clearly  covering  also  the  Irish  Sea.  In  its 
conclusions,  the  Council  also  agreed  to  "promote  a  co-ordinated  approach  between 
Commission  and  Member  States,  where  appropriate,  in  order  to  support  in  a  cost  effective 
way  large  scale  deployment  of  offshore  wind  power  in  the European  seas  while  preserving 
the reliability of the grid". 

More recently, the Europe 2020 strategy59 put again energy infrastructures in 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. It also highlighted 
the  need  to  promote  infrastructure  projects  of  major  strategic  importance  to  the  EU  in  the 
Baltic, Balkan, Mediterranean and Eurasian regions. 

3. 

OBJECTIVES 

The  general  objective  of  the  initiative  is  to  ensure  sufficient  and  timely  infrastructure 
development across the EU and beyond in order to: 

• 

further develop the internal energy market so as to ensure reliable energy provision at 
affordable prices to European customers,  

•  ensure security of supply, 
•  meet the EU’s energy and climate targets. 

In  order  to  sustain  infrastructure  development,  its  main  hindrances  are  to  be  tackled.  The 
planned Communication on infrastructure priorities hence has the objectives to propose clear 
priorities  and  improve  focus  of  EU  action  for  all  relevant  energy  infrastructure,  reinforce 
regional  co-operation  and  coordination,  highlight  the  difficulties  linked  to  permitting 
to  help  reducing  planning  and  permitting 
procedures  and  build  public  acceptance 
uncertainties. Clear infrastructure priorities will also provide a political message towards third 
countries.  

58 COM(2008) 781 p. 5 
59 COM(2010) 2020, 3.3.2010 

27

 
 
 
 
 
 
 
 
 
                                                 
The  abovementioned  objectives  are  fully  in  line  with  the  Europe  2020  strategy  and  in 
particular  the  "Resource  efficient  Europe"  flagship  initiative  and  support  directly  the 
achievement of the two binding targets of 20% share of renewables and 20% of greenhouse 
gas emission reductions by 2020. In addition, the uptake of smart grid technologies directly 
promotes  energy  efficiency.  The  objectives  are  furthermore  consistent  with  the  EU  policies 
on competitiveness and innovation. 

The  objectives  explained  above  are  consistent  with  the  Commission’s  on-going  work  to 
outline possible roadmaps for a transition to a low-carbon energy system by 2050. While the 
development of electricity and CO2 transport infrastructure is recognised as a key factor for 
success  under  almost  any  future  scenario,  uncertainties  concerning  future  gas  and  oil 
demand do not reduce the need for infrastructure development in the near term future60. 

4. 

POLICY OPTIONS 

In order to better analyse solutions to the main problems identified above, it is suggested to 
split the analysis in policy areas and propose separate options for each area (see Table 1). 
The  policy  options  are  evaluated  against  the  criteria  of  effectiveness,  subsidiarity  and 
proportionality.  The  main  criterion  for  effectiveness  is  how  much  adequate  infrastructure 
investment  the  single  options  are  likely  to  deliver.  All  the  options  are  coherent  with  the 
overarching  EU  objectives,  strategies  and  priorities.  Based  on  this  evaluation,  the  most 
effective and efficient options will be combined into a preferred policy set. 

Policy area A: Scope of the policy instrument 
Option 1: Business as usual (electricity and gas) 
Option 2: Enlarged electricity and gas 
Option 3: Enlarged electricity and gas, inclusion of CO2 networks and oil pipelines 
Policy area B: Design of policy instrument 
Option 1: Business as usual (project lists as today) 
Option 2: Updated project list 
Option 3: Limited number of priority projects/regional corridors and smart selection criteria 
Policy area C: Coordination 
Option 1: Business as usual (national approach, EU coordinators), voluntary regional 
structures 
Option 2: EU coordinators and mandatory regional or thematic priority structures 
Option 3: EU TSO 
Policy area D: Permitting 
Option 1: Business as usual (national competence), exchange of best practices 
Option 2: Inclusion of projects of European interest in national priorities and application of 
fastest national procedure (where existing) 
Option 3: National one-stop-shop approvals with streamlined time limits (5 years) 
Option 4: New harmonised permitting scheme at the EU level 

Table 1: Policy options 

60 Indeed, while the evolution of gas demand is uncertain until 2030 and even more so until 2050, gas is expected 
to have an increasing share until 2020, which is unlikely to drop dramatically after 2030 from a projected share of 
22.4%-24.3%  of  total  energy  demand  under  the  PRIMES  reference  scenario,  especially  if  carbon  capture  and 
storage  technologies  develop.  Similarly,  the  projected  oil  share  of  around  32%  by  2030  is  unlikely  to  drop 
drastically, especially considering its slow substitution in the transport sector. 

28

 
 
 
 
 
 
 
 
                                                 
4.1. 

Policy area A: Scope of policy instrument 

All  proposed  options  in  this  policy  area  are  considered  to  meet  the  subsidiarity  and 
proportionality principles. 

Option 1: Business as usual: electricity and gas 

This  option  would  cover  electricity,  gas  and  olefin  transmission  infrastructure,  gas  storage 
and liquefied natural gas (LNG) infrastructure, as is the case with the current TEN-E policy. 

Option 2: Enlarged electricity and gas 

Under this option, the electricity infrastructure targeted would be enlarged to cover also smart 
grids  and  storage  projects,  in  addition  to  the  traditional  transmission  projects.  Compressed 
natural gas (CNG) infrastructure would be added under the targeted gas infrastructure. This 
option can in principle be combined with all options of policy areas B, C and D. 

Option 3: Enlarged electricity and gas, inclusion of CO2 networks and oil pipelines 

This option would include electricity transmission, storage as well as smart grid technologies; 
gas pipelines, storage, LNG and CNG, as is the case in option 2. But it would also cover both 
CO2 transportation and oil pipeline infrastructure, thus overall energy transport infrastructure. 
This  option  can  in  principle  be  combined  with  all  options  of  policy  areas  B,  C  and  D. 
However, oil pipelines could a priori not be treated under option C3 (EU TSO, see below), as 
they are privately operated without central management through an independent TSOs. 

4.2. 

Policy area B: Design of policy instrument 

All  proposed  options  in  this  policy  area  are  considered  to  meet  the  subsidiarity  and 
proportionality principles. 

Option 1: Business as usual 

The  “business  as  usual”  option  would  mean  to  continue  with  the  TEN-E  policy  as  it  is, 
including  the  current  project  list  divided  into  three  categories  and  re-confirmation  of  the 
existing priority axes.  

Option 2: Updated project list 

Option 2 would mean to continue with the general TEN-E policy, but to revise and update the 
priority  projects  defined  in  the  annexes  of  the  decision  and  to  possibly  enlarge  the  scope 
under options 2 or 3 of policy area A (through ordinary legislative procedure). New projects 
would  benefit  from  political  support  and  an  EU  label,  as  is  the  case  in  the  current  TEN-E 
policy. 

Option 3: Limited number of priority projects/regional corridors and smart selection criteria 

This  option  would  propose  new  broad  priority  areas  and  regional  corridors  of  European 
interest,  focusing  on  the  main  bottlenecks  identified  (see  chapters  2.4  and  2.5),  thus  not 
fixing  a  list  of  projects  beforehand.  These  broad  priority  corridors  would  be  complemented 
with smart and transparent criteria for identifying projects in need of more focused attention 
at  the  regional  or  EU  level.  The  approach  is  based  on  a  European  top-down  (thematic  or 
regional)  perspective  rather  than  on  individual  projects.  This  differs  from  the  current 
approach laid down in the TEN-E guidelines, where the list of projects is fixed in the Annexes 
and has been identified bottom-up, reflecting Member States' national priorities. The criteria 
for  the  identification  of  projects  should  be  based  on  the  following  principles  and  further 

29

 
 
 
 
 
 
 
 
 
 
 
discussed  and  refined  with  relevant  stakeholders,  so  that  the  more  detailed  criteria  can  be  
included in the future legislative proposal61. 
Principles  to  be  applied  in  the  electricity  sector  would  cover  the  major  objectives  of  EU 
energy  and  climate  policy:  (1)  contribution  to  security  of  electricity  supply;  (2)  capacity  to 
connect renewable generation and transmit it to major consumption centres; (3) increase of 
market integration and competition; (4) contribution to energy efficiency and smart electricity 
use. 
The  principles  suggested  for  gas  infrastructure  are  derived  from  the  objectives  of  the  EU 
energy  and  climate  policy  to  improve  security  of  supply  and  market  development:  (1) 
diversification,  giving  priority  to  diversification  of  sources,  counterparts  and  in  last  place 
routes; (2) ratio of increase in interconnection level; (3) reduction of market concentration. 

4.3. 

Policy area C: Coordination 

Option 1: Business as usual 

This  option  would  continue  the  current  approach  based  on  largely  national  initiatives,  with 
support from EU coordinators and voluntary regional structures for certain projects. 

Option 2: EU coordinators and mandatory regional or thematic priority structures 

While maintaining the involvement of EU coordinators, existing regional structures would be 
given  the  task  of  identification  of  concrete  priority  projects  and  implementation  and 
monitoring  of  infrastructure  priorities  in  a  given  region  or  sector,  with  the  involvement  of  all 
relevant  stakeholders  (national  administrations,  National  Regulatory  Authorities,  NGOs  and 
TSOs).  A  compulsory  framework  would  ensure  that  there  is  a  regional  view  and  that 
approaches  do  not  remain  fragmented  at  national  level.  The  identification  of  the  priorities 
would be linked to the criteria referred to under option B3. 
There  is  already  mandatory  regional  co-operation  in  the  framework  of  the  internal  energy 
market  rules  (second  and  third  package)  in  various  areas:  regional  10-year  network 
development  plans  shall  be  prepared  by  the  TSOs  and  national  regulatory  authorities  co-
operate within the “regional initiatives”. The Regional Initiatives are currently under  revision 
and a new proposal is expected in 2011. The overall EU optimum would be ensured through 
the  already  existing  EU-level  institutions  such  as  ACER,  the  ENTSOs  and  regulatory  for  a. 
Building on the positive example of the BEMIP or the NSCOGI, the Commission may support 
ad-hoc regional co-operation on request, such as the Visegrad+ initiative to implement North-
South  interconnections  in  Central-Eastern  and  South  East  Europe.  This  solution  would 
simplify the cooperation, build on synergies with other discussion areas (defined in the third 
package) and reduce the number of fora and meetings for all stakeholders. The constitution 
of  regional initiatives  under  this  option  will  be closely  linked  to  the  identification  of  priorities 
under policy area B. 

Option 3: EU Transmission System Operator 

The idea of a single European TSO for gas was raised by a group of EU gas companies and 
outlined also in the Green Paper. The European Parliament concluded that "forward-looking 
initiatives,  such  as  the  European  transmission  system  operator  and  the  establishment  of  a 
single  European  gas  network,  should  be  encouraged"62.  The  aim  could  be  to  build 
progressively  independent  companies  to  manage  unified  transport  networks  throughout  the 
EU  in  gas,  but  also  in  electricity  or  CO2.  The  progressive  merging  of  national  networks, 
provided  that  it  is  organised  in  a  manner  compatible  with  competition  law,  would  allow 
looking at network development from a truly EU perspective and enhance incentives to invest 
in infrastructure where it is needed regardless of national boundaries.  

61  As  long  as  these  detailed  criteria  have  not  been  elaborated,  an  estimation  of  the  precise  number  of  projects 
qualifying or not qualifying under the new regime is not possible. 
62 European Parliament resolution of 3 February 2009 on the Second Strategic Energy Review (2008/2239(INI)) 

30

 
 
 
 
 
                                                 
An  EU  TSO  would  facilitate  more  regulatory  and  technical  standardisation  and  thus  allow 
energy to cross borders more easily. This could lead to a situation where national regulators 
would  not  any  more  be  capable  to  regulate  transmission.  A  European  regulator  would  be 
needed  –  a  future  role  that  could  be  played  by  ACER.  Such  a  solution  would  also  allow 
introducing “European transmission tariffs” to cover the TSO’s costs (and wider EU benefit). 
In  the  case  of  electricity,  such  a  TSO  could  also  be  charged  with  the  design  and 
implementation of integrated offshore grids or new European high-voltage long distance grid. 
For CO2, this would also allow the up-front planning of an optimal CO2 network. 
These single EU TSOs would have to take into account all objectives of the EU energy policy 
(market integration, security of supply and the climate goals). 
An EU TSO would become a monopoly and have a huge asset base. This would increase its 
creditworthiness and capacity to invest. To be a truly EU TSO, it should be given exclusivity 
over  infrastructure  development  in  the  EU,  which  would  eliminate  the  possibility  for  other 
market players to construct "merchant lines" dedicated to trade, where the owners reserve all 
or  part  of  the  capacity  for  their  own  use.  Past  experiences  for  strong  monopolies 
demonstrate, however, that such a TSO would need to be closely regulated and monitored 
with full transparency in order to make sure that transmission costs are correctly allocated to 
the users and to prevent abuse of its dominant market position. No individual supplier should 
be  allowed  to  acquire  a  controlling  stake  in  the  EU  TSO  in  order  to  maintain  its  neutral 
position and non-discriminatory approach on the market. 
It  is  also  considered  that  the  process  towards  an  EU  TSO  may  rather  take  place  on  a 
progressive and voluntary basis and that the Treaty does not provide the powers to impose 
this solution. This solution furthermore is unlikely to respect the principles of subsidiarity and 
proportionality,  as  strengthened  or  mandatory  regional  co-operation  and  infrastructure 
planning may lead to similarly effective results. Therefore this option is discarded from further 
analysis. 

4.4. 

Policy area D: Permitting 

Option 1: Business as usual: national competences, exchange of best practice 

In  this  option  (current  TEN-E  approach),  national  competences  would  be  maintained,  their 
obligation  being  to  make  best  efforts  to  facilitate  implementation  of  identified  TEN-E 
infrastructure.  They  would  be  enhanced  through  the  publication  of  national  best-practice 
measures. Member States would apply these measures on a voluntary basis. 

Option  2:  Inclusion  of  projects  of  European  interest  in  national  priorities  and  application  of 
fastest possible procedure (where existing) 

This  option  would  oblige  Member  States  to  include  projects  declared  to  be  of  European 
interest  (PEI)63  in  their  national  priorities  and  to  apply  the  fastest  existing  authorisation 
procedure  (where  these  exist).  The  principles  of  subsidiarity  and  proportionality  would  be 
respected as this option does not provide for concrete procedures, which would be left to the 
Member States. This policy option would be applicable only in Member States where national 
priorities  have  been  defined  and  where  “fast-track”  procedures  exist.  In  the  other  Member 
States, “business as usual” would be maintained.  

Option 3: National one-stop-shop approvals with streamlined time limits 

The  Presidency  of  the  European  Council  invited  the  Commission  in  March  2007  "to  table 
proposals  aiming  at  streamlining  approval  procedures"64,  and  industry  expressed  the  need 
for EU measures to facilitate permitting procedures. This option would introduce a "one-stop-
shop"  permitting  scheme  for  projects  of  European  interest,  under  which  all  Member  States 

63 NB: The definition of "project of European interest" could be revised and does not necessarily correspond to the 
currently used definition in the TEN-E guidelines. 
64 See European Council Presidency Conclusions of 8/9 March 2007, 7224/1/07 REV 1 

31

 
 
 
 
 
                                                 
would  have  to  nominate  a  national  contact  authority.  It  would  be  left  up  to  Member  States, 
whether this authority would have decision making powers or be a coordination body where 
decision-making  competence  would  remain  with  the  competent  authorities  at  national, 
regional, and/or local level. The one-stop shop would serve as a single interface between the 
project  developer  and  the  competent  authorities.  It  could  include  more  detailed  objectives 
and  specify  the  procedures  to  implement,  including  guidelines  for  public  consultations,  for 
minimum  transparency  requirements  and  for  compensation  of  affected  populations,  as  well 
as tacit approval or sanction mechanisms in case of delays. This option may ideally introduce 
a  time  limit  of  5  years65  for  a  final  authorisation  decision  to  be  taken  by  the  competent 
authority for a given project, feasibility of which still would need further assessment. 
The  introduction  of  a  one-stop-shop  would  facilitate  administrative  procedures  for  project 
developers, and a time limit would lead to accelerated authorisation and more certainty in the 
process.  Such  an  option  would  also  apply  to  all  Member  States,  not  only  to  those  where 
national strategies exist. Effects could further be enhanced by more specific guidelines. Tacit 
approval  or  sanction  mechanisms  would  incentivise  authorities  to  meet  the  timeline.  With 
respect  to  the  principle  of  proportionality,  a  legislative  proposal  would  introduce  general 
guidelines on the implementation of these measures. The concrete formulation of measures 
would still be left to the Member States, giving them freedom and flexibility how to meet the 
stipulated objectives. 

Option 4: New harmonised permitting scheme at EU level 

Option  4  would  create  a  new  harmonised  permitting  scheme,  based  on  some  of  the 
measures  as  outlined  under  option  3  (one-stop-shop  approach,  time  limit  for  final 
authorisation decisions), but with an aim at harmonising national approaches and giving final 
decision making power to the EU level in case problems cannot be resolved at Member State 
level. This should in certain cases allow overriding other interests on the basis of “European 
interest”, similarly to the “Déclaration d'utilité publique” (DUP) procedure applicable in certain 
Member  States.  The  impact  of  this  approach  would  be  substantial  because  of  the 
harmonised  and  hierarchical  decision  making  approach.  However,  this  policy  option  is 
unlikely to respect the principles of subsidiarity and proportionality, as the same results could 
be achieved by implementing option 3. Thus this option is discarded from further analysis. 

5. 

ANALYSIS OF IMPACTS 

We first analyse impacts for the business as usual (BAU) scenario, which includes the policy 
option 1 for each of the four policy areas. We then analyse the impacts of the different other 
options  sequentially  in  each  policy  area  A  (scope),  B  (design),  C  (coordination)  and  D 
(permitting) as compared to BAU. The impact analysis for all options is based on qualitative 
and,  where  available,  quantitative  evaluation,  covering,  as  relevant,  economic  (including 
administrative  and  compliance  costs),  social  and  environmental  aspects.  This  methodology 
will  allow  identifying  a  limited  number  of  policy  sets  for  further,  more  detailed  assessment 
and comparison. 

5.1.  Baseline ("business as usual") 

Under  business  as  usual  (BAU),  implementation  of  third  internal  market  measures  would 
help to resolve some of the identified problems in infrastructure planning and implementation 
of cross-border projects. The shortcomings of the current TEN-E instrument would however 
remain as such, with a focus on electricity and gas, rigid project lists, insufficient cross-border 
coordination  and  persistent  delays  in  permitting.  Nationally  focussed  and  for  technologies 
"conservative"  tariff-setting  would  still  render  certain  projects  commercially  not  viable  (see 

65 See recommendation of Priority Interconnection Plan (2007), COM(2006) 846 final/2, p.12f. 

32

 
 
 
 
 
                                                 
more  details  in  Box  2).  Moreover,  due  to  the  limited  amounts  of  available  EU  funding  and 
their  focus  on  studies  rather  than  works,  only  market  based  investments  would  take  place, 
i.e. investments that are commercially viable under current market and regulatory conditions. 
Planning  and  permitting  difficulties  would  lead  to  a  remarkable  mismatch  between  planned 
investments and investments actually carried out. 

Box 2: Methodology used for assessing the impact of identified problems on investment 

Quantifying the impacts of the problems identified under BAU is only possible to a limited extent, given 
the  complexity  of  electricity  and  gas  markets  and  corresponding  infrastructure  development.  It  was 
therefore  decided  to  limit  the  quantitative  analysis  of  impacts  for  this  study  to  the  following  two 
dimensions, whose impacts can be estimated, based on existing theoretical and empirical evidence: 
-  uncertainties  about  technologies,  imperfect  tariff  regulation  and  internal  market,  assessed  through 
their impact on the commercial viability of projects; 
- permitting, assessed through its impact on the realisation ratio of projects. 

Commercial viability 

While it is very difficult to circumscribe precisely the field of commercially viable projects in regulated 
markets  such  as  those  for  electricity  and  gas  transmission  infrastructure,  one  can  consider  in  a 
simplified  manner  that  an  investment  concerning  a  new  corporate  financed  asset  is  commercially 
viable if its cost-benefit analysis results lead the concerned TSO(s) to submit the investment project for 
approval  to  the  regulator,  for  a  given  set  of  market  and  regulatory  conditions  (related  to  future 
utilisation  rate  forecasts,  expected  congestion  rents  etc.  on  the  one  hand,  and  a  given  set  of  rules 
concerning the asset base, regulated rate of return, amortisation etc. on the other hand). 
Concerning project financed assets, commercial viability can also be tested through the ability of the 
project  to  secure  commercial  financing  (equity  and  debt).  One  can  further  consider  that  regulated 
investments, which are approved by the regulator but afterwards not implemented by the concerned 
TSO because the regulated rate of return for the project is considered too low, given its expected risk 
and return profile, are not commercially viable. 
Obviously,  the  field  of  commercially  viable  projects  is  a  function  of  the  applicable  regulation,  which 
itself  should  evolve  with  the  implementation  of  the  third  internal  market  package.  However,  as 
described  in  chapter  2.4.2,  the  definition  of  commercial  viability  applied  here  takes  already  into 
account these evolutions. 

Based  on  this  definition  and  the  investment  needs  analysis  carried  out  in  chapter  0,  infrastructure 
investment needs and effective investment under BAU for electricity for the period 2010-2020 were 
calculated as follows: 
•  70 bn€ for transmission infrastructure (source:  ENTSO-E), out of which 28 bn€ are assumed to be 

dedicated  to  cross-border  interconnections  (source:  KEMA).  It  was  assumed  that  these 
investments will be commercially viable, although, given problems related to cost-benefit allocation 
for complex cross-border projects, some of them might actually not be so. 

•  32bn€  for  offshore  grid  infrastructure,  based  on  an  estimated  40  GW  of  installed  offshore  wind 

generation capacity by 2020 (source: ENTSO-E, OffshoreGrid study). Given the technological and 
regulatory  uncertainties  and  the  lack  of  incentives  to  develop  optimised  grid  architecture,  it  was 
assumed  that  the  corresponding  investments  will  not  be  commercially  viable,  although  some  of 
them  will  happen  under  BAU.  One  must  also  note  that  first  results  from  the  OffshoreGrid  study 
indicate  that  overall  costs  for  connecting  offshore  wind  farms  and  interconnecting  electricity 
markets  across  the  Northern  Seas  could  be  reduced  with  an  optimised  integrated  grid 
infrastructure. 

•  40bn€ for smart grid infrastructure in distributio n and transmission networks (not related to smart 
metering).  Given  the  technological  and  market  design  uncertainties  as  well  as  the  lack  of 
incentives  for  individual  market  actors  to  develop  such  grid  infrastructure  on  their  own,  it  was 
assumed that 50% of this investment (20bn€) will not be commercially viable. 

Infrastructure investment needs and effective investment under BAU for gas for the period 2010-2020 
were calculated as follows (source: PRIMES / DG ENER analysis): 
•  28bn€ for import pipelines, out which an estimated 50% (14 bn€) will be built within the EU. It was 

assumed  that  intra-EU  investments  will  be  commercially  viable  under  current  market  und 
regulatory conditions. 

33

 
 
 
 
 
 
 
•  21bn€ for intra-EU interconnectors. It was assumed 

that intra-EU investments will be commercially 

viable under current market und regulatory conditions. 

•  21  bn€  for  storage.  It  was  assumed  that  about  1/ 3  of  these  investments  (7bn€)  will  not  be 

commercially viable under current market and regulatory conditions; 

•  1bn€ for reverse flow infrastructure. It was assumed that the corresponding investments will not be 

commercially viable under current market and regulatory conditions. 

Given the technological, regulatory and market uncertainties surrounding CO2 transport infrastructure 
and  the  lack  of  incentive  to  build  an  optimised  network,  it  was  assumed  that  none  of  the  estimated 
2.5bn€ of investment needed over the peri od 2010-2020 will be commercially viable. 

Realisation ratio 

The impact of delays in planning and permitting on the effective commissioning of projects has been 
analysed based on stakeholder consultations as well as on empirical evidence from the literature. The 
2005  "TEN-Energy-Invest"  study  concluded  that  the  ratio  “performed  investments”/”scheduled 
investments” could be as low as 60% for certain electricity TSOs. It is highly likely that this ratio has 
further  declined since, given the increased levels of local opposition and associated media focus on 
certain projects since 2005. This assumption seems to be validated when examining in detail the list of 
projects presented in the first TYNDP: despite conservative estimates for commissioning dates, delays 
are expected for about 20% of all projects identified and for about 50% of cross-border interconnectors 
in particular. 

For  gas  infrastructure  projects,  consulted  stakeholders  have  confirmed  that  planning  and  permitting 
problems  exist  but  are  less  acute.  Under  BAU,  it  was  therefore  assumed  that  the  realisation  ratio is 
50% of the total commercially viable investment for electricity and 90% for gas. 

Based on the analysis described in Box 2, the total investment need amounts to 142 bn€ for 
electricity, out of which about 90 bn€ are assumed to be commercially viable under current 
market and regulatory conditions. The total investment need is 71 bn€ for gas, with 63 bn€ 
assumed to be commercially viable. For CO2 transport infrastructure, the number is 2.5 bn€. 
Applying  the  assumptions  made  on  commercial  viability  and  realisation  ratios  under  BAU, 
electricity infrastructure delivery would reach about 30% (45 bn€ out of 142 bn€), while gas 
infrastructure  delivery  would  reach  about  80%  (57  bn€  out  of  71  bn€).  No  significant 
investment  would  take  place  for  CO2  transport  infrastructure.  These  figures  are  average 
figures  taken  as  reference  for  simplification.  In  terms  of  overall  economic  impacts,  BAU 
would  therefore  result  in  insufficient  and  sub-optimal  development  of  electricity  and  gas 
transmission  infrastructure,  with  an  estimated  investment  shortfall  of  113.5  bn€  over  the 
period 2010-2020, corresponding to an overall infrastructure delivery rate of only 47%. 

Error! Reference source not found. Table 2 below summarises these numbers: 

Sector 
(investment 2010-2020, bn€) 

Business-as-
usual delivery 

Commercially 
viable delivery 

Total need 

Electricity 

Gas 

CO2 transport 

TOTAL 

Investment gap 

Total (%) 

45 

57 

0 

102 

113.5 

47% 

90 

63 

0 

153 

62.5 

71% 

142 

71 

2.5 

215.5 

0 

100% 

Table 2: Business-as-usual, commercially viable and needed investment by sector 2011-2020 

34

 
 
 
 
 
 
 
 
 
 
Concerning electricity, transmission would continue to be optimised mainly at national rather 
than EU level, thus bearing significantly higher costs. For offshore grids in particular, certain 
projects would not be realised at all up to 2020, given delays and difficulties in the planning 
and permitting process, while for other projects, national, technologically mature and mostly 
radial  connections  to  shore  would  be  preferred  over  cross-border  or  technologically  more 
advanced  and  integrated  designs.  Concerning  onshore  projects,  planning  and  permitting 
delays  and  obstacles  due  to  the  imperfect  internal  market  would  affect  in  particular  cross-
border  connections,  maintaining  certain  transmission  bottlenecks  and  hence  congestion 
rents. Between 2006 and 2009, total congestion rents of 26 European electricity TSOs (EU-
27  without  CY,  MT  and  UK  plus  Norway  and  Switzerland)  have  varied  between  about  1.2 
bn€  and  1.95  bn  per  year 66.  The  energy  imbalances  between  Member  State  price  zones 
would  generate  price  differences,  leading  to  significant  social  welfare  impacts.  These 
differences  reached  in  2008  on  average  between  15  and  29  €/MWh  for  12  different 
interconnectors  linking  two  Member  States,  with  corresponding  welfare  losses  estimated  at 
over 3 bn€ 67. Increased price volatility and negative prices would be another consequence of 
insufficient transmission capacity in a given price zone. 
Concerning both economic and social impacts, risks of system instability would increase due 
to  higher  balancing  constraints,  leading  to  more  black-outs.  Despite  their  relatively  low 
probability,  research  shows  that  black-outs  have  unusually  costs,  notably  for  industry  or 
services  (production  shortfalls,  restarting  of  machinery,  and  damage  to  machinery  or  raw 
material)  or  households  (loss  of  food,  comfort  and  potentially  free  time).  For  the  case  of 
Germany, it has been estimated that overall costs could amount to 8-16 €/kWh, or about 30 
to  150  times  more  than  the  current  electricity  price68.  Therefore,  even  slightly  deteriorated 
security of supply could induce macroeconomic losses of several billion euros for this country 
alone69.  The  social  impacts  of  a  black-out  on  society  and  daily  life  were  felt  clearly  in 
November  2006  when  a  black-out,  originated  in  North-West  Germany,  struck  France, 
Austria,  Belgium,  Italy,  Spain  and  even  Morocco,  leaving  a  total  of  about  15  million  people 
without  electricity  for  up  to  two  hours.  Among  the  concrete  consequences  affecting  directly 
EU citizens were about 100 train delays in Germany and hundreds of passengers trapped in 
lifts in Paris due to the outage. 

Concerning  smart  grids,  BAU  would  lead  to  insufficient  development,  given  their  inherent 
risks,  with  associated  negative  impacts  in  terms  of  power  outages,  losses  in  the  electricity 
system  (technical,  e.g.  thermal  losses,  but  also  non  technical,  due  to  sub-optimal  systems 
planning  and  asset  management)  and  greater  difficulty  if  not  impossibility  to  integrate  an 
increasing  share  of  renewables  and  integrate  and  operate  grids  at  European-level.  But  it 
would  also  prevent  the  EU  from  benefiting  from  directly  quantifiable  positive  economic 
impacts:  The  French  regulator  CRE  has  estimated  that  with  the  implementation  of  smart 
metering  the  supplier  switch  capability  for  households  will  increase  by  a  factor  of  10  (50% 
instead  of  5%).  In  the  longer  term,  smart  grids  would  contribute  to  price  reductions  on  the 
electricity  market  by  increasing  transparency  of  supply  and  demand,  hence  reducing 
congestions,  optimising  system  flows  and  providing  the  information  needed  for  dynamic 
pricing.  Moreover,  the  Bio  Intelligence  Report  concludes  that  smart  grids  could  reduce  the 
EU’s  annual  primary  energy  consumption  in  the  energy  sector  by  almost  9%  by  202070, 
which equals to about 148 TWh of electricity. In 2010 prices, this amounts to annual savings 
of almost 7.5 bn€. 

66  European Commission consultation on an Inter-TSO Compensation Mechanism, 2008; ENTSO-E 
67  “Influence  of  National  and  Company  Interests  on  European  Electricity  Transmission  Investments”,  Study  by 
Matti Supponen, Helsinki University of Technology, August 2010 
68 German electricity prices were about 11c€/kWh for industry and 23c€/kWh for household customers during the 
second half of 2009 (Eurostat). 
69  “Hohe  Versorgungszuverlässigkeit  bei  Strom  wertvoller  Standortfaktor  für  Deutschland”,  David  Bothe  and 
Christoph Riechmann in Energiewirtschaftliche Tagesfragen, 10/2008 
70  Pilot  projects  with  smart  metering  in  various  European  Member  States  have  yielded  annual  reductions  of 
consumption between 5 and 15%. 

35

 
 
 
                                                 
Lack  of  sufficient  gas  infrastructure  would  increase  the  probability  of  supply  shortages  or 
supply disruptions, or limit the possibilities to mitigate actual supply disruptions, in a context 
of  decreasing  domestic  production  (all  over  Europe)  and  higher  import  dependency.  The 
example of the winter 2005/2006 in the UK illustrates the possible economic impact of supply 
shortages: due to higher prices, the extra cost paid by British consumers amounted to about 
2  billion  £71  (about  four  times  the  value  of  the  BBL  pipeline  between  NL  and  UK).  This 
shortage was mainly due to an infrastructure failure (storage burn) combined with insufficient 
import capacity to bring additional gas from other sources (through pipelines or LNG). 
The  economic  damage  caused  by  the  January  2009  gas  supply  disruption  in  South  East 
Europe  has  been  estimated  at  1.65  billion  € 72  for  Slovakia,  Hungary,  Croatia,  Serbia  and 
Bulgaria.  This  amount  is  by  far  higher  than  the  total  cost  of  all  reverse  flow  projects  and 
Central-Eastern European interconnector and storage projects included in the EEPR (around 
1.2 bn€), which could have mitigated the supply disruption had they been operational at the 
time  of  the  crisis.  It  was  mainly  inadequacies  in  gas  transport  which  constrained  flows 
(capacities, reverse flow capabilities, unusual routes, insufficient integration of gas networks 
in Central and South Eastern Europe), not lack of gas73. 
Social  impacts  on  consumers  could  also  be  significant,  especially  in  the  winter.  During  the 
January 2009 gas crisis, many Bulgarian households remained without heating for up to 48 
hours. While transit disputes, such as the one that lead to the above described crisis, have 
occurred on average 2  to 3 times each year in  Europe over the past years74, they resulted 
only twice (January 2006 and January 2009) in effective supply shortfall/disruption to the EU. 

Lack  of  infrastructure  would  also  increase  dependency  from  only  a  few  or  a  single  source 
and hence hinder market integration and competition, leading to higher prices. This can be 
demonstrated by looking at the price evolution at existing trading hubs. North-West Europe 
seems to be rather well integrated, as the prices of TTF (Netherlands), Zeebrugge (Belgium), 
Gaspool  or  Net-Connect  (Germany),  PEG  (France)  and  NBP  (UK)  generally  seem  to 
converge. However, the prices at the Italian PSV are constantly higher than the prices in the 
North-West. In Eastern Europe, liquid and transparent hubs are still under development (or to 
be developed), making the assessment of price differentials and missing links more difficult. 
However,  as  confirmed  by  stakeholder  consultations,  there  are  significant  price  differences 
between Central-Eastern European Member States75. These Member States (who joined the 
EU  in  2004  and  2007)  and  the  member  countries  of  the  Energy  Community  Treaty  are 
therefore those exposed to the highest risks in terms of supply shortage or disruptions, lack 
of market and integration and therefore possible negative economic and social impacts. 

Finally,  the  impacts  of  over-  or  under-investment  in  both  electricity  and  gas  infrastructures 
are  asymmetric.  As  the  cost  of  transmission  is  limited  in  the  final  energy  price,  over-
investment in infrastructure will cause only a limited increase of the final price76. But a lack of 
infrastructure  can  cause  energy  shortages,  disruptions  or  price  increases  with  far  higher 
economic  and  social  impacts.  For  electricity  in  particular,  transmission  on  average  only 
amounts to about 10% of overall electricity cost. Investing in more generation and/or back-up 
capacity to avoid energy shortages and black-outs would result in higher overall costs for the 
concerned  Member  States  compared  to  the  construction  of  interconnectors  to  obtain  EU-

71  "Crossing  Borders  in  European  Gas  Networks:  The  Missing  Links",  Clingendael  Energy  Paper,  September 
2009 
72 Estimates were provided by the concerned Member States to DG ENER. 
73 SEC(2009) 979 Impact Assessment of the gas security of supply regulation 
74 Such disputes arise for supplies coming from Russia through Ukraine, but also for those coming from Algeria 
through Morocco, the most recent one being the dispute between Belarus and Russia in July 2010. 
75 Note that even in the case of perfect interconnectivity and market integration, price differentials between distant 
regions would remain due to transport costs. However, prices should converge within a region if the market works 
well and sufficient interconnection capacities are available. 
76  For  gas,  transmission  costs  account  on  average  for  only  2-4%  of  the  final  gas  price  in  Western  Europe, 
although this share may be significantly higher in individual Member States, in particular in Eastern Europe. 

36

 
 
 
 
 
                                                 
wide or regional balancing, thus again increasing prices to final consumers. This effect would 
be  even  stronger,  if  missing  transmission  infrastructure  prevents  the  development  of 
renewable  generation  capacities  and  hence  favours  the  use  of  fossil  fuel  based  generation 
with higher fuel-dependent operating costs. This in turn could lead to increased problems of 
energy poverty for low income households, notably in Eastern Europe. 

Concerning CO2 transportation, the BAU scenario would prevent any significant investment 
in networks and give rise to piecemeal development (at project or national level) with a high 
risk  of  future  redundancy  or  bottlenecks  in  through-flow  capacity  (similarly  to  the  electricity 
and gas grids) and limited market integration with a risk of higher energy prices in the long 
term. 

Concerning environmental impacts, less infrastructure development would diminish negative 
local  impacts  for  those  directly  concerned  by  new  energy  infrastructure  projects,  both 
temporarily  (e.g.  during  the  construction  period  for  underground  gas  pipelines  or  electricity 
lines) and permanently (notably for overhead electricity lines or offshore grid infrastructure). It 
would also limit potential losses of biodiversity due to energy infrastructure crossing natural 
habitats.  However,  these  impacts  should  be  put  in  perspective  with  the  negative  global 
climate  impacts  generated  by  insufficient  infrastructure  development.  Under  BAU,  lack  of 
transmission  infrastructure  and  smart  grids  would  limit  the  possibilities  to  inject  electricity 
from renewable sources into the grid to reach final customers, hindering the achievement of 
the  20%  renewables  target  and  preventing  CO2  emission  reductions,  with  the  related 
consequences  on  the  climate  and  the  environment.  Concerning  renewables,  given  the 
difficulties  and  shortcomings  identified  above  for  offshore  grid  development,  it  is  estimated 
that  a  significant  share  of  the  32  bn€  of  investments  needed  for  offshore  connection 
infrastructure  by  2020  will  not  be  realised.  As  demonstrated  by  KEMA  and  confirmed  by 
ENTSO-E,  reaching  the  20%  renewables  target  in  2020  will  therefore  be  impossible,  given 
the  important  contribution  expected  from  offshore  wind  (over  12%  of  total  renewable 
electricity  production  in  2020  or  about  20%  of  the  additional  renewables  capacity  to  be 
installed between today and 202077). Concerning emissions, the Smart 2020 study estimates 
that  global emissions could  be  reduced  by  15%  thanks  to  smart  grids,  mainly  through  their 
contribution to energy efficiency. 
Similarly,  absence  of  sufficient  transportation  capacity  and  lack  of  interconnection  between 
CO2 producing sites in one Member State and CO2 storage sites in another Member State 
would slow down the uptake of CCS technologies, again maintaining higher CO2 emissions. 
Gas supply shortages or disruption due to lack of infrastructure or alternative sources (such 
as  LNG  or  CNG)  would  on  the  one  hand  lower  CO2  emissions  under  BAU,  as  less  gas  is 
consumed.  On  the  other  hand  however,  one  can  realistically  assume  that  gas  would  be 
replaced  by  other  more  emitting  fossil  fuels,  typically  oil  or  coal.  The  overall  effect  of 
insufficient gas infrastructure can be assumed to be higher CO2 emissions. 
This  environmental  impact  analysis  is  confirmed  at  the  macro-level:  cumulated  CO2 
emissions  for  the  EU  between  2010  and  2030  under  the  PRIMES  baseline  scenario 
(corresponding to BAU) are projected to be about 2,500 millions tons or over 3% higher than 
under  the  Reference  scenario,  where  all  necessary  infrastructure  is  supposed  to  be 
operational. 
In addition, the absence of additional energy infrastructures might also lead to negative local 
environmental  impacts  (e.g.  air  pollution),  due  to  longer  lifetimes  or  development  of  new 
capacities for non renewable, higher emission electricity generation capacities. In the case of 
oil  transport,  the  alternatives  to  bringing  additional  oil  to  the  EU  in  case  of  an  oil  supply 
disruption  would  be  an  increased  tanker  traffic  in  the  environmentally  sensitive  Baltic  Sea 
and the Bosporus to compensate a shortfall in the Druzhba pipeline system (the stop of the 
entire supply of this system would require to redirect approximately 60 million tons of crude 

77 DG ENER calculations 

37

 
 
 
 
                                                 
oil/per year78). Developing alternative supply routes would require investments, which might 
not happen without political support and awareness-raising at EU level. 

5.2. 

Policy area A: Scope of policy instrument 

From  the  impact  assessment  of  the  BAU  scenarios,  one  can  clearly  conclude  that  major 
positive impacts are expected at the economic and social level from extending the scope of 
the  policy  instrument  to  new  sectors  in  electricity  (smart  grids  including  storage)  and  gas 
(CNG), but also to CO2 transportation. This would address some of the uncertainties and the 
shortcomings  of  the  current  TEN-E  framework,  outlined  in  Chapter  2.3.  Moreover,  by 
focussing  attention  on  new  technologies  such  as  smart  grids,  electricity  storage  or  carbon 
capture  and  storage,  extending  the  scope  would  also  foster  innovation  in  these  fields.  The 
extension to oil would also provide positive environmental impacts, by ensuring diversified oil 
supply routes to the EU to reduce the environmental risk related to increased tanker traffic on 
the  Baltic  Sea  and  in  the  Bosporus.  Nevertheless,  these  would  be  limited  to  countries  in 
Central  and  Eastern  Europe  supplied  through  the  Druzhba  pipeline  system.  Including  all 
these new sectors in the scope of the policy instrument (option A3) is therefore the preferred 
option. 

5.3. 

Policy area B: Design of policy instrument 

Compared  to  BAU  with  a  fixed  and  rigid  project  list  defined  in  2006,  the  update  of  this  list 
(option B2) based on an enlarged scope (option A3) would allow taking into account new or 
changed priorities in terms of infrastructure development. This improved focus would have an 
overall  positive  impact,  but  would  maintain  the  rigidity  of  a  project  list,  which  might  again 
need adaptation in the future up to 2020 and beyond.  
By  contrast,  a  complete  reform  of  the  current  approach  (option  B3),  with  a  very  limited 
number of broad priorities of European interest, no ex ante list of priority projects and smart 
and  transparent  selection  criteria  instead  of  the  current  three-tiered  categorisation  of 
projects, would yield far bigger positive economic, social and environmental impacts. Indeed, 
this  option  would  allow  focussing  all  attention  on  those  priorities,  which  are  of  major 
European  interest  and  for  which  EU  intervention  will  be  most  beneficial,  or  on  areas  with 
strong  innovation  and  high  positive  environmental  impacts  such  as  renewables’  integration 
into the grid, smart grids, storage or CO2 transport. More generally, this approach based on 
European  priorities  would  draw  attention  on  economic  and  environmental  trans-boundary 
and regional effects, while option B2 would be influenced more by national or even local level 
effects.  Establishing  smart  and  transparent  selection  criteria  would  minimise  possible 
distorting  effects  on  the  internal  market,  by  designing  rules  that  are  in  line  with  current 
legislation  and  regulation.  It  would  also  allow  evolution  over  time  of  the  concrete  support 
given  to  projects,  optimising  the  use  of  the  policy  instrument  even  in  the  longer  term.  It  is 
therefore considered to be the preferred option. 
Transition from old guidelines projects list to new priorities and projects: 
- Some projects are implemented or well underway (will be implemented by 2014). 
- Some projects have been abandoned (proved unfeasible or uninteresting). 
- Some will be taken up under the new priorities (if identified so by the respective regions). 
- Projects, which lose their status acquired under the former guidelines, will do so because 
they are not of European, but of national or sub-regional interest, and should be promoted at 
these respective levels. 

78 "Technical aspects of variable use of oil pipelines coming into the EU from third countries", feasibility study by 
ILF and Purvin & Gertz 

38

 
 
 
 
 
                                                 
5.4. 

Policy area C: Coordination 

As seen in chapter 2.2 and 2.3, the current TEN-E design with voluntary regional structures 
and  EU  coordinators  has  not  provided  all  the  necessary  incentives  for  effective  regional 
coordination and rapid implementation of cross-border infrastructure projects. Option C2 with 
mandatory  regional  structures  and,  where  necessary,  EU  coordinators,  would  have 
significant  positive  impacts  in  terms  of  infrastructure  development  and  is  therefore 
considered  as  the  preferred  option  compared  to  BAU.  These  regional  structures  would  be 
particularly positive for projects with a clear regional delimitation such as the offshore grid in 
Northern Europe or the development of a gas corridor in South-Eastern Europe. They would 
also  contribute  positively  to  market  integration  and  better  functioning  of  regional  markets. 
Their negative impacts in terms of administrative burden would be very limited to the meeting 
and coordination requirements created for various actors (national governments, regulators, 
TSOs, energy companies) through the newly established or extended regional structures. As 
existing regional structures, for example the so-called Regional Initiatives, would be used for 
this task, no additional administrative costs are expected. 

5.5. 

Policy area D: Permitting 

Both measures would introduce more efficiency in the decision making process by clarifying 
existing  rules  and  ways  or  recourse,  optimising  the  number  of  steps  needed  for  a  given 
decision to be taken and reducing as much as possible delays for each of these steps. While 
BAU  is  expected  to  lead  to  very  limited  streamlining  and  acceleration  of  permitting 
procedures  only,  option  D2  would  allow  an  accelerated  treatment  for  European  priority 
projects in those countries where priorities have been defined or where fast-track procedures 
exist.  It  is  considered  that  this  would  partially  shorten  the  delays  observed  under  BAU  and  
allow improving infrastructure delivery significantly in the electricity sector by raising the ratio 
"performed  investments"/"scheduled  investments"  for  the  period  2010-2020  from  50%  to 
75%.  In  the  gas  sector,  the  effect  would  be  more  limited  (from  90%  to  95%).  This  would 
considerably increase infrastructure investment from 102 bn€ under BAU to 130 bn€ over the 
period 2010-2020. 
The  one-stop-shop  approach  (option  D3)  however  would  further  facilitate  administrative 
procedures  and,  combined  with  the  limit  of  5  years  for  a  final  authorisation  decision  to  be 
taken by the authority for a given project, accelerate permitting and increase project delivery 
compared to the investment needs. It is assumed that 100% of the scheduled market based 
investments  in  electricity,  gas  and  CO2  transportation  would  be  realised  during  the  period 
2010-2020. The additional investment due to option D3 would be about €53bn compared to 
BAU, further increasing infrastructure investment to 155.5 bn€, with most of the contribution 
coming  from  the  electricity  sector,  where  the  problems  due  to  delays  in  planning  and 
permitting are biggest.. 

The table below summarises the realisation rates assumed under BAU and with both options 
D2 and D3: 

Sector 

Selected scenarios 

Realisation rate    
assumption  
(% of total investment1) 

business as usual (D1) 

Electricity 

fastest national procedure (D2) 

one-stop-shop (D3) 

Gas 

business as usual (D1) 

50% 

75% 

100% 

90% 

39

 
 
 
 
 
 
 
Sector 

Selected scenarios 

Realisation rate    
assumption  
(% of total investment1) 

fastest national procedure (D2) 

one-stop-shop (D3) 

95% 

100% 

Table 3: Realisation rates under different scenarios (2010-2020) 

Concerning  the  macroeconomic  impacts  assessed  using  the  E3ME  model,  both  options 
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-
2020 for option D3 (see Annex 3 for more details). This would correspond to a net cumulative 
increase in GDP of about 8.8 bn€ over the period 79. The positive impact of option D2 would 
only  be  about  half  (+0.22%  of  GDP,  about  150,000  additional  jobs).  In  any  case,  the 
additional  investment  made  possible  would  have  positive  impacts  on  small  and  medium 
enterprises,  through  the  need  for  more  employment  generated  in  construction,  mechanical 
engineering  and  business  services.  This  would  in  turn  increase  incomes  and  household 
spending, confirming the positive social impacts of the policy.  

industry 

to  BAU.  The 

repeatedly  pointed  out 

Contrary to  policy areas A and B and C, policy area D  would have considerable impact on 
for  both  companies  and  national 
the  administrative  burden  and  compliance  cost 
administrations  compared 
reduced 
administrative burden as a major desired change. Option D2 would simplify procedures and 
reduce  administrative  burdens  only  for  projects  in  those  Member  States,  where  national 
priorities and fast-track procedures exist. The national "one-stop-shop" of option D3 however 
would reduce the amount of interlocutors for project promoters to a single identified authority 
per Member State, as opposed to the current situation where the number of authorities can 
reach up to 20, yielding the largest positive administrative impact. It must be noted however 
that,  while  option  D2  is  assumed  to  be  easy  to  comply  with,  option  D3  would  create 
compliance  costs  for  Member  State  governments  in  terms  of  national  transposition  of  new 
rules, re-design of existing permitting procedures and re-organisation of authorities in charge 
of these procedures. While this option would also necessitate more administrative resources 
to  process  permitting  for  projects  of  European  interest,  it  is  not  considered  that  this  would 
lead to crowding out effects when compared to the processing of national projects, given the 
limited number of projects concerned. 
Concerning environmental impacts, it must be underlined that both options D2 and D3 do not 
aim at reducing environmental standards for the evaluation of energy infrastructure projects. 
The  compliance  with  EU  environmental  legislation  is  extremely  important  for  the  smooth 
implementation of energy infrastructure projects. All projects, if so required, will be subject to 
the appropriate environmental assessment in accordance with existing EU legislation (mainly 
SEA  directive80,  EIA  directive81  Habitats  directive82  and  Water  framework  directive83),  as  is 
already the case in the current TEN-E guidelines. As a result, certain projects might have to 
change  their  technology  choice  (e.g.  from  overhead  line  to  underground  cable  or  special 
measures  for  gas  pipelines  in  order  to  be  able  to  cross  Natura  2000  sites;  direct  current 
instead  of  alternating  current  to  reduce  the  size  of  power  poles).  Others  would  have  to 
change  their  routing  or  to  adopt  measures  in  order  to  prevent  and  mitigate  the  possible 

79  Based  on  2000  prices,  the  cumulative  investment  taking  place  under  business  as  usual  between  2011  and 
2020 is about 73.9 bn€ (down from 89 bn€ in 2008 prices),
 while it is 117.8 bn€ under S1, yielding a difference of 
43.9  bn€.  Comparing  this  number  to  the  cumulative   annual  GDP  increase  of  52.7  bn€,  one  obtains  the  net 
absolute GDP impact in 2000 prices. 
80 Directive 2001/42/EC on the assessment of the effects of certain plans and programmes on the environment 
81 Directive 85/337/EEC on the assessment of the effects of certain public and private projects on the environment 
82 Directive 92/43/EEC on the conservation of natural habitats and of wild fauna and flora 
83 Directive 2000/60/EC establishing a framework for the Community action in the field of water policy 

40

 
 
 
 
 
 
                                                 
adverse  effects  on  the  environment  or,  if  not  possible,  to  compensate  negative  impacts,  in 
particular on the conservation objectives and integrity of Natura 2000 sites.  

Following this assessment, it is considered that option D3 would be the most effective, while 
option D2 would imply lower compliance costs at Member State level. 

However,  the  Communication  covered  by  this  impact  assessment  will  only  consider 
principles  to  make  permitting  procedures  more  efficient  and  transparent,  whereas  concrete 
rules to achieve this in the Member States will only be proposed in the Energy Security and 
Infrastructure  Instrument  to  be  tabled  in  2011.  A  more  detailed  impact  assessment  will  be 
prepared  for  this  instrument,  providing  for  an  in-depth  assessment  of  the  different  policy 
options with regard to the sectors covered, their compatibility with national legal systems and 
their  compliance  with  the  principle  of  subsidiarity,  taking  into  account  the  importance  of 
transparency  and  public  acceptance.  It  will  also  include  an  analysis  of  the  administrative 
burden  and  compliance  costs  for  each  policy  option.  It  must  be  noted  that  these  rules 
concerning  permitting  will  only  cover  electricity  transmission  infrastructure  as  well  as  gas 
infrastructure  transmission  and  storage  infrastructure.  Smart  grid  projects,  which  do  not 
involve  large  visible  infrastructure  investment  with  high  environmental  impacts,  and  CO2 
transport projects, which will see only limited investment up to 2020, should not be covered 
under these new rules. 

In  view  of  the  next  impact  assessment,  a  study  has  been  launched  and  will  deliver  first 
results  by  May  2011.  The  study  will  analyse  the  legal  and  regulatory  framework  as  well  as 
the effective practice concerning planning and permitting for electricity and gas infrastructure 
(covering spatial planning, environmental protection and public consultation rules), on which 
procedures and decisions are based. It will in particular assess the number and tasks of the 
authorities involved during each step of the permitting and licensing for typical infrastructure 
projects, as well as their respective level (local, regional, national). 

Based  on  this  analysis,  the  study  will  make  recommendations  for  improving  the  existing 
legal, regulatory and incentive framework at EU level, taking into account differences in the 
Member  States,  notably 
local  acceptance.  The 
recommendations  will  pay  due  respect  to  the  impact  of  the  solutions  proposed  in  terms  of 
simplifying  and  accelerating  permitting  procedures,  and  their  viability  in  terms  of  how 
administrations will be able to implement them technically and legally. The recommendations 
will further be reflected against the principles of proportionality and subsidiarity. 

legal  systems  and 

terms  of 

in 

to 

the  study,  extensive  stakeholder  consultations, 

In  addition 
involving  national 
administrations,  TSOs  and  NGOs  are  foreseen.  A  dialogue  with  representatives  from 
Member  States  where  accelerated  procedures  have  been  or  are  about  to  be  implemented 
has been initiated to enquire about best-practices and compliance costs incurred. 

6. 

COMPARISON OF POLICY OPTIONS AND CONCLUSION 

The four different policy areas, with between 2 and 3 maintained policy options for each, can 
be combined in numerous ways. In addition to BAU (analysed in the previous chapter), there 
are 8 possible policy sets combining different policy options in each area: 2 in area A, 2 in 
area B, 1 in area C and 2 in area D. However, the impacts of the different options within one 
policy area can be independent of those of another policy area. On the one hand, the scope 
of the policy instrument (policy area A) does not influence the effectiveness of the design of 
the instrument (policy area B); and the coordination between regional players (C) will impact 
each  sector  independently  of  the  number  of  sectors  targeted  (A).  On  the  other  hand,  while 
the  impacts  of  the  different  permitting  schemes  (D)  on  the speed  of  project  implementation 
will not be affected by a variation in scope (A), it is likely that certain permitting policy options 

41

 
 
  
 
 
 
 
 
will  be  more  effective  if  combined  with  certain  options  of  policy  instrument  design  (B)  or 
coordination (C). 

The following table summarises the main impacts of each maintained policy option presented 
in chapter 5 in terms of economic, social and environmental impacts: 

Economic impacts 

Social impacts 

Environmental impacts 

A: Scope 

(due 

development 

case  of  oil 

-  higher  air  pollution  and 
to 
CO2  emissions 
limited 
of 
renewables, 
smart  grids, 
CCS) 
-  higher  environmental  risks 
in 
supply 
disruption  (due  to  increased 
oil tanker traffic) 
-  higher  air  pollution  and 
CO2  emissions 
to 
limited development of CCS) 
-  higher  environmental  risks 
in 
supply 
disruption  (due  to  increased 
oil tanker traffic) 
-  air  pollution  reduction  and 
less CO2 emissions 
-  more 
and 
negative  local  environmental 
impacts  (due  to  additional 
infrastructure development) 

case  of  oil 

nuisance 

(due 

nuisance 

- 
local 
environmental 
limited 
- more CO2 emissions 

and 
impacts 

and 

-  negative  impacts  on  both 
gas 
electricity 
consumers  in  case  of  black-
outs/shortages 
-  energy  poverty  due 
higher energy prices 

to 

- slightly reduced impacts as 
compared to B1 

-  slightly  diminished  effects 
as compared to B1 

-  reduced  security  of  supply 
risks  and  lowering  effect  on 
energy  prices  beneficial  to 
final consumers 

-  increased  local  nuisance 
and environmental impacts 
- lower CO2 emissions 

A1 

A2 

for 

-  more  power  losses,    more 
energy consumption and less 
transparency 
the 
consumer  due  to  insufficient 
smart grid 
-  limited  innovation  in  new 
as 
technologies 
electricity 
smart 
grids, CCS 
- slightly diminished negative 
impacts  compared 
to  A1, 
notably  for  new  technologies 
grids, 
such 
electricity storage and CNG 

storage, 

smart 

such 

as 

A3 

-  best  coverage  of  all 
sectors,  in  line  with  energy 
and climate policy objectives 

B: Design 

B1 

B2 

B3 

to 

insufficient 

- 
adequate 
transmission  and  storage 
capacity 
rigid, 
due 
suboptimal  priority  setting, 
leading  to  congestion  rents, 
price 
price 
differences, 
volatility 
-  increased  risk  of  electricity 
black-outs  or  gas  supply 
shortages / disruptions 
-  reduced  impacts  compared 
to  B1,  due 
to  slightly 
improved priority setting 
-  significant  positive  impacts 
(price 
on 
convergence,  lowering  effect 
on  prices)  and  security  of 
supply 
-  significant  development  of 
renewables, 
smart  grids, 
electricity  storage  and  CCS, 
in 
line  with  energy  and 
climate policy objectives 

market 

C: Coordination 

42

 
 
 
 
 
 
 
 
 
C1 

C2 

insufficient  cross-border 
- 
infrastructure 
investment, 
insufficient market integration 
and bigger risks to security of 
supply 

more 

cross-border 
- 
infrastructure 
development 
and  optimised  design,  better 
(regional) market integration 
-  very  limited  administrative 
burden 
various 
for 
stakeholders 

D: Permitting 

D1 

D2 

D3 

- 
significant 
infrastructure 
insufficient development 

delays 

in 
delivery, 

delays 

in 
delivery, 

- 
reduced 
infrastructure 
improved development 
-  positive  effect  on  GDP 
(+0.22%  over 
the  period 
2010-2020) 
- limited administrative cost 
- full delivery of commercially 
viable infrastructure projects 
-  significant  positive  impact 
on GDP (+0.42%) 
-  less  administrative  cost  for 
operators 
-  significant  compliance  cost 
for national administrations 

and 

-  negative  impacts  on  both 
electricity 
gas 
consumers  in  case  of  black-
outs/shortages 
-  energy  poverty  due 
higher energy prices 
-  reduced  security  of  supply 
risks  and  lowering  effect  on 
energy  prices  beneficial  to 
final consumers 

to 

impact  on 

-  positive 
job 
creation  (+150,000  over  the 
period 2010-2002) 

nuisance 

local 
- 
environmental 
limited 
- more CO2 emissions 

and 
impacts 

-  more  CO2 
emission 
reduction (e.g. through focus 
on offshore grids, CCS) 

nuisance 

and 
impacts 

- 
local 
environmental 
limited 
- more CO2 emissions 
-  more  local  nuisance  and 
environmental  impacts  than 
in D1 
-  CO2  emission 
compared to D1 

reduced 

-  significant  positive  impact 
on  job  creation  (+410,000) 
and, 
lesser  extent, 
SMEs 

to  a 

-  more  local  nuisance  and 
environmental  impacts  than 
in D2 
-  CO2  emission 
compared to D2 

reduced 

As summarised above, the combination of options with the largest positive impacts would be 
A3,  B3,  C2  and  D3,  noting  that  the  policy  area  of  permitting  will  still  have  to  be  analysed 
more in depth. While BAU would lead to only 102 bn€ of investment, leaving an investment 
gap of 113.5 bn€, the most effective policy set as described above would significantly raise 
infrastructure  delivery,  with  an  investment  level  of  155.5  bn€.  Our  analysis  also  shows  that 
this policy set would be most beneficial in economic, social and environmental terms. 

It must however be noted that even the most effective policy set would deliver 60 bn€ less 
than  the  identified  investment  need  of  215.5  bn€.  Indeed,  the  mere  enlargement  of  the 
scope,  as  well  as  the  proposed  reforms  on  the  design  of  the  policy  instrument,  regional 
cooperation  structures  and  permitting,  will  not,  ceteris  paribus,  close  the  remaining  huge 
investment  gap  and  will  not  make  those  projects  bankable,  which  are  commercially  non 
viable  under  BAU  market  and  regulatory  conditions.  This  applies  in  particular  to  certain 
cross-border electricity grid, smart grid84 and offshore grid infrastructure, to gas cross-border, 
reverse  flow  and  storage  infrastructure  and  to  certain  CO2  transport  infrastructure.  At  the 
same time, the potential for tariff increases to be able to create the regulatory conditions to 

84 First studies and experiences do highlight the long-term economic viability of smart metering deployment alone. 
The  UK  Department  for  Energy  and  Climate  Change  (DECC)  has  estimated  that  fitting  26  million  homes  with 
smart meters by 2020 would cost over 8 bn £. But this cost would be more than compensated for by 14.5 bn £ of 
savings  in  operational  costs  for  power  companies  and  lower  bills  for  customers.  However,  the  corresponding 
"smart" investments on the grid are not currently covered by the market. 

43

 
 
 
 
 
 
 
 
                                                 
cover these investments is limited, given the investment amounts at stake85. Therefore, one 
could  expect  significantly  higher  positive  impacts  under  a policy  set  using  public funding  or 
dedicated  regulatory  measures  to  enable  the  implementation  of  all  projects  of  European 
interest, including those, which are not commercially viable86. Establishing principles for the 
cost-allocation  across  borders  could  solve  the  issues  where  the  commercial  viability  of  a 
project  is  due  to  its  uneven  cost-benefit  allocation  to  users.  Regulators  could  agree  on 
common  principles  in  relation  to  cost-allocation  of  interconnection  investments  and  related 
tariffs. In electricity the development of long term forward markets for cross-border capacity 
should  be  explored,  whereas  in  the  gas  sector  the  investments  costs  could  be  allocated  to 
TSOs in neighbouring countries, both for normal (based on market-demand) investments as 
well as those motivated by security of supply reasons. The Commission plans to put forward, 
in 2011, a proposal or guidelines to address cost allocation of major technologically complex 
or  cross-border  projects,  through  tariff  and  investment  rules.  Where  a  higher  rate  of  return 
would  be  required  to  match  the  project  risks  and  thus  make  them  bankable,  a  regulatory 
approach could also be envisaged. Public funding could be explored for those areas, where 
the  above-mentioned  measures  would  fail.  However,  this  needs  detailed  further  analysis 
which will be included in the Impact Assessment to be prepared for the EU Energy Security 
and Infrastructure instrument. 

7. 

MONITORING AND EVALUATION 

Specific indicators to monitor the evolution of the policy will be:  

•  The  number  of  projects  constructed,  under  construction  or  commissioned  by  given 
target  dates  such  as  2015,  2020  and  2030,  compared  to  the  number  of  projects 
identified  as  being  of  European  interest.  This  indicator  could  also  be  measured  in 
terms  of  installed  capacity  and  length  of  new  power  lines  or  gas  pipelines  and 
capacity of other new electricity and gas infrastructure (storage, LNG/CNG). 

•  To measure diversification of gas imports: the share of each import source and their 
concentration  within  the  overall  import  (at  national,  regional  and  EU  level),  for 
example through the Herfindahl index87. 

•  To measure the integration of renewables: the share of (variable) electricity produced 
from  renewable  sources  in  the  overall  electricity  generation.  This  will  be  monitored 
through the bi-annual reports Member States must submit to the Commission under 
article 22 of the renewables directive. 

•  To  measure  market  integration:  the  interconnection  level  between  Member  States 
and  the  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,  prices  at  major  European  hubs  could 

85 There are strong signs that energy prices will increase in the short and medium term to respond to changes in 
the EU's energy system. In comparison to investments linked to increased electricity generation from renewables 
and  investments  in  distribution  grids,  the  impact  of  grid  investments  is  forecasted  to  be  minor.  ENTSO-E  has 
calculated that 100 bn € of transmi ssion investment over the period 2010-2020 would represent only about 2% of 
bulk power prices. However, the combined impact of all needed investments on prices could be significant. The 
UK energy regulator (OFGEM) for example has calculated that prices could increase over the next 10 years by as 
much as 25%, while France has discussed a price increase of 20% over three years during 2009. 
86 The E3ME model confirms that such funding, if compensated e.g. by a small increase in direct taxation rates, 
would be revenue  neutral at  macroeconomic level compared to full funding of  all the investment through higher 
energy prices. 
87 The Herfindahl index, also known as Herfindahl-Hirschman Index or HHI, is a measure of the size of firms in 
relation to the industry and an indicator of the amount of competition among them. It is defined as the sum of the 
squares  of  the  market  shares  of  the  50  largest  firms  (or  summed  over  all  the  firms  if  there  are  fewer  than  50) 
within the industry, where the market shares are expressed as fractions. The result is proportional to the average 
market share, weighted by market share. As such, it can range from 0 to 1.0, moving from a huge number of very 
small firms to a single monopolistic producer. 

44

 
 
 
                                                 
be  used.  Price  monitoring  is  already  being  done  by  DG  ENER’s  Energy  Market 
Observatory. 

•  To  measure  the  adoption  of  smart grid  technologies:  the  share  of  grid  infrastructure 
(including 
lines,  converter  stations,  substations  etc.)  equipped  with  new 
communication technologies compared to the total infrastructure for a given TSO as 
well  as  the  number  of  electricity  costumers  having  signed  up  to  smart  grid  enabled 
services. 

•  To measure security of supply of gas: the compliance with the N-1 and reverse flow 

standards will be monitored under the security of gas supply directive. 

•  To  measure  progress  concerning  permitting:  the  average  duration  of  authorisation 
procedures  for  projects  of  European  interest  compared  to  the  average  duration  of 
procedures  for  all  infrastructure  projects.  This  activity  could  be  carried  out  by  the 
ENTSOs. 

For monitoring and evaluation, like in the past, the Commission would assess the evolution 
via an implementation report on a bi-annual basis. 

45

 
 
 
ANNEX 1: ELECTRICITY TRANSMISSION CAPACITY INCREASES FOR THE PERIOD 2010-2015 
AND 2015-2025 

Major transmission capacity increase in Europe in the next 5 years 
(mid-term)

capacity increase greater than 500 MW
low er capacity increase

Major transmission capacity increase in Europe in 2015 and beyond 
(longer term)

capacity increase greater than 500 MW
low er capacity increase

Source: ENTSO-E 

46

 
 
 
 
 
 
 
 
ANNEX 2: CURRENT FINANCING OF TEN-E PROJECTS 

Investments  in  infrastructure  are  mainly  financed  from  private  sources,  whereby  the  TSOs' 
own  resources  can  vary  between  20%  and  100%  of  the  total  investment  depending  on  the 
risks  and  the  scale  of  the  overall  investment.  The  rest  is  typically  covered  by  loans  from 
commercial banks and international financial institutions. Partnerships with companies active 
in  the  gas  and  power  sector,  other  than  TSOs,  may  offer  additional  capital  in  the  form  of 
equity  participations.  Energy  infrastructure  can  be  corporate  financed  or  project  financed. 
The  involved  risks  are  different.  As  a  general  rule,  if  a  project  lies  within  the  TSOs'  own 
network and is mainly linked to domestic transmission or distribution, TSOs will invest at their 
own  risk  and  cover  the  investment  from  their  own  corporate  sources.  Larger  mid-stream 
(gas)  and  cross-border  (gas  or  electricity)  projects  are  often  project-financed,  with  special 
purpose companies set up for them. Member States in most cases do not participate directly 
in financing the of energy infrastructure and in particular TEN-E projects.  

EU-funded support to TEN-E projects was based so far on the following instruments: 

–  TEN  budget  of  155  mln  €  for  the  period  2007-2013  (see  chapter  2.2):  Although  the 

maximum co-financing rate is up to 50% for studies and 10% of eligible costs for works, it 
has so far rarely amounted to more than 0,01-1% of the total investment cost of a project. 

–  The European Investment Bank plays an important role in the implementation of the TEN-
E  projects.  In  2007-2009  the  financial  envelopes  providing  senior  loans  amounted  to 
2.561 bn€ and 3.407 bn€ respectively for gas and electricity projects. 

–  In recognition of their social and economic importance, energy infrastructure projects have 
risen  in  priority  in  other  EU  funding  sources,  including  the  Structural  Funds,  Instruments 
for  Pre-Accession  (IPA)  and  European  Neighbourhood  Policy  (ENPI/NIF)  as  well  as  the 
RTD Framework Programme. These programmes have a significantly larger budget than 
TEN-E  for  energy-related  measures.    However,  from  a  total  sum  of  1.33  bn€  available 
under the structural funds for 2007-2013, only a fraction has been allocated to projects so 
far: 0.7% (7.5 mln €) for gas and 0.04% (12,000 €) for electricity. This is mainly due to the 
same difficulties as identified in chapter 2.3. 

–  In 2009, the Council agreed exceptionally to allocate 3.98 bn€ to energy infrastructure and 

technology through the European Energy Programme for Recovery (EERP), out of which 
2.365 bn€ went to electricity and gas infrastructu re projects. These funds targeted projects 
where  delays  caused  by  credit  withdrawal  would  not  only  have  been  detrimental  to  the 
EU's security of supply, and therefore to future economic growth, but would also have had 
a  serious  impact  on  employment  and  skills  in  the  energy  and  construction  sectors.  The 
remaining  funds  were  aimed  at  the  introduction  of  renewables  (offshore  wind,  565  m€) 
and  other  low  carbon  technologies  (CCS,  1.05  bn€)  into  energy  networks.  For  the 
supported  offshore  grid  projects,  a  European  added  value  was  required,  namely  an 
"innovation component of large scale projects with cross-border significance", suggesting 
that  "Such  projects  should  include  an  integrative  approach  for  interconnecting  offshore 
wind power to provide transmission capacity in view of trading electricity between Member 
States." A large proportion of EERP funding will benefit the most mature Trans-European 
energy  infrastructure  projects,  in  order  to  speed  up  and  secure  investments  and 
accelerate their realisation. 

47

 
 
 
 
 
ANNEX 3: E3ME MODELLING SCENARIOS AND RESULTS 

1.  Presentation of E3ME model 

The E3ME  model was used to carry out a more advanced macro-economic analysis of the 
impacts  of  the  different  policy  options  examined  in  chapter  5.  E3ME  is  a  computer-based 
model  of  Europe’s  economic  and  energy  systems  and  the  environment.    It  was  originally 
developed through the European Commission’s research framework programmes and is now 
widely used in Europe for policy assessment, for forecasting and for research purposes. 

The  structure  of  E3ME  is  based  on  the  system  of  national  accounts,  as  defined  by  ESA95 
(European  Commission,  1996),  with  further  linkages  to  energy  demand  and  environmental 
emissions.  The labour market is also covered in detail, with estimated sets of equations for 
labour  demand,  supply,  wages  and  working  hours.    In  total  there  are  33  sets  of 
econometrically  estimated  equations,  also including  the  components  of  GDP  (consumption, 
investment,  international  trade),  prices,  energy  demand  and  materials  demand.  Each 
equation set is disaggregated by country and by sector. 

E3ME’s  historical  database  covers  the  period  1970-2008  and  the  model  projects  forward 
annually to 2050. The main data sources are Eurostat, DG ECFIN’s AMECO database and 
the  IEA,  supplemented  by  the  OECD’s  STAN  database  and  other  sources  where 
appropriate.  Gaps in the data are estimated using customised software algorithms. 

The other main dimensions of the model are: 

•  29 countries (the EU27 member states plus Norway and Switzerland) 
•  42 economic sectors, including disaggregation of the energy sectors and 16 service 

sectors 

•  43 categories of household expenditure 
•  19 different users of 12 different fuel types 
•  14  types  of  air-borne  emission  (where  data  are  available)  including  the  six 

greenhouse gases monitored under the Kyoto protocol. 

•  13  types  of  household,  including  income  quintiles  and  socio-economic  groups  such 

as the unemployed, inactive and retired, plus an urban/rural split. 

Typical  outputs  from  the  model  include  GDP  and  sectoral  output,  household  expenditure, 
investment,  international  trade,  inflation,  employment  and  unemployment,  energy  demand 
and CO2 emissions.  Each of these is available at national and EU level, and most are also 
defined by economic sector. 

The  econometric  specification  of  E3ME  gives  the  model  a  strong  empirical  grounding  and 
means  it  is  not  reliant  on  the  assumptions  common  to  Computable  General  Equilibrium 
(CGE) models, such as perfect competition or rational expectations.  E3ME uses a system of 
error  correction,  allowing  short-term  dynamic  (or  transition)  outcomes,  moving  towards  a 
long-term trend. The dynamic specification is important when considering short and medium-
term analysis (e.g. up to 2020) and rebound effects88, which are included as standard in the 
model’s results. 

More detailed information on the E3ME model can be found in the impact assessment study 
done by COWI, Cambridge Econometrics and KEMA. 

88  Where  an  initial  increase  in  efficiency  reduces  demand,  but  is  negated  in  the  long  run  as  greater  efficiency 
lowers the relative cost and increases consumption. 

48

 
 
 
 
 
 
 
 
 
 
 
 
 
                                                 
The graph below depicts the methodology applied to analyse the macroeconomic impacts of 
infrastructure investment in the framework of this study. 

Energy balances 
for electricity and 
gas

Electricity infrastructure 
requirements and 
modelling

Electricity investment 
needs

Gas infrastructure 
requirement

Gas investment needs

Definition of investment baseline and scenarios

E3ME macro-economic input modelling

Impact assessment results and conclusions

2.  Policy sets 

Different  combinations  of  policy  options  (policy  sets)  were  designed  to  analyse  the 
macroeconomic impacts of various policy options89. In addition to policy set (S1) combining 
all preferred options (A3, B3, C2 and D3), a policy set (S2) was established, where option D3 
is  replaced  by  option  D2  to  diminish  Member  State  compliance  costs.  For  the  sake  of 
comparison,  an  additional  policy  set  (S3)  was  designed  to  take  into  account  possible 
measures targeted at non commercially viable projects. Indeed, S3 assumes public support 
or  regulatory  measures  (such  as  guidelines  on  remuneration  of  non  commercially  viable 
projects  including  for  example  capacity  payments,  compensation  schemes,  rate-of-return 
bonuses)  to  ensure  full  delivery  of  all  investments  needed,  including  non  commercial 
projects. The three abovementioned scenarios (S1, S2 and S3) were compared to business 
as usual, using the E3ME model. 

The following table summarises the policy sets and the investment assumptions90 made 
for their development, based on existing studies and expert analysis: 

89  It  must  be  noted  that  these  policy  sets  could  not  stylise  the  impacts  of  the  options  in  each  policy  area,  but 
mainly relied on assumptions arising from policy area A and D. 
90  Under  BAU  and  policy  sets  S1  and  S2,  total  investment  corresponds  to  the  investment  assumed  to  be 
commercially viable under current market and regulatory conditions, not taking into account potential delays due 
to  planning  and  permitting,  which  can  reduce  the  realisation  rate  for  a  given  period.  Only  under  policy  set  S3, 
which  assumes  support  targeted  both  at  commercially  viable  and  non-commercially  viable  projects,  total 
investment corresponds to the identified investment need. 

49

 
 
 
 
 
 
 
                                                 
Scenarios 

Input assumptions for E3ME modelling (investment in the EU only) 

Business as 
usual               
(A1, B1, C1, D1) 

(alias CS1) 

Investment electricity (including smart grids): 
45BN€ (50% of total market based investment needs) 
Investment gas: 
44.7BN€ (90% of total market based investment needs) 

2010-2020 

2010-2020 

TOTAL:   89.7BN€ 

Financing: 
Energy price + x M€ EU funding 91 (60% electricity, 40% gas) 

Policy set S1           
(A3, B3, C2, D3) 

(alias CS4) 

Investment electricity transmission: 
90BN€ (100% of a total commercially viable needs)  
Investment gas: 
49.7BN€ (100% of a total commercially viable needs 92) 

Investment CCS: 2.5BN€  

TOTAL:   142.2BN€ 

2010-2020 

2010-2020 

2015-2020 

Financing method: 
Energy price + x M€ EU funding (11/ 30 gas, 11/20 electricity, 1/12 CCS) 

Policy set S2           
(A3, B3, C2, D2) 

Investment electricity transmission: 
68BN€ (75% of a total commercially viable needs) 

(alias CS3) 

Investment gas: 
47.2BN€ (95% of a total commercially viable needs) 

Investment CCS: 2.5BN€ – 2015-2020 

TOTAL:   117.7BN€ 

Financing method: 
Energy price + x M€ EU funding 
(11/30 gas, 11/20 electricity, 1/12 CCS) 

Investment electricity transmission: 142BN€ 

Investment gas: 57BN€ 

Investment CCS: 2.5BN€ 

TOTAL:   201.5BN€ 

Financing method: 
Energy price + y M€ EU funding to be determined 
(11/30 gas, 11/20 electricity, 1/12 CCS) 

Policy set S3           
(A3, B3, C2, D3 
and public 
support) 

(alias CS6) 

1/4 for 2010-
2015, 3/4 for 
2015-2020 

2010-2020 

2015-2020 

2010-2020 

2010-2020 

2015-2020 

91 The available amount under the current TEN-E programme is 155M€ for the period 2007-2013. 
92 It is important to note that the E3ME model only takes into account investment taking place within the EU and 
therefore assumes a total investment need for gas of 57 bn€, with 49.7 bn€ corresponding to commercially viable 
projects. 

50

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
                                                 
For oil, given the limited (around 600 million euros) and only hypothetical investment needs 
for the considered period, it was assumed that no investments would take place. 

3.  Modelling results 

Concerning the macroeconomic impacts of the different scenarios on GDP and employment, 
it appears that policy set S1 has a significant positive overall impact compared to BAU. The 
positive impact of S2 is only about half. The biggest increase in GDP and employment could 
be  expected  from  policy  set  S3.  Table  4  gives  a  detailed  presentation  of  impacts  for  each 
policy set93. 

Policy set 

Infrastructure 
investment 
(in billion €, 2011-2020) 

GDP 
(cumulative percentage point 
difference compared to BAU, 
2011-2020) 

Employment 
(000s, cumulative difference 
compared to BAU,          

2011-2020) 

BAU 

S1 

S2 

S3 

89.7 

142.2 

117.7 

201.5 

0 

0.42 

0.22 

0.9 

0 

409 

153 

774 

Table 4: Impacts on GDP and employment 2011-2020 (E3ME model results) 

Indeed, more investment creates the need for more employment in a first phase, notably in 
construction,  mechanical  engineering  and  business  services.  This  in  turn  leads  to  higher 
incomes  and  household  spending.  Multiplier  effects  contribute  in  a  second  phase  to 
increased  employment  in  consumer  sectors  such  as  retail,  even  if  these  effects  can  be 
delayed  in  time.  The  model  also  concludes  that  the  forecasted  investment  will  have  small 
positive  impacts  on  small  and  medium  enterprises,  even  if  the  size  of  certain  of  the  bigger 
infrastructure  projects  (notably  in  the  gas  sector)  might  favour  large  companies.  This 
confirms the positive social impacts of the different policy sets studied. Table 5 summarises 
the  positive  impacts  of  all  policy  sets  on  the  main  macroeconomic  parameters  for  the  year 
2020  when  compared  to  BAU94.  The  cumulative  impact  of  S1  on  household  spending, 
investment, exports and imports roughly doubles the impacts of S2. The positive effect of S3 
compared to S1 is even bigger, as it more than doubles investment, exports and imports. 

Cumulative percentage point 
difference compared to BAU      

2011-2020 

Household spending 

Investment 

Exports 

Imports 

S1 

0.15 

1.30 

0.21 

0.21 

S2 

0.07 

0.68 

0.10 

0.10 

S3 

0.27 

2.93 

0.45 

0.48 

93 Increases in GDP vary significantly between Member States depending on the level of investment taking place 
in each of them and can be superior to 1% in 2020 for smaller countries. 
94  As  the  model  does  not  take  into  account  the  different  impact  loops  of  infrastructure  investment  on  gas  and 
electricity  prices,  changes  in  inflation  and  sectoral  prices  are  close  to  zero  for  all  policy  sets.  No  distributional 
impacts appear, i.e. no differentiated impact according to different income levels. 

51

 
 
 
 
 
 
 
 
 
 
 
 
                                                 
Table 5: Impacts on other macroeconomic parameters 2020 (E3ME model results) 

It  must  be  pointed  out  that  due  to  the  complexity  of  possible  interactions  between  energy 
infrastructure  investment  and  energy  prices  the  analysis  of  their  correlation  at  the 
macroeconomic  level  was  only  indicative  and  limited  to  gas.  The  model  confirms  that  gas 
prices  would  decrease  gradually  over  time  compared  to  BAU  as  new  interconnection 
capacities come on stream, which in turn would have a positive effect on GDP outweighing 
the additional investment cost. Concerning electricity, it was assumed that there would be no 
direct  knock-on  effects  on  prices  (through  increased  and  smoother  supply)  from  new 
interconnection  investments95.  Given  the  positive  price  impact  of  the  various  policy  options 
described  in  chapter  5,  it  can  therefore  be  assumed  that  the  model  gives  conservative 
estimates of the benefits provided by the different policy sets as compared to BAU. 

95  Additional  cross-border  flows  typically  only  occur  at  times  of  peak  electricity  demand  and  may  be  in  both 
directions, making it difficult to estimate changes on the average annual electricity prices used in the model. 

52

 
 
 
 
 
 
                                                 
 ANNEX 4: DESIGN OPTIONS FOR AN INTEGRATED OFFSHORE GRID 

Various  design  options  are  currently  studied  for  developing  offshore  grids  (see  graphs 
below).  The  OffshoreGrid96  study  suggests  that  radial  grid  connections  in  general  make 
sense up to 50 km distance from their connection points onshore. For larger distances (in the 
range of 50-150 km) from shore, the concentration of wind farms is a determining factor for 
the  benefits  of  clustering.  Above  150  km  distance,  offshore  grid  hubs  are  considered  as 
typical solutions. In countries where such hubs can easily be defined, the connection costs of 
offshore wind farms could be reduced by up to 34%97. The OffshoreGrid study has calculated 
that, assuming strong offshore wind development, the cost reduction for the North Sea area 
as a whole could be around 17% by 203098. 

Regarding  integrated  "wind  farm  connection  and  interconnector"  solutions,  these  are 
beneficial  in  terms  of  infrastructure  investments,  as  there  is  always  a  cost  reduction. 
However, the cost savings have to be compared to the increased system costs that are the 
result  of  the  constraints  for  electricity  trading,  which  underlines  the  need  for  coordinated 
approaches involving developers, regulators and TSOs to identify optimal solutions.  

Currently available designs 

Radial connection using alternating (AC) or 
direct current (DC) technology 

Radial AC or DC connection of clustered 
offshore wind power plants 

96 Financed by the Intelligent Energy Europe (IEE) programme has made a quantitative assessment of the costs 
and  benefits  of  different  design  options  in  order  to  identify  how  much  anticipatory  investment  would  be  needed 
while avoiding stranded costs. More information can be found at: www.offshoregrid.eu 
97 Cost reduction calculated for Germany.  
98 According to the OffshoreGrid study, offshore grid infrastructure development would cost 32 billion euros until 
2020  and  90  billion  euros  until  2030  considering  radial  connections.  Clustering  offshore  wind  farms  at  offshore 
hubs could reduce this investment need by 15 bn € be tween 2020 and 2030. Further investment need reductions 
could  be  gained  by  clustering  wind  farms  before  2020  and  by  integrating  wind  farm  hubs  with  interconnectors. 
According  to  the  case  study  about  the  Great  Britain  /  Norway  /  continental  Europe  area,  an  integrated  solution 
could require 70-80% less grid investment, but would present constraints for the use of interconnectors between 
countries. However the net benefits are estimated to be significantly higher in this geographic area.  

53

 
 
 
 
 
 
 
 
 
 
                                                 
Radial AC or DC connection of wind park 
clusters with point-to-point international 
interconnector 

Target design 

Meshed international offshore grid based on 
multi-terminal scheme 

Source: ENTSO-E / OffshoreGrid study 

54

 
 
 
 
 
 
 
 
 
ANNEX 5: INPUT DOCUMENTS 

This impact assessment builds on the following general inputs: 

-  Current  framework  for  Trans-European  Energy  Networks  (TEN-E)99  and  its  impact 

assessment100 

-  Green  Paper  "Towards  a  secure,  sustainable  and  competitive  European  Energy 
Network"101 and its public consultation102 in the period November 2008 – March 2009. 
Implementation Report103 on the TEN-E guidelines and TEN-E financial regulation  

- 
-  European Energy Plan for Recovery104   
-  Priority Interconnection Plan 2007105 
-  Third internal energy market package106 
-  Climate and Energy package107 
-  Directive 2009/28/EC on renewables energies108 and National Renewable Energy Action 

Plans109 

-  Directive 2009/31/EC on the geological storage of CO2 

-  Directive  2008/114/EC  on  the  identification  and  designation  of  European  critical 

infrastructures and the assessment of the need to improve their protection 

-  Regulation  concerning  measures  to  safeguard  security  of  gas  supply  and  repealing 

Directive 2004/67/EC, impact assessment and accompanying documents110 

-  Communication on Offshore Wind Energy111 
-  Political Declaration of the North Seas Countries Offshore Grid Initiative112 
-  Declaration of the Budapest V4+ Energy Security Summit 24 February, 2010113 

99 Decision 1364/2006/EC and Regulation 680/2007 of the European Parliament and of the Council  
100 SEC(2003) 742 
101 COM(2008) 781 
102 http://ec.europa.eu/energy/strategies/consultations/2009_03_31_gp_energy_en.htm 
103 COM(2010)203 and SEC(2010)505 
104  Regulation  (EC)  N°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 
L 200, 31.7.2009) 
105 COM(2006) 846 final/2 
106 
http://ec.europa.eu/energy/gas_electricity/third_legislative_package_en.htm: 
2009/72/EC and 2009/73/EC and Regulations (EC) 713/2009, 714/2009 and 715/2009 
107 OJ L140 of 5.06.2009  
108 Directive 2009/28/EC OJ L140 of 5.06.2009 p. 16 
109 Available at: http://ec.europa.eu/energy/renewables/transparency_platform/transparency_platform_en.htm 
110 COM(2009) 363, SEC(2009) 979, SEC(2009) 977 
111 COM(2008) 768  
112 http://www.benelux.be/pdf/pdf_fr/act/act0170_NorthSeasCountriesOffshoreGridInitiativePoliticalDeclaration.pdf 
113 http://visegradgroup.eu/main.php?folderID=859&articleID=27720&ctag=articlelist&iid=1 

notably  Directives 

see 

55

 
 
 
 
 
 
 
 
 
 
                                                 
The impact assessment also builds on the results of the following studies: 

1.  General studies 

-  EU Energy Trends to 2030: Update 2009 (Baseline 2009 and Reference scenario 2009) 

-  World Energy Outlook 2009. IEA 

- 

- 

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

"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  by  Centro  Elettrotecnico  Sperimentale  Italiano,  Instituto  de 
Investigación  Tecnológica,  Mercados  Energeticos  and  Ramboll  for  the  European 
Commission. October 2005 

2.  Studies concerning fossil fuels 

-  Ten Year Network Development Plan by ENTSOG114 

- 

- 

- 

- 

- 

"Methodologies  for  Gas  Transmission  Tariffs  and  Balancing  Fees  in  Europe",  study  by 
KEMA. December 2009 

"Feasibility  of  Europe-wide  CO2  infrastructures",  study  by  Arup  for  the  European 
Commission. To be published by end 2010 

"Evolution of size and cost of a trans-European CO2 pipeline network", study by the Joint 
Research Centre (JRC) of the European Commission. 2010 

"Technical  aspects  of  variable  use  of  oil  pipelines  coming  into  the  EU  from  third 
countries",  feasibility  study  by  ILF  and  Purvin  &  Gertz  for  the  European  Commission 
(expected to be completed by autumn 2010) 

"Model-based  Analysis  of  Infrastructure  Projects  and  Market  Integration  in  Europe  with 
Special  Focus  on  Security  of  Supply  Scenarios",  study  by  EWI  Institute  of  Energy 
Economics at the University of Cologne. May 2010 

- 

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

3.  Studies concerning the power sector 

-  Ten-Year Network Development Plan, ENTSO-E. 2010115 

- 

- 

"2009 Technology Map of the European Strategic Energy Technology Plan (SET-Plan) – 
Part I: Technology Descriptions", Chapter 12, JRC-SETIS Work Group. 2009 

"The  European  Electricity  Grid  Initiative  (EEGI):  Roadmap  2010-2018  and  Detailed 
Implementation Plan 2010-2012", ENTSO-E and EDSO. 25 May 2010 

-  System Adequacy Forecast 2010-2025, ENTSO-E. 2009 

-  Power Choices, Eurelectric. 2009 

114 http://www.entsog.eu/download/investment/ENTSOG_TYNDR_MAIN_23dec2009___.pdf 
115 https://www.entsoe.eu/fileadmin/user_upload/_library/SDC/TYNDP/TYNDP-final_document.pdf 

56

 
 
 
 
 
 
                                                 
-  Roadmap  2050:  A  Practical  Guide  to  a  Prosperous,  Low-Carbon  Europe,  European 

Climate Foundation. 2010 

-  Renewables 24/7: Infrastructure Needed to Save the Climate, Greenpeace/EREC. 2009 

-  Transforming Europe’s Electricity Supply, EASAC. 2009 
-  OffshoreGrid study116, consortium coordinated by 3E. July 2010 

-  European Wind Integration Study (EWIS), final report. March 2010 
-  Pure Power: Wind energy targets for 2020 and 2030117, EWEA, December 2009 
-  Oceans of Opportunity, report on offshore wind energy118, EWEA, September 2009 

-  Reports  produced  under  SUSPLAN,  REALISEGRID  and  IRENE  40  projects  financed 

under FP7. Forthcoming 

- 

- 

- 

- 

“Influence  of  National  and  Company  Interests  on  European  Electricity  Transmission 
Investments”. Study by Matti Supponen, Helsinki University of Technology. Draft version 
dated 1 August 2010 

4.  Studies concerning smart grids 
"Impacts  of  Information  and  Communication  Technologies  on  Energy  Efficiency"119,  Bio 
Intelligence  Service  Final  Report,  September  2008.  Supported  by  the  European 
Commission DG INFSO 
"Smart 2020: Enabling the low carbon economy in the information age"120 by The Climate 
Group on behalf of the Global eSustainability Initiative (GeSI) 

“The  Green  Grid:  Energy  savings  and  carbon emissions  reductions  enabled  by  a  smart 
grid”, Electric Power Research Institute (EPRI), Palo Alto, California, United States, June 
2008 
http://www.smartgridnews.com/artman/uploads/1/SGNR_2009_EPRI_Green_Grid_June_
2008.pdf 

-  Findings  of  the  High-Level  Advisory  Group  on  ICT  for  Smart  Electricity  Distribution 
Networks: “ICT for a low carbon Economy – Smart Electricity Distribution Networks”, July 
2009.  Supported  by  the  European  Commission,  DG  for  Information  Society  and  Media 
http://ec.europa.eu/information_society/activities/sustainable_growth/docs/sb_publication
s/pub_smart_edn_web.pdf 

- 

"Electricity Storage: Making Large-Scale Adoption of Wind and Solar Energies a Reality". 
Cornelius Piper, Holger Rubel, Boston Consulting Group. March 2010 

116 Deliverables are available at: www.offshoregrid.eu  
117 http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Pure_Power_Full_Report.pdf 
118 http://www.ewea.org/fileadmin/ewea_documents/documents/publications/reports/Offshore_Report_2009.pdf 
119 http://cordis.europa.eu/fp7/ict/sustainable-growth/studies_en.html 
120 http://www.smart2020.org/_assets/files/02_Smart2020Report.pdf 

57