EUROPEAN COMMISSION 
Brussels, 19.10.2011 
SEC(2011) 1233 final 
  
COMMISSION STAFF WORKING PAPER 
Impact assessment 
 
Accompanying the document 
Proposal for a  
 
Regulation of the Europen Parliament and of the Council  
on guidelines for trans-European energy infrastructure and repealing Decision No 
1364/2006/EC 
{COM(2011) 658 final} 
{SEC(2011) 1234 final}  
 
 2TABLE OF CONTENTS  
 Background and policy context.................................................................................................. .......... 3
 
1. Procedural issues and consultati on of interested parties.................................................. 3  
2. Context........................................................................................................................ .......... 8  
3. Problem definition ............................................................................................................. .. 9 
4. Baseline scenario .............................................................................................................. .. 18 
5. Key players and affected population................................................................................ 22  
6. EU right to act ................................................................................................................ .... 22  
7. Objectives ..................................................................................................................... ...... 23  
8. Policy options................................................................................................................. ..... 25  
9. Analysis of impacts ............................................................................................................ 36 
10. Comparison of policy options ........................................................................................... 48  
11. Monitoring and evaluation................................................................................................ 50  
Annex 1 Glossary............................................................................................................... .................. 52  
Annex 2 Input documents........................................................................................................ ........... 53  
Annex 3 results from the public cons ultation on permit granting .................................................. 57  
Annex 4 Outcome of stakeholder consultation  among transmission system operators ................ 65  
Annex 5 Energy infras tructures pr iorities...................................................................................... .. 68 
Annex 6 Typical project development process for an energy infrastructure project and examples 
of projects having faced permit granting delays .............................................................................. 69  
Annex 7 Key data on permit granting pr ocedures in selected Member States.............................. 72  
Annex 8 Main reasons for public oppositi on to energy infrastructure projects............................ 73  
Annex 9 National electricity and gas market statistics .................................................................... 74  
Annex 10 Elements of national regulatory framew orks for electricity and gas infrastructure ... 80  
Annex 11 Project case studies concerning regulatory and financing issues................................... 82  
Annex 12 Externalities faced by energy infrastructure projects .................................................... 86  
Annex 13 Financing context for gas and electricity infrastructure ................................................ 88  
Annex 14 The current regulatory fram ework for infrastr ucture delivery .................................... 92  
Annex 15 Past and future infrastr ucture development in the EU .................................................. 98  
Annex 16 Evaluation of suboptions with regard to permit granting and public consultation ... 111  
Annex 17....................................................................................................................... ...................... 116  
Challenges and corresponding  measures proposed........................................................................ 116  
for permit granting and public involvement................................................................................... 11 6 
Annex 18 Administrative cost assessment....................................................................................... 1 18 
Annex 19 Impact of a 2% equity adder on transmission tariffs ................................................... 122  
 
 
 3BACKGROUND AND POLICY CONTEXT  
 
This impact assessment is prepared to support the forthcoming legislative proposal on energy 
transmission infrastructure for the EU, which w ill replace the existing legal framework for Trans-
European Energy Networks (TEN-E). The Commission adopted in November 2010 a 
“Communication on energy infrastructure priorites for 2020 and beyond”, supported by an impact 
assessment, confirming the need to revise the exis ting policy and financing framework, identifying 
nine priority corridors/areas to be implemente d by 2020 and proposing a new method to identify 
projects of common interest (PCIs) to implement these priorities. The Commission's approach was 
largely endorsed by the February 2011 European Council. In June 2011, a Commission Staff Working 
Paper for the Energy Council assessed in detail th e investment needs and obstacles for the coming 
decade. 
 
This impact assessment builds on the findings and conclusions of the above-mentioned documents and 
provides a more in-depth analysis concerning possible measures for permit granting, regulation and 
financing of energy infrastructure. 
The upcoming legislative proposal will confirm the identified infrastructure priorities and establish 
rules for selection of projects of common interest as well as their implementation through permit 
granting, regulatory and whilst financing measures w ill be addressed in the proposal for a Connecting 
Europe Facility. 
 
Out of the pool of projects of common interest, a limited number of projects will be chosen for 
funding under the proposed Connecting Europe F acility (CEF), which the Commission proposed in 
June 2011 for the next multiannual financial frame work (2014-2020) and which covers energy, 
transport and digital infrastructure. The CEF will be  dealt with under a separat e regulation and impact 
assessment. 
 
The general principles for financing and the criteria for eligibility of projects of common interest to 
CEF funding will be provided for in this proposal, while the CEF regulation will specify the selection 
and award criteria. It should be underlined that for the purpose of presenting and assessing the full 
range of possible measures with regard to infrastru cture development, this impact assessment also 
addresses financing options, even if their transla tion in policy measures will take place in the CEF. 
1. PROCEDURAL ISSUES AND CONSULTATION OF INTERESTED PARTIES  
Identification: Lead DG: DG ENER; Agenda planning/WP reference: 2011/ENER/XXX 
1.1. Organisation and timing 
Between March and September 2010, a first impact assessment1 ("the 2010 impact assessment") was 
prepared for the Communication "Energy infrastru cture priorities for 2020 and beyond – a blueprint 
for an integrated European energy network"2 ("the November 2010 Communication"), which was 
adopted in November 2010. 
The work for this impact assessment started in November 2010. The various parts of the problem 
definition were discussed with the Impact Ass essment Steering Group (IASG) in three meetings 
between February and May 2011. The policy options and impact analysis were presented to the IASG 
in late June 2011 and the draft final IA in early July. 
Services involved in the Impact Assessment Steering Group were: AGRI, DEVCO, BEPA, BUDG, 
CLIMA, COMP, ECFIN, EEAS, ELARG, EMPL, ENTR, ENV, ESTAT, HOME, INFSO, JUST, JRC, MARE, MARKT, MOVE REGIO, RTD, SANCO, SJ, SG, TRADE, TAXUD 
                                                 
1  SEC(2010) 1395 
2  COM(2010) 677 
 
 41.2. Consultations and expertise 
1.2.1.  Public consultations 
Several specific consultations have fed this im pact assessment. As early as November 2008 the 
Second Strategic Energy Review launched the Gr een Paper "Towards a secure, sustainable and 
competitive European energy network"3 on the TEN-E revision. Among respondents from the energy 
industry consensus emerged on the need for a fundame ntal review of the TEN-E, for the EU to better 
align the energy network policy and the EU energy a nd climate policy targets, to provide for a stable 
regulatory framework, coordination and raising public acceptance. The respondents identified 
complicated administrative procedures, diverging regulatory regimes across local authorities and 
national borders as well as local resistance as the ma in barriers. The absence of a specific legal remit 
at EU level to mitigate these obstacles was acknow ledged. The role of the EU in facilitating 
infrastructure projects in third countries was welc omed, and the importance of external energy 
relations to infrastructure policies was reaffirmed. 
Following the November 2010 Communication, a pub lic consultation on perm it granting took place 
between March and April 2011. The majority of  the 80 respondents favours the introduction of 
binding time limits (60%) as well as a "one-stop-shop" approach (79%) for energy infrastructure projects.
4 To further increase transparency of the pe rmit granting process guidelines for an earlier 
involvement of the public were considered he lpful. This includes better communication of the 
economic and social benefits of projects, through pr omoters and authorities, as well as the early and 
full provision of environmental information. Regarding compensation measures, half of the 
respondents believed that here competency should  remain with the MS and opposed a harmonization 
on EU level. More detailed resu lts are presented in Annex 3. 
A public consultation led by ECFIN was also carried  out during the same period concerning the EU 
2020 Project Bonds Initiative. More than 130 stake holders from financial institutions, government 
bodies, infrastructure development, manufacturing, and research, the insurance and legal sector 
submitted their contributions. The initiative was consid ered useful by most of them. 60% considered 
that the bond mechanism is likely to attract privat e sector institutional investors to the sectors of 
transport, energy and ICT. A further 16% expected its success to be dependent on technical features of 
the mechanism (price, structure, attracted rating, et c.). Views on the project size appropriate for bond 
funding varied widely, but it emerged that the instru ment is likely to be suitable for bigger investments 
with a minimum size of EUR 50 to EUR 250 million. 
1.2.2.  Surveys, workshops and studies 
Targeted questionnaires on permit granting and financ ing have been sent to the main stakeholders: 
ENTSOs in electricity and gas, GIE, national regulat ors and financial institutions (notably the EIB). 
Results from this consultation can be found in Annex 4. 
A series of four workshops took place with re gulators between February and June 2011 to discuss 
investments needs, cost allocation and financing. A workshop was jointly organised with the Florence 
School of Regulation in May 2011 to discuss cost al location issues with academics and energy experts. 
All relevant issues have also been presented to and discussed with other stakeholders such as industry 
associations or NGOs. Two workshops were also he ld for Member States in May and June 2011 to 
present and discuss options for selection of projects of common interest and permit granting measures. 
The working group meetings of the Baltic Energy Market Interconnection Plan (BEMIP – electricity 
and gas), the North Seas Countries Offshore Grid  Initiative (NSCOGI – electricity) and the North-
                                                 
3  COM(2008)782 launched the public consultation between  13/11/2008 and 31/03/2009. The Commission received 
91 written replies to the Green Paper. 13 came from Member  States (2 from a regional and a local government), 1 
from regulators, 60 from the industry, 2 from academia  and 13 from individual citizens, NGOs and other 
organisations. See http://ec.europa .eu/energy/strategies/consultati ons/2009_03_31_gp_energy_en.htm for details. 
4  Approximately 20 % did not express a clear preference. 
 
 5South Interconnections High Level Group for Central Eastern Europe5 (electricity, gas and oil) offered 
platforms to discuss the regional aspect s of infrastructure development. 
In addition, the Commission used external expertise provided thro ugh two consultant studies on permit 
granting and financing carried out in the period January to May 2011. 
1.2.3.  Other consultations 
A high level conference under the Hungarian Counc il presidency on energy infrastructures took place 
on 16th and 17th May 2011, where Member States ad ministrations, network operators, regulators and 
other stakeholders were given the opportunity to  discuss the various proposals of the Commission. 
Discussions also took place at the Gas Coordination Group (March and May 2011), the Madrid (March 2011) and Florence Fora (May 2011) and at th e relevant working group meetings of the Berlin 
Fossil Fuels Forum. Consultations with individual Member States have been ongoing on a continuous 
basis. 
 
1.3. Opinion of the IAB 
 
 
IAB opinion Changes made 
(1) Improve overall coherence with related policies 
The report should better describe how this initiative relates to the overriding Connecting Europe Facility and other EU initiatives such as 
the Project Bonds Initiative. In particular the 
report should ensure greater coherence and consistency with these related initiatives in terms of synergies, underlying market/regulatory failures, evaluation of results and project selection. The approach to financing modalities should be 
clarified. The relation between this initiative and the CEF 
is now described in great detail in Section 7.3. 
The problem definition should be enhanced by a better description of the wider context of the need for investment of public funds in energy infrastructure in particular by highlighting underlying problem drivers such as the market failure aspects. The 2010 IA described in detail the overall 
investment needs and the project categories facing particular regulatory and market failures justifying the use of public funds. Annex 12 of this IA refines the analys is of these externalities. 
The IA accompanying the Regulation for the 
CEF discusses the need for public funds further. 
 Section 2.2 of the 2010 IA made a detailed presentation of the current TEN-E financing framework in the context of major future 
investment needs and related externalities and its 
shortcomings (notably insufficient resources; limitation to electricity and gas infrastructure; lack of focus; rigid list of targeted projects without top-down identification of priorities; insufficient coordination with other EU funding 
                                                 
5  This High Level Group was set up in early 2011 to promot e the implementation of energy infrastructure projects 
and improve security of supply and mark et development in the region. It in cludes representatives from Bulgaria, 
the Czech Republic, Hungary, Poland, Romania and Slovakia, and Croatia as an observer. 
 
 6programmes). Section 3.3.3 of this IA explains 
them again. The introduction of the problem 
definition chapter has also been strengthened in this regard.
 
Greater clarity concerning the content of the proposed legal instrument should be provided and the report should better explain why this Impact Assessment focuses mainly on problems relating to permit granting, regulation and financing. The proposed Regulation will focus on the 
identification of projects of common interest and measures for these projects in the fields of permit granting, regulation and financing, which is why the analysis in this IA is focused on these issues. 
Section 7.3 explains the content of this initiative 
further and establishes the link with the other proposals. 
(2) Strengthen the subsidiarity analysis and option design 
The report should much better explain and justify, in terms of the principles of subsidiarity and proportionality, the need for EU level measures relating to time limits and other process and structural changes (such as 'one stop shops') to 
Member States' procedures for granting permits 
for energy infrastructure. The description of the policy options has been 
complemented with an analysis of the measures with respect to the principles of proportionality and subsidiarity, and the identification of the preferred options has been more thoroughly 
justified in light of this analysis, stakeholder 
views, and the effectiveness of measures with regard to the overall objective of the proposal.  
In relation to regulatory problems, the report 
should better explain the need for EU measures on cost allocation and tariff setting. The business as usual scenario now has been 
adapted with a detailed analysis on why this is a not option and where the internal energy market rules should be complemented by new rules on 
cost allocation and incentives in the tariff 
systems and regulatory framework. 
The report should discuss and underpin with adequate evidence the assumption that all identified problems, including those of an environmental nature, can be solved in an appropriate manner by a more centralised 
approach/procedure. The description of the Policy Option A.2 has 
been extended to explain how a centralised approach would adequately address the issues at stake, particularly with regard to environmental procedures.  
The presented options should be better explained 
and justified and more nuanced options, such as 
soft law, considered in greater depth. The policy options have been explained in more 
detailed where necessary, particularly policy 
option A.1. A more nuanced suboption with respect to the establishment of time limits has been created, which is, due to constraints in text length, assessed in detail in Annex 16. 
The logical flow between the identified problems on the one hand, and the proposed policy 
options/measures on the other, should be much 
more clearly established (such as the impact of changes to permitting rules on public acceptance). A table illustrating how the proposed measures 
solve the identified problems has been included 
in Annex 17.  
The report should integrate and fully address 
different stakeholders' views on these key points. The report was complemented by a more detailed 
description of stakeholder views in the context of the proposed policy options, and explanations were provided how these have been taken into 
account in the selection of the policy options. A 
more detailed summary of the consultation on permit granting procedures has been provided in the Annex. 
 
 7(3) Improve the assessment of impacts 
The report should provide a more in-depth 
assessment of the impacts of the options on 
stakeholders including Member States and citizens 
particularly in relation to existing rights regarding planning. The assessment of impacts of policy options A.1 
and A.2 on stakeholders with regard to existing 
procedures provides more details on how 
Member States' authorities and citizens would be affected.  
The report should include a more comprehensive 
analysis of the legal implications of the preferred policy options concerning permit granting, which should be followed-up in the discussion of 
economic implications. In  particular, the report 
should clarify the legal implications (e.g. creating a precedent, impact on other legislation) of the introduction of a Lex Specialis clause for Projects of Common Interest. The report provides highlights in more detail that 
legal implications on Member States are expected to be relatively limited for the mandatory measures foreseen. However, the 
information needed to provide an analysis on 
each of the 27 EU Member States' legal frameworks is not available, and can therefore not be included in this report. The description of the legal implications in terms of the Lex Specialis with regard to the creation of a 
precedent and impact on the Waterframework 
Directive has been exte nded. The compatibility 
with the EU acquis will nevertheless remain subject to scrutiny of the Legal Service as part of the interservice consultation.  
In terms of time limits the report should assess in 
greater depth the impact of such limits on the 
fulfilment of all legal requirements, including for 
public consultation. Furt hermore the report should 
assess the impact of such time limits in countries where the current timeframes for awarding permits are significantly longer than the four years 
proposed and possible spill-overs to other 
infrastructure projects. A more detailed analysis of the impacts of the 
time limits has been provided for policy option 
A.2. An illustrative overview of how the time 
limits and other measures foreseen accommodate existing procedures, i.a. established by environmental legislation, is provided for under policy option A.3. 
Summaries of relevant findings from assessments of impacts in earlier, related IA reports should be included in the report. The report should better explain the reasons for choosing options judged to be difficult to implement (such as for example the ex ante cost allocation mechanism). The results from stakeholder consultations have 
been added in the description of the regulatory options and the business as usual scenario provides for the justification of the choice of options made. 
In all regulatory options the views of 
stakeholders have been added, in particular the 
preferences and design options as well as likely impacts with regard to their implementation. The ex-ante cost allocation method will provide for a cost allocation principle and a framework for a 
joint decision by NRas concerned on the cost 
allocation negotiations, with the involvement of ACER in case of disagreement. 
(D) Procedure and presentation 
The report should provide much greater transparency of the extent of stakeholder consultation and should better reflect the comments of all stakeholders on all major points The views of stakeholders on the main issues of 
the proposal have been integrated in the text, and are particularly discussed in the context of the 
 
 8throughout the main text. It should be clearer as to 
the extent that stakeholders and Member States 
have been consulted on the specific set of options assessed in this report. policy options proposed.  
 
2. CONTEXT  
The November 2010 Communication built on an impact  assessment, which covered the development 
of energy infrastructures for the period 2010-2020 with a view beyond to 2030. It assessed investment needs for new transmission infrastructure, evalua ted the current TEN-E framework and financing 
possibilities and compared various policy options fo r implementing sufficient infrastructure to support 
the achievement of the EU's energy and climate po licy goals in the most cost efficient way. The 
impact assessment analysed the design of a new policy instrument to replace the current framework 
and expressed preference for broad priority corridors complemented by smart and transparent criteria for identifying projects of common interest (PCIs) at EU level, thereby building on existing regional 
cooperation initiatives.  
It also quantified the total investment need  at about EUR 200 bn between 2010 and 2020 and 
identified two major categories of obstacles related to permit granting and regulation and 
financing . Based on a top-down estimation, it valued the projects subject to these obstacles and 
therefore at risk of not being delivered to appr oximately EUR 100 bn (also called "investment gap"). 
The November 2010 Communication accordingly proposed nine strategic priority corridors for the 
period up to 2020 and two longer-term prioriti es (see Annex 5), as well as a new approach to 
identifying, selecting and implementing projects of common European interest, including through 
measures in the field of permit granti ng, public consultation and regulation.. 
Both the 4 February 2011 European Council and the 28 February 2011 Energy Council endorsed the 
priorities proposed by the Commission and e xpressed support for the Commission’s approach to 
implement these priorities, notably concerning criteria for PCI selection. The Commission presented, in a Staff Working Document
6 to the June 2011 Energy Council, a refined analysis on investment 
needs, investments at risk of not being delivered , and measures proposed to respond to the financing 
requirements and overcome the obstacles identified. 
On 29 June 2011, the Commission adopted the Co mmunication "A Budget for Europe 2020" on the 
next multiannual financia l framework (2014-2020)7, which proposes the creation of a Connecting 
Europe Facility to promote the completion of priority energy, transport and digital infrastructures with 
a single fund of EUR 40 billion, out of which EUR 9.1 bn are dedicated to energy. 
In July 2011, the European Parliament expr essed strong support for the Commission's proposed 
priorities, project selection method and specific implementation measures8. Concerning the next 
multiannual financial framework, it came out in fa vour of using the EU budget to promote the 
development of energy infrastructures and optimizing the use of the budget to support the Europe 2020 headline targets
9. The Committee of the Regions also supported in July 2011 the Commission's 
approach and suggested the preparation of a corresponding detailed financing plan10. 
Building on the 2010 impact assessment, a complement ary, more detailed imp act assessment is now 
being presented for the legislative proposal following up on the EIP. It analyses policy options in the 
fields of permit granting / public c onsultation, regulation and financing that should apply to projects of 
                                                 
6 SEC(2011) 755 
7  COM(2011) 500/I final and COM(2011) 500/II final (Policy Fiches) 
8 European Parliament resolution of 5 July 2011 on energy infrastructure priorities for 2020 and beyond 
(2011/2034(INI)) 
9 European Parliament resolution of 8 June 2011 on Inve sting in the future: a new Multiannual Financial Framework 
(MFF) for a competitive, sustainabl e and inclusive Europe (2010/2211(INI)) 
10  CoR 7/2011 rev. 2 – ENVE-V-010 
 
 9common interest selected for implementation of th e defined 2020 infrastructure priorities. For each of 
the various obstacles identified, it assesses availa ble, effective and cost-efficient solutions. 
This impact assessment does not discuss again the id entification of energy infrastructure priorities and 
the choice of criteria for PCI selection to implement these priorities as these issues have been analysed 
in the 2010 impact assessment, presented in the November 2010 Communication and further refined 
since with all relevant stakeholders. In line with  the outcome of the 2010 impact assessment and as 
already specified in the November 2010 Communication, the Commission has defined simple and 
transparent criteria to ensure th e selected projects of common interest contributes effectively to the 
implementation of the identified energy infrastructure priorities. 
Nor does it analyse the scope of the new policy to be  developed, as this was the subject of the 2010 
impact assessment, which concluded that oil and ca rbon dioxide infrastructures should be included in 
addition electricity and gas infrastructures, which are already covered under the current TEN-E policy. 
As a result, the infrastructure priorities form the scope of this impact assessment and the upcoming 
initiative. The sectors covered by the priorities are electricity transmission, storage and smart grids, 
gas transmission, storage and LNG/CNG, as well as transport of carbon dioxide and oil. The projects 
covered are all those projects with European signifi cance, i.e. projects with a significant cross-border 
impact affecting at least two Member States. 
The general options regardi ng financing of projects of common interest are discussed in this IA for the 
purpose of presenting and assessing the full range of po ssible measures with regard to infrastructure 
development. However, the precise problems relate d to EU financing, notably with regard to 
investment leverage and project implementati on, are also discussed in the impact assessment 
accompanying the Regulation for the CEF. This treat ment of financing questions in both impact 
assessments is justified, as this initiative will de fine the eligbility criteria for financing of 
infrastructure projects under the CEF, while the Regulation for the CEF will provide for award criteria 
and the various types of financial assistance (grants and innovative financial instruments) available for 
selected projects. 
3. PROBLEM DEFINITION  
The 2010 impact assessment explained the wider contex t of the need for privat e and public investment 
in energy infrastructures and highlighted in particular the scale change in both investment volumes 
and investment delivery times necessary to deliver about EUR 140 bn worth of investments in 
onshore and offshore electricity networks, including smart grids11, and about EUR 70 bn in gas 
networks of European significance, as well as EU R 2.5 bn for the construction of CO2 transport 
infrastructure by 202012. Investment volumes for period up to 2020 will, based on TSO forecasts, 
increase by 30% for gas and 70% for elect ricity compared to current levels13. Compared to the period 
1989-2003, the needed annual investment in elect ricity transmission will even have to double14. This 
investment challenge and urgency clearly distinguishes energy infrastructures from infrastructures in other sectors, as energy networks are a precondition for reaching the 20-20-20 targets. 
These estimations did not take account of maintenanc e, refurbishment or new investment expenses for 
national transmission networks without European significance or for distribution networks, nor of 
investments necessary for the period after 2020. The im pact assessment highlight ed that the identified 
European infrastructure priorities will represent a significant share of the investment needs. These 
                                                 
11  In Europe, over EUR 5.5 bn have been invested in about 300 Smart Grid projects during the decade 2000 to 2010. 
Only about €300 million has come from the EU budget, mainly through Framework Programme funding. About 
EUR 70 million are foreseen under the Framework Programme for the period 2012/2013 on smart grid topics, 
while another EUR 75 million have been committed for i nvestments in R&D for smart cities and communities. 
Nevertheless, the actual deployment of Smart Grids in Europe is still at an early stage. 
12 See SEC(2010)1395 for more detail on the figur es and the uncertaintie s attached to them. 
13  Roland Berger, 2011a. 
14 SEC(2010)1395. Note also that the 2006 inquiry into the European Gas and Electricity Sectors underlined that 
"Amounts invested in cross-border infrastructure in Europe appear dramatically low. On ly 200 million € yearly is 
invested in electricity grids (…)." 
 
 10numbers have in the meantime been largely c onfirmed by national regulators and exceeded by 
estimates from transmission system operators15. The 2010 impact assessment also estimated that the 
full delivery of the needed infrastructure would have significant positive overall effects on GDP and 
employment compared to BAU, with a cumulative effect of +0.42% of GDP and 410,000 additional jobs over the period 2011-2020
16. 
The security of new and existing energy infrastructur es, as a key element to ensure their integrity, 
reliability and climate resilience are important parts of the EU's energy policy. Infrastructure security 
is the subject of a specific, complementary po licy called the European Programme for Critical 
Infrastructure Protection (EPCIP). Given the possible im pacts of events related to climate change such 
as storms, floods, heat and droughts, climate proofing of existing and even more so new infrastructures 
is equally important17. Present and future critical energy in frastructures will need to comply with 
existing legal instruments18 in view of implementing the physical and operational measures to achieve 
a high level of security – including cyber-security – against malicious acts. Other risks, such as those 
related to natural hazards may also be addressed wi thin this policy and other specific instruments in 
the area of safety. The measures necessary to mitig ate these risks will create additional investment 
needs, which are part of the network operators ' core duty of ensuring safe, secure and reliable 
transmission of energy. They are not specifically  addressed in the following, as they can only be 
assessed by relevant actors in the spatial planning and development process for one or several projects. 
3.1. Problems related to permit granting pr ocedures and public involvement for energy 
infrastructure projects 
Lengthy and ineffective permit granting procedures,  along with public opposition, are amongst the 
major reasons impeding the timely implementation of energy infrastructure projects, in particular 
electricity overhead lines. The time from start of the process to final commissioning of a power line19 
is frequently more than ten years, and the commissioning of a project which faces substantial public 
opposition can even take longer (see Annex 6 for project examples). This is of particular concern in 
view of the massive investments in electric ity transmission necessary up to 2020 and the according 
number of permits to be granted20. 
In the context of a survey to which 24 TSOs re sponded, 16 identified difficulties related to the 
administrative permit granting procedure and 21 id entified public opposition as relevant reasons for 
delays in the implementation of electricity infrastructure21. Results of another survey amongst TSOs of 
13 MS showed that public opposition was considered as  the most important potential cause for delays 
(rating: 5.2 of 6 points), followed by complex pe rmit granting procedures (rating: 4.5 of 6 points)22. 
                                                 
15  See SEC(2011)755 for more detail. 
16  The impact of developing an offshore grid would be particularly positive in this regard. A case study on 
Bremerhaven on the German North Sea has shown that co mpanies in the city have attracted about EUR 250 million 
and created some 700 new jobs in the period 2006-2009 (Source: EWEA, "Oceans of Opportunity", September 
2009). 
17 Impacts of climate change and extreme weather events ha ve shown to disrupt energy services (with significant 
costs to the economy). According to the IAEA, about half of the system faults  in electricity grids are caused by 
weather effects. Adapting energy infrastructure, including transmission lines, to these effects could, according to 
the literature available to date, entail significant costs (s ee for example Vattenfall Europe (2006); Van Ierland, E.C. 
et al. (2007); ADAM project (2009); US National Research Council (2010)). Despite these first studies allowing an 
initial discussion of the issue, its specific relevance fo r transmission infrastructure needs to be further assessed, 
based on more evidence. 
18  Council Directive 2008/114/EC of 8 December 2008 on the identification and designation of European critical 
infrastructures and the assessment of the need to improve their protection 
19  The major phases of a typical pr oject development process in electricity are presented in Annex 6. 
20  One example is the offshore grid development in the Nort hern Seas: According to ENTSO-E, it could lead to about 
250 offshore cables needing onshore landing points between now and 2030. It should however be noted that 
planning and permit granting procedures are different fo r onshore and offshore installations, the detail and amount 
of environmental and socio-economic spatial data used, the number of possi ble planning solutions and the time it 
takes to involve all stakeholders bei ng usually higher on land than at sea. 
21 Acknowledging these problems, TSOs and NGOs have formed an allian ce to find solutions (Renewables Grid 
Initiative and Smart Energy for Europe Platform), and some Member States have already introduced legislation to 
facilitate procedures (such as UK, IE, NL, DE). 
22  Roland Berger study on perm it granting procedures, 2011. 
 
 11The two main drivers causing the long delays will be examined in the following sections: 
1. Inefficient administrative procedures, notably  with regard to the organisation of the 
procedures, and the conduct and competences of involved parties; 
2. Opposition of affected population 
3.1.1.  Inefficient administrative procedures 
• Complex and fragmented process : Although the stages of the permit granting process are 
generally similar in different Member States,  the concrete procedures within one phase differ 
highly from one country to another, and often al so between the different regions within one 
country, particularly in those countries with fede ral structures where planning competence is at 
regional level (Austria, Belgium)23, which makes cross-border projects even more of a challenge. 
Furthermore, permit granting processes are also generally of extremely fragmented nature. There are typically many authorities indirectly whose opinion is required in the process. their number can reach up to 50 per project. The number of auth orities directly involved,  i.e. responsible to 
issue constitutive, legally-binding permits, is us ually lower, ranging between one and more than 
ten (for data see Annex 7). If responsibility for the delivery of the permits is spread over several 
authorities, this leads to difficulties in identifyi ng responsibilities, different interpretation of laws, 
inconsistencies in the handling of procedur es, friction losses and duplication of work.  
• Lack of upfront planning and coordination : It is in many Member States up to the promoter to 
plan the process and coordinate the different  bodies and permits, with limited guidance from 
public administrations. However, due to lacking managerial resources and competences of 
promoters, coordination activities are often ineffici ent. Lack of appropriate upfront planning and 
coordination procedures has particularly severe consequences for cross-border projects, where delays on one side of the border can significantly impede progress on the other side. Such procedures are also crucial for wind offshore infrast ructure projects, which often span large areas 
such as entire regional seas. Acknowledging the benef its of an effective upfront maritime spatial 
planning, the Commission is at present carrying out an impact assessment. 
• Lack of time limits:  In many Member States there are no binding time limits in place to ensure 
that decisions are taken in a timely fashion. In 13 MSs there are time limits for the entire 
procedure and/or its individual st ages. However, in many MSs these are not always respected as 
enforcement mechanisms are not applied or do no t exist. Surveys show that the permit granting 
process (i.e. pre-application efforts and statutor y administrative procedure) has an average 
duration of between four and ten years (see Annex 7 for details). Adding about three years for first 
planning efforts and construction, this leaves an average duration of 7-13 years
24. 
• Unclear documentation standards and lack of quality : Specific difficulties arise in the pre-
application phase, when usually only limited inform ation is available regarding the elements to be 
analysed and submitted with the application, a nd when promoters hand in  application documents 
of poor quality. This leads to cumbersome and lengthy request-response cycles between promoters 
and authorities, particularly when dead lines for additional requests are missing. 
• EU legislation25 and national legislation ha ve set high standards for environmental protection , 
which has been perceived as a major challenge by pr omoters during the past years. This legislation 
is not leading to delays per se, nor does it prevent projects from taking place, but the lack of coordinated implementation by national authorities has posed major difficulties for promoters, as 
the fulfilment of requirements is often time cons uming and can, if not implemented adequately, 
                                                 
23  Germany adopted a law in 2011 to shift planning competence from the state to the federal level 
(Netzausbaubeschleunigungsgesetz – NABEG). 
24  Judicial procedures are not included in this time frame . To be noted that for complex cross-border projects the 
duration tends to exceed the average duration. 
25  Directive 2001/42/EC on the assessme nt of the effects of certain plan s and programmes on the environment; 
Directive 85/337/EEC on the assessment of the effects of certain public and private pr ojects on the environment; 
Directive 92/43/EEC on the conservation of natural habitats  and of wild fauna and flora; Directive 2009/147/EC on 
the conservation of wild birds; Di rective 2000/60/EC establis hing a framework for the Community action in the 
field of water policy 
 
 12lead to delays in the process. A comprehensiv e analysis of impacts on the environment may – 
depending on the available data for the specific site  concerned – take one year or more as a whole 
vegetation period or two migration sea sons have to be analysed. Particular difficulties arise if the 
assessment of the implications for the site or the st atus of a water body is negative, and if there are 
no alternative solutions available, as construction is in this case only allowed if the project is 
granted the status of overriding public interest by  the national competent authority and if adequate 
compensation measures are taken, such that promoters face uncertainty whether a project can 
eventually be carried out. This issue is particular ly relevant in MSs with large and scattered parts 
of land designated as Natura2000 habitats26, and in border regions, wh ich are often along natural 
barriers of environmental significance (e.g. Py renees along the ES-FR border, coastal areas). 
3.1.2.  Opposition of affected population 
Opposition by landowners, citizens living in the vici nity of potential insta llations and stakeholder 
organisations poses the most significant impediment in  the permit granting process. This is particularly 
true for Western MSs, where citizens seem to be more sensitive to (perceived) environmental and 
visual impacts, but it is increasingly the case also  in new MSs. Public opposition usually leads to 
numerous objections  during consultations (up to 20.000) whic h have to be answered by authorities 
and/or promoters, leading to significant additional efforts and delays in the process. Complicated and 
lengthy negotiations with landowners  may also lead to delays at the stage when the developer needs 
to obtain the right to use the land in order to start construction. Lodging appeals to courts  is another 
means of public reaction preventing the start of c onstruction. In some countries, court appeals are 
possible at any time throughout the permit granting process and beyond (e.g. AU, IT), delaying the process even further. There is usually less opposition to offshore projects as citizens are not directly 
affected by installations. However, strong resistance of  citizens living in the vicinity of landing points 
can prevent the timely connection of wind farms. The main reasons for public opposition, notably 
unclarity about the added value of a project, r eal or perceived impacts on the environment and 
landscape, health and safety concerns, and late and insufficient involvement of the public and 
stakeholders are presented in Annex 8. 
 
3.2. Problems related to the regulatory framew ork for energy infrastructure investments 
Electricity and gas transmission are regulated sectors with costs for network investment, operation and 
maintenance recovered through tariffs fixed by natio nal regulation, which differs from MS to MS (see 
Annex 9 and 10 for statistics and relevant elemen ts of the regulatory framework concerning EU 
electricity and gas markets and networks). In most MS s, cost recovery for projects is based on verified 
national market needs and cheapest available solutions , in order to ensure cost-efficiency and keep 
tariffs low for national consumers
27. The existing framework is therefore not geared towards 
delivering the identified European infrastructure prior ities in view of further integrating the European 
energy networks and meeting the European climate and energy objectives. 
It should also be noted that the commercial viability and hence the "bankability", i.e. capacity to attract 
commercial financing, of infrastructure projects is  intrinsically linked to the regulatory framework. 
Infrastructure operators and investors have repeated ly called for a stable and incentivising regulatory 
framework with adequate long-term signals, notably  for cross-border investments. The way, in which 
investments costs and risks are treated, directly determines the return and hence influences the 
incentive to invest or to lend money for a project . At the same time, changing conditions in capital 
markets can influence regulation for such investments (see also section 3.3). 
The three main shortcomings with regard to the regulatory framework, which hinder cross-border 
infrastructure investments, are described in the following. Examples of electricity and gas 
infrastructure projects subject to regulatory difficulties are given in Annex 11. 
                                                 
26  E.g. 30% in the case of Slovenia. 
27  Transmission tariffs account on average for only about 5-10% of household electric ity prices across EU MSs. 
 
 133.2.1.  Asymmetric benefits and externalities 
With national energy networks becoming both more  decentralised and increasingly interdependent, 
cross-border projects between at least two – isolated or well-interconnected – Member States or projects in one MS with significant cross-border imp act multiply, which either feature an asymmetric 
distribution of costs and benefits among beneficiar ies, or offer externalities not appropriately 
internalised by either market signals or the ex isting regulatory system. These two categories partly 
overlap, as many of the externaliti es discussed also have a cross-border, supranational dimension. 
Concerning asymmetric impacts , a new internal electricity line can benefit the origin country by 
reducing its internal congestions, but also border countries by increasing transits. A gas reverse flow 
infrastructure on the territory of one Member State can be for the sole benefit of its neighbour, if the 
latter has only a single other gas supply route. Simila rly, a new cross-border line (e.g. Austria-Italy in 
electricity, Hungary-Slovakia in gas) can de fact o permit to increase transit for both the immediate 
neighbours and third countries, which are indirect beneficiaries. 
As a result, internal as well as cross-border invest ments can positively impact the functioning of third 
country networks, without any explicit participa tion from the concerned network operators to the 
incurred investment cost
28. This leads to a significant problem of free riding due to the asymmetry 
between benefit distribution and cost allocation29. In gas, the investment risk for new transmission 
networks is moreover strongly linked to the upstream and downstream commitments. 
In addition, the more MSs are interconnected with e ach other, the more the identification of benefits 
can be complex and difficult to predict. Indeed, the be nefits of a new electricity line on the territory of 
two MSs but benefiting several others indirectly can be very difficult to predict for the indirect beneficiaries, as these benefits depend on various factors such as l ong term price differentials, which 
themselves are influenced by a large set of parame ters (generation mix in the exporting and importing 
country, support schemes for renewables, future ot her transmission lines). Given these uncertainties, 
benefits and revenues might not be quantifiable at all ex ante . 
Today, there is no common European or region-speci fic framework for benefit identification and cost 
allocation. For more complex projects, this absen ce has often led to complex and lengthy decision-
making negotiations between indivi dual operators and national regulatory authorities or even made 
certain projects impossible to realise
30. More specifically for gas, the l ack of transparent, timely and 
efficient coordination across borders creates uncertain ty to market participants and risks for network 
operators31. Under today's narrow framework, operators t oday have few incentives to develop cross-
border investments when benefits go to another area. 
Concerning  externalities , they are positive or negative impacts provided by a given infrastructure 
investment, which are not properly reflected by exis ting market signals and revenue streams, i.e., in 
the case of regulated grids, transmission tariffs and, in electricity, congestion rents32. In some cases 
increasing the capacity or the electricity grid to th e optimum level even decreases the congestion rents. 
While the socio-economic benefit, notably at region al or EU-wide level, of a project providing such 
externalities would outweigh its cost, the investment will not take place if it is based on a merely corporate based commercial viability evaluation or on optimising national interests in one MS. The 
                                                 
28  In its draft position paper on cost  allocation, CEER calls these bene fits “commercial externalities”. 
29  Cf. Glachant and Kalfallah, 2011 
30  The Kriegers Flak project is an excellent example: It initially envisioned the de velopment of three wind farms 
within German, Swedish and Danish waters, linked by a combined offshore grid connection, which would also 
serve as an interconnection between the three countries. The three-countr y solution has in the meantime been 
abandoned with Sweden's withdrawal, a nd the development of the project has been delayed because of regulatory 
challenges, despite EUR 150 million of EU funding received in the context of the European Energy Program for 
Recovery. 
31  The 2006 sector inquiry had already outlined that on cert ain borders, long-term pre-liber alisation gas transmission 
capacity reservations still exist despite the ruling of the European Court of Ju stice that such reservations are not 
compatible with EC law, unless they were notified under Directive 96/92/EC. 
32  In its draft position paper on cost allocation, CEER calls the externalities disc ussed under this category “non 
commercial externalities”. 
 
 14main categories of externalities were already discu ssed in the 2010 impact as sessment and are further 
detailed in Annex 12. 
3.2.2.  Lack of appropriate regulatory incentives a nd long-term signals to meet EU priorities 
Compared to the European infrastructure priorities and the EU's energy and climate policy objectives, 
such as the 20-20-20 targets for 2020 or the 80-95% emission reduction objective for 2050,  the 
existing regulatory framework does not give appr opriate incentives and long-term signals for the 
implementation of all projects necessary to meet these priorities. NRAs have so far not sufficiently 
taken account of the corresponding investment challenge for networks  up to 2020 and beyond and 
their specific responsibility under the third market  framework for making these investments happen. 
In addition, given their cross-border nature and the broader benefits and positive externalities they 
provide as described in the previous section, projects of common interest in particular will often face 
additional technological or operational risks. Given the additional effort their development implies, 
operators will be reluctant to enter into the devel opment of these projects. And without adequate return 
on investment, investors and banks will discard thes e projects compared to other "standard projects" 
with a lower but more certain risk-return profile. This will further endanger the timely implementation 
of the EU's infrastructure priorities. 
Some countries have recently introduced – in ad dition to the existing third market legislative 
framework (see section 1) – additional incentive sch emes in their regulatory framework to promote 
certain categories of investments. France (for gas) and Italy (for electricity and gas) for example give 
explicit incentives for congestion reduction and cro ss-border investments. Some NRAs have also 
introduced explicit incentives for innovation (UK, Italy). 
Member State Incentive Scheme 
Austria Possible ex-ante consideration of extraord inary investment costs (project specific mark-
up of 0.20% for gas) 
France Gas: New investments can receive RO R add-on upon decision by the regulator 
Germany Investment budgets are approved for expansion investments by the regulator upon certain 
conditions. After a certain period, the investment budget is transferred into the RAB. 
Italy Investment premiums of 2%-3% for certain categories of investments 
Great Britain Specific innovation incentive scheme s for low-carbon outputs (e.g. Networks Innovation 
Competition, Innovation Allowance, Revenue Adjustment Mechanism, Transmission 
Investment for Renewable Generation (TIRG)) 
Netherlands Extra income for substantial investments upon decision by the regulator 
Portugal Gas: Cost of capital and amortisation are smoothed for the whole concession period (e.g. 
40 years). 
Spain Investment allowances 
Table 1: Existing national transm ission investment incentive schemes  (source: CEER)  
However, such mechanisms exist only in certain Me mber States, remain limited with regard to the 
types of investment they cover and are only partly in line with the EU's infrastructure priorities. 
Finally, it should be noted that investment signals and tariffs are intrinsically linked as the tariff 
methodology sets the main conditions for the recovery of the investme nt costs for regulated networks. 
NRAs decide on cost allocation via the tariff setti ng in accordance with nationa l preferences, user and 
network particularities. NRAs will therefore be re luctant to provide by themselves incentives for 
projects of common interest, which might negatively impact their national customers for the shared and bigger overall benefit of costumers in several other Member States. 
3.2.3.  Lack of coordination for cross-border investment approval process 
As projects of common interest will by definition aff ect at least two Member States, they will require 
approval of at least two NRAs for the corresponding in vestment, notably with regard to cost allocation 
among the two Member States involved. Coordination of procedures on both sides of the border for such approval is crucial to prevent delays or obstacles for the realisation of such projects. 
 
 15This is even mort important, as national regulati ons differ with regard to the way, in which 
investments are accounted for and remunerated. For the gas sector, the 2009 KEMA study concluded 
that differences in commercial viability of the same project according to the different national regimes 
could create a serious barrier to investment: "Investors will compare the retu rn with similar projects in 
terms of risk and allocate their money accordingly" . Concerning specifically open seasons, CEER and 
the Gas Regional Initiative North-West have under lined difficulties related notably to different 
regulatory rules applying in different MSs, th e uncoordinated launch of open seasons, the lack of 
transparency due to invoked confidentiality by mark et operators and the insufficient reliability of the 
non-binding bidding phase33. 
Concerning electricity, experts working on regulator y issues for offshore grid development under the 
NSCOGI recognised that "the regulatory regimes for offshore tr ansmission are different and may need 
to become more consistent in future if coordinated development is to be achieved" . They noted 
"notable differences in grid charging regimes  and procedures between the countries and these, 
together with the different levels of renewables support , could lead to developers seeking to locate in 
areas with low connection charges and high suppor t mechanisms resulting in sub-optimum siting"34. 
However, cooperation among NRAs and TSOs for cr oss-border investments and attempts at 
coordinating procedures have proved to be difficu lt and cumbersome, thereby creating delays in 
project approval and delivery (e.g. Dutch-German or  Bulgarian-Greek cooperation in gas or Franco-
Spanish cooperation in electricity).35 
 
3.3. Problems related to financing of energy infrastructure projects 
Energy infrastructure projects are primarily finan ced by the private sector. Most commonly corporate 
financing is used: TSOs develop projects with their own capital (balance sheet) and loans from 
commercial banks and interna tional financial institutions36. Project finance, where the long term 
financing is only based upon the projected cash flows of the project rather than the balance sheets of 
the project sponsor, is used only rarely37 (see Annex 13). Moreover, in order to increase their 
investment capacity, TSOs may seek corporate equity investments from other companies (also from outside the energy sector). Such companies offer add itional capital in return for participation in profits 
generated by the TSO’s projects. 
While this system functions rather well in a predic table and stable regulatory environment, there are 
factors, which make the financing of infrastructures – notably those of cross-border nature targeted by 
this initiative – difficult
38. Financing will be even more cha llenging for projects with low or no 
commercial viability, which are often those falling into  the categories listed in section 3.2.1. Because 
of their high economic, social or environmental bene fits, public funding would be fully justified to 
trigger an investment decision for such projects. Ne vertheless, the existing support is insufficient both 
in form and available volumes. The three main factor s likely to hinder investme nts are discussed in the 
following. 
                                                 
33  CEER, "Monitoring Report 2010 on the compliance with  the Guidelines of Good Practice of Open Season 
procedures (GGPOS)", Ref: E10-GMM-11-04, 7 Decembe r 2010; ERGEG Gas Regional Initiative North-West 
(GRI NW), "Open Season Co ordination", 28 April 2009. 
34  NSCOGI Working Group 2, "Report to the Steering Committee", May 2011 
35  It should be noted that this impact  assessment does not examine in further de tail, how different national regulatory 
regimes by themselves impact investme nt decisions and to what extent ha rmonisation would be beneficial. This 
question will be addressed under the third package framework (see section 1). 
36  TSO equity in projects typically varies between 20% and 100% of the total investme nt depending on the project 
risks and scale. 
37  As a general rule, if a project lies within the TSO's se rvice area and is mainly linke d to domestic transmission or 
distribution (gas) or uses alternating current technology in  a meshed grid (electricity), TSOs will use corporate 
financing. Project financing, which implies setting up a special purpose comp any, is used for larger, specific 
projects such as LNG terminals, storage, merchant lines or complex joint ventures (e.g. mid-stream and some cross-
border pipelines) in gas and high-voltage direct  current lines or storage in electricity. 
38  It should be noted that the financing cha llenges identified vary between Member States. 
 
 163.3.1.  Limited financing capacities of TSOs 
In view of the scale change in both investment volumes and investment delivery times necessary to 
deliver on the energy infrastructure priorities until 2020, many TSOs, especially in eastern European 
Member States, will reach the limits of their financing capacity. The volumes of new investments will exceed the financing possibilities offe red by their balance sheet size. Both debt and equity providers 
have confirmed that, given the le vels of available equity, TSOs w ill face challenges raising sufficient 
amounts of debt at reasonable cost, especially because of borrowing ceilings or the absence or 
insufficiency of investment grade ratings, as lenders  are not going to accept higher debt/equity ratios. 
Therefore, certain TSOs could need large equity injec tions by private investors or public owners to be 
able to contract more debt for their future inv estment programmes. Partly or fully state-owned TSOs 
will depend to a large extent on their government. Gi ven the very difficult budgetary situation of most 
EU MSs, it is unlikely that they will accept signi ficant equity injections. This is especially 
handicapping when extensive investment plans exis t and TSOs already have a high debt/equity ratio 
(70/30 or more), as is the case for National Grid or Tennet. 
In addition, TSOs are increasingly facing difficulties with accessing long-term debt  on favourable 
terms. Following the financial cris is, banks have reacted with a ra dical shortening of maturities, 
increased pricing and collateral requirements. Basel III rules
39 will require banks to keep a higher 
percentage of equity on their balance sheets. Long-term capital commitments for infrastructure 
projects will become more expensive and difficult to execute. Furthermore, lending conditions have 
appeared to be insufficiently adapted to project and/or corporate needs of TSOs (loan duration too 
short, impossibility to make a subs tantial bullet payment at the end of the loan, limited flexibility, no 
bridge financing offered between the construction phase and the operational phase)40. As a result, 
banks will favour less complex and bigger unitary transactions over more complex, innovative or 
riskier projects. Furthermore, access to EIB lo ans may become more difficult for certain TSOs41. 
These constraints will affect a TSO’s ability to deliv er on its overall investment programme (including 
infrastructures of European and of solely natio nal relevance). PCIs will have to compete for 
investment budget with national priorities. Give n the increasing constraints on lending capacities, 
bond markets to raise larger debt volumes could play an increasingly important role in the coming 
years. However, issuing bonds implies that TSOs ha ve a solid credit rating. Today, however, about 
40% of TSOs in Europe (gas and electricity) are not rated42 and therefore have no access to funding 
from bonds and private placements. As energy networ ks are regulated, an increase in tariff levels for 
energy consumers could be an alternative way to raise capital to finance new investments. However, 
there are important social and political lim its to increasing tariffs (see chapter 10). 
3.3.2.  Difficulties for energy infrastructure investme nts to attract new institutional investors 
Institutional investors such as pension funds, insu rance companies and wealth funds are increasingly 
moving into infrastructure investment given its potential to match long-term assets and provide 
diversification. The stability provided by the regulated model corresponds to pension funds’ 
investment profile, characterized by rela tively low rates of return – around 7%-8%43 – and long 
investment horizons. These investors are also beco ming increasingly ready to invest directly in 
infrastructure assets. This is new, as their exposure to infrastructure has traditionally been via listed 
                                                 
39  The Basel III global regulatory standard will come into  force in 2013. It strengthens bank capital requirements and 
introduces new requirements on ba nk liquidity and bank leverage. 
40  Roland Berger, 2011a. 
41  Loans from the EIB are seen as the most important compone nt of debt financing by ma ny TSOs, especially smaller 
TSOs in Eastern Europe. Many TSOs have reached limits  with regard to how much unsecured lending they can 
receive from the EIB. As a general principle, the EIB ai ms at not providing more than 10% of unsecured lending 
compared to a TSO's equity. In the EU15 TSO sector, the EI B already is often already above this ceiling. In most 
EU12 Member States however, the EIB does not yet agree to higher unsecured lending and requires bank or state 
guarantees. 
42  Roland Berger, 2011a. 
43  Compared to 10%-12% infrastructure funds typically offe r their investors. Source: In fraNews, “How Real a Threat 
to Infra Funds is the Direct I nvesting Phenomenon?” 24 May 2011. 
 
 17companies (such as utilities), or via real estate portfolios44. Their role as financiers for TSOs and 
dedicated infrastructure project compan ies is therefore expected to rise. 
However, the arrival of such new classes of inv estors, which might have different expectations 
concerning the risks incurred compared to current regulatory practice, may require regulatory adaptations. Furthermore, there need to be invest ment opportunities available, i.e. equity opened to 
participation and/or debt products. The fact that to date only some TSOs are fully open to equity 
investment from third parties, given their owners hip structure (see Annex 13, Figure 16 and 17), limits 
the inflow of capital from institutional investors and will not help to ease the investment challenge in 
the short to medium term. 
3.3.3.  Lack of adapted funding instruments and sufficient envelopes 
The 2010 impact assessment already described the available financing under the existing TEN-E 
programme (in its Annex 2) and its shortcomings (notably lim ited budget, inflexibility, no risk 
mitigation instruments, no funding outside the EU, insu fficient synergies with other EU funds). It also 
highlighted the positive contribution made by the European Energy Programme for Recovery
45, which 
has responded to some of the weaknesses  identified, but was a one-off exercise. 
In addition, energy infrastructrures today can benefit from the support of Structural and Cohesion 
Funds . Under the 2007-2013 budget, EUR 1.6 bn have b een allocated to Member States for projects 
classified as TEN-E. However, available funds have seen only a slow uptake by Member States. The 
programming approach makes it less flexible to shif t funds between projects and programmes, even if 
they are seen as particularly relevant from the EU en ergy policy perspective at a certain point of time. 
The funds are not centrally managed, which make s it difficult to coordinate across and between 
countries to ensure the regional ne twork benefits of investments. 
European energy infrastructures can also benefit from grant support under the EU research 
programmes . Such support is important from the t echnology development and demonstration 
perspective, but it does not contribute directly to the construction of industrial-scale projects. 
The table below summarises the financial efforts at  EU level to support the development of energy 
infrastructures during the current financial period (2007-2013). 
  Funds allocated within 
financial perspective 2007-
2013  Funds spent/committed 2007-2009  
 
 Gas infrastructure Electricity 
infrastructure 
  Electricity and gas 
infrastructure Studies Works Studies Works 
EIB 3 500 – 7 000 - 3 407 - 2 561 IFI 
EBRD  - - - 488 
TEN-E 155 22 7 23 18 
EEPR 2 268 11 1 352 2 903 
Structural 
Funds 1 607 24 8 EU 
RTD 
Framework 
Programme 150 - - 50 - 
Total IFI and EU 
funds 7 680 – 11 180 4 823 4053 
Table 2: Total funds (loans and grants) from EU institutions allocated to electricity and gas infrastructure 
within financial perspective 2007-2013 (* EEPR: Some infrastructure projects related to works include studies) 
                                                 
44  OECD, "Pension Fund Investment in Infrastructure", Working Paper on Insurance a nd Private Pensions, January 
2009. 
45  Regulation (EC) No 663/2009 of the European Parliame nt and of the Council of 13 July 2009 establishing a 
programme to aid economic recovery by granting Union financ ial assistance to projects in the field of energy (OJ 
L200, 31.7.2009) 
 
 18The range of financial tools  available at EU level to promote projects of common interest is for the 
moment effectively limited to grants. There are no specific “innovative financial instruments”, which 
would support projects in a different manner than ju st by reducing the initial capital expenditure for 
investors. There is no possibility to provide risk capital to projects46. There are also no risk sharing 
arrangements, through which the Commission could en able financial institutions to provide sector 
specific lending facilities (loans on adapted terms, guarantees, facilitation of direct market (bonds) 
financing)47 addressing the risks of specific projects. The existing tools do not allow for using the EU 
budget to accelerate project preparation by e.g. providing start-up capital. 
With a growing number of complex and cross-borde r projects of European importance, well designed 
equity or debt instruments would be likely to assist them in facilitating access to equity and/or debt 
finance, reducing the cost of capital, adapting le nding conditions to better match project cash flows 
and facilitating project finance structuring through sta ndard equity and debt instruments. It is also 
essential to note that such form of support would come  at a lower expense to the public budget (higher 
leverage)48. It should however be noted that innovative fi nancial instruments will never be the remedy 
for all types of projects, especially if project financ ing is a prerequisite. Such instruments can only be 
used for projects which generate sufficient revenues to repay their debts and remunerate for financial 
support received – hence the need for the commercial viability of projects. 
4. BASELINE SCENARIO  
This chapter looks at how energy infrastructur es would develop over the coming decades, should no 
further policy actions be taken. It builds on th e chapter "Baseline scenario" of the 2010 impact 
assessment, which presented the methodology used for the energy infrastructur e needs assessment and 
analysed the resulting energy trends and infrastruct ure needs. The findings of this chapter are not 
repeated here. In the following, we do however, on the basis of a detailed assessment of the current 
policy framework in Annex 14, analyse how much  and which type of infrastructure would be 
delivered and which one not, if no further action was taken. This allows us to refine the analysis of 
investments at risk of not being delivered when needed ("investment gap"  in the 2010 impact 
assessment). 
As already highlighted in the 2010 impact assessme nt and as described in the previous section, the 
current planning, permit granting, regulatory and financing framework for energy infrastructure 
development will lead to significant under-deliv ery of infrastructures under business as usual (BAU). 
Insufficient top-down prioritisation  and cross-border planning will not allow focussing attention 
on those infrastructures, which bring the highest va lue added in view of reaching the 2020 energy 
policy targets. As a result, there is a high risk of projects of common European interest not receiving 
the political attention they need to be pushed trough by 2020. 
Persistent delays due to complex and lengthy permit granting procedures and low public 
acceptance  will further delay new infrastructure projects,  notably in electricity. Under business as 
usual, the real duration of the statutory authorisa tion procedure would continue to vary between less 
than 2 years and 10 years depending on the Member States, with an average of about 4 years (see Annex 7). In many Member States, public resistance to new infrastructure projects would increase this 
duration by a significant amount of years due legal recourse procedures. The efforts associated with 
                                                 
46  The Marguerite Fund, to which both the Commission and the EIB have contributed, is expected to invest also in 
energy projects. However, the high yi eld expectation is likely to exclude typical energy transmission projects. 
47  Such risk sharing instruments have already been devel oped for other sectors.  Since more than ten years, the EU 
budget has been using financial inst ruments. Under the 2007-2013 financia l framework, a new generation of 
financial instruments has been put in place in cooperation w ith the EIB, such as the Risk-Sharing Finance Facility 
(RSFF) under the 7th R&D Framework Programme, or the Loan Guarantee Instrument for TEN-T projects (LGTT). 
Although fragmented, experience until now with financial in struments has been positive in these sectors. Court of 
Auditors' reports have generall y praised the effectiveness of these instrume nts, with exceptions  in certain cases. 
48  Market based/innovative instruments are characterised by  a higher leverage (in comparison to grants) and their 
potential to generate reve nue for the body that provides them (unlike grants, they do not come for free) 
 
 
 19the permit granting procedure could exceed 10% of total project costs49, thereby also increasing the 
investment and the overall electricity system cost and binding resources, which could be used more 
efficiently for the actual investment s necessary in grid infrastructure. 
In line with the results of the 2005 "TEN Energy Invest" study already presented in the 2010 impact 
assessment, the ratio “performed investments” on ”sch eduled investments” in electricity could be as 
low as 50% for the coming decade, given the incr eased levels of local opposition and associated media 
focus on certain projects since 200550. This business-as-usual scenario  can be compared to the 
planning presented in the 2010 electricity TYNDP: Despite conservative estimates for commissioning 
dates, almost 30% of all projects identified foresee  completion in or after 2020 or have not set a 
commissioning date at all. This applies in particul ar to 35 transboundary projects listed in the 2010 
TYNDP. 
Applying these results to the total investment needs in electricity of EUR 100 bn (excluding smart grid 
investments), it can be estimated that up to EUR 50 bn worth of projects could be subject to delays 
beyond 2020 and jeopardize the efforts of the EU to meet the Union's 2020 energy and climate 
objectives. This number has been largely confirmed by national regulators51. 
Concerning requirements set by environmental legislation , an analysis of the current TYNDP 
showed that about 20 projects may face difficu lties due to conflicts with Natura2000 areas. EU 
environmental legislation leaves substantial flexibili ty to the MS competent authorities to solve the 
conflicting objectives between security  of supply and renewables integr ation and the protection of the 
local wild life. If these conflicts are not satisfactorily solved, some  of these energy infrastructure 
projects may be not be delivered. 
Nationally focused regulation , lack of cost allocation solutions and difficult coordination between 
NRAs and TSOs would further delay the realisati on of projects with cross-border impacts and 
increasingly asymmetric costs and benefits. This will particularly affect the implementation of the 
identified infrastructure priorities, which are mainly  based on cross-border or even regional projects. 
Insufficient risk-related incentives in line with policy objectives could lead to lock-in situations with 
infrastructures, which in the short term contri bute to energy and climate policy objectives (e.g. 
emission savings) but generate  fewer benefits in view of longer term objectives. 
Concerning electricity  interconnectors , between 2000 and 2011, about 30 cross-border electricity 
projects involving EU Member States have been commissioned, out of which 25 concerned new lines (see list in Annex 15). By comparison, the 2010 TYNDP  foresees a total of 76 cross-border projects, 
out of which 58 projects concern new lines for a tota l value estimated by the Commission at over EUR 
31 bn. In the absence of new cost allocation rul es, it is unlikely that existing regulation and new 
measures described above alone will allow completing the internal market, wh ile adapting effectively 
to the fast rising electricity flows from variable  renewable generation and the ensuing needs for 
balancing and storage capacities, in a contex t of rapidly changing national energy policies
52. This 
could also endanger the reliable operation of the European electricity grid as a whole53. Assuming a 
business-as-usual development pace, only about 25 out of the 58 needed interconnectors can be 
expected to be online by 2020. This would leave about 30 projects or EUR 16 bn at risk.  
                                                 
49 This estimation is based on empiri cal data provided by various TSOs. 
50 The ratio is even lower in the cas e of Germany: The 2010 DENA network study II identifies a need of grid 
extension of 3,500km between 2015 and 2020. A first DE NA study in 2005 had estimated a need of 850km, of 
which less than 100km have so far been completed. 
51  "The CEER survey suggests that the volume of investmen ts being delayed due to planning procedures, licensing 
and lack of public acceptance is likely to be si gnificantly higher [than EUR 40 bn, the initial Commission 
estimate]."  ("European Infrastructure Package: Investment needs and financing mechanisms – Financing Task 
Force conclusions", reference C11-FTF-02-01, 23 March 2011). 
52  Following the tsunami and ensuing nuclear accident at  Fukushima (Japan) in March 2011, Germany decided in 
June 2011 to phase out its nuclear power generation capaci ties by 2022, while a referendum in Italy reverted a 
previous decision to develop new nuclear power plants. Several other Member States are currently reconsidering 
their approach to nuclear approach. This will have im portant consequences on the electricity mix until 2020 and 
beyond, with corresponding impacts on th e need for additional electricity an d gas transmission infrastructure. 
53  Certain Central European operators in particular are wa rning about massive electrical  power flows of insufficient 
control, which could lead to bulk outages of suppl y and, under extreme conditi ons, even a total blackout. 
 
 20Concerning more specifically offshore grids  in the Northern Seas, under business-as-usual with merely 
national regulatory frameworks and without general cost allocation rules or risk-related incentives, 
internationally optimised solutions – including di rect connection of wind farms to international 
interconnectors or interconnectors between two wind farm hubs – will not be de veloped, while radial 
solutions will continue to be the preferred op tion of TSOs connecting new individual wind farms54. 
This would affect roughly EUR 10 bn out of a total investment of EUR 30 bn foreseen up to 2020 and 
prevent offshore grids from starting to develop into a meshed network already by 202055, increasing 
long-term costs and preventing optimal renewables and market integration at European level, also in 
view of developing a continental electricity highways system. 
Concerning innovative investments in electricity storage and smart grids , it can be expected that these 
will progress only at slow pace under BAU, given the ri sks inherent to such projects, the uncertain 
allocation of costs and benefits and the insufficiency  of existing incentives. With regard to smart grids 
in particular, failure to act at EU level might al so lead to insufficient integration of large-scale 
renewables capacities and deployment of electric vehicles as well as lack of regional cross-border 
demand-supply optimisation. As a result, peak demand in electricity could be up to 5% higher by 2020 
and up to 8% by 2030 respectively56, with corresponding needs for inv estment in expensive peak load 
and back-up generation assets. 
With regard to gas networks , the years 2000-2011 saw considerable development of new storages and 
LNG terminals with an upward trend throughout th e period. Gas interconnectors, linking EU regional 
gas markets, however, have only developed sl owly. While several new import pipelines are 
successfully coming online in the North and South of the EU, only 4 new gas interconnectors were 
built in the past decade. The EEPR support has had a significant impact in accelerating major 
interconnector investments in 2011 (PL-CZ, HU- CR, RO-HU). Other projects were and are being 
delivered on the basis of exemptions (see Annex 15). 
Concerning planned future investments, the 2011 TYNDP considers higher investment needs of EUR 
89 bn for the period 2011-2020 than those estimated in the 2010 impact assessment (EUR 70 bn). Projects worth about EUR 67.8 bn have not received a final investment decision (FID) yet, although 
they will, according to ENTSOG, contribute most to enhancing security of gas supply, creating 
flexible gas networks for market integration and linking isolated regions. Most of them are cross-
border (EUR 58 bn). Currently planned FID projects,  notably in storage, will only address additional 
demand under severe weather conditions  (see Annex 15). It can therefore be concluded that under a 
business-as-usual development scenario and in the light of past investments, the value of projects at 
risk of not being delivered could be significantl y higher than the EUR 10 bn  estimated in the 2010 
impact assessment, in particular with regard to interconnectors.  
Concerning CO2 transportation , as already explained in the 2010 impact assessment, most of the 
potential EUR 2.5 bn investment needed over the period 2010-2020 will not be delivered under 
business-as-usual. 
Business as usual would also mean the continuation of the current TEN-E approach to financing , 
with limited amounts of EU funding focussed on studies rather than works57 and no reiteration of the 
                                                 
54  The Dutch-German grid operator TenneT, which as  of March 2011 had over 7 GW of offshore wind farm 
connection projects ongoing or planned in the German North Sea, indica ted regulatory clarity among the key 
challenges for the feasibility and commercial viability of its projects. Operators in the United Kingdom have also 
indicated that the current round 3 tender process for offs hore wind farm developments c ould lead to uncontrolled 
point-to-point connections onshore without  overall optimisation, e.g. by deve loping integrated hub-and-spoke grid 
designs, as the latter involve too high a nd risky investments. This could lead to increased costs and difficulties for 
onshore onwards transmission on already fully used networ ks. NRAs have argued that hub solutions could develop 
in certain Member States of the NSCOGI from 2015 onwards. Results from the OffshoreGrid study show however 
that "teeing in", i.e. directly conn ecting wind farms into an interconnector , or linking two wind farm hubs in two 
different Member States through an interconnector makes socio-economic se nse in many cases, notably if the 
concerned wind farms are far from shore. 
55  Commission estimation, based on OffshoreGrid study results. 
56  Source: IEA, April 2011 
57  In the 2007-2009 period, about 65% of the allocated TEN -E funds were dedicated to studies (45M€), while 35% 
went to works (25M€). 
 
 21European Energy Programme for Recovery. As a r esult, projects of European significance would 
continue to mainly receive EU grants for feasi bility and front-end engineering and design studies. 
Financial support for the construction of projects w ould remain very limited: An expected EUR 55M 
of the available funds of EUR 155M would cover works expenses. In addition, EU allowed co-
financing rates for works would continue to be in sufficient to boost the implementation of certain 
projects. Indeed, as demonstrated by the EEPR expe rience, for projects aiming at increasing security 
of supply, a co-financing rate of 50% or more can be necessary to unblock the project while the 
current TEN-E co-financing rate is ca pped at 10% of the construction costs58. As a result, only 
investments with a sufficiently high direct and short- term benefit for the investor(s) would be realised, 
which would be insufficient to meet the challenge  arising from the step change in investments59. 
Concerning the other contributions to infrastructure financing , it can expected that the EIB lending 
trends to energy grid projects observed over the l ast couple of years would not be maintained. While 
the EIB's lending volume to the energy infrastructure industry rose from EUR 2.5 bn in 2007 to 
EUR 6 bn in 2010 (with about EUR 3 bn for energy transmission and EUR 3 bn for energy distribution), the EIB Board of Governors has made it clear that it did not wish for extended EIB lending towards energy grid infrastructures, with lendi ng volumes returning to pre-crisis levels, i.e. 
decreasing by roughly one third compared to their peak in 2010. Depending on the evolution of macroeconomic conditions and the sp eed of economic recove ry in EU economies, this downside effect 
could be partly compensated by a renewed inter est from commercial banks in lending to regulated, 
risk-free activities. 
On the equity side, equity capital provision will con tinue to be dominated by government involvement, 
as a large number of European TSOs have public institu tions as their majority shareholders. This will 
limit the potential involvement of external sharehol ders, leaving internal equity stemming from the 
TSO's own operational revenues as the main source of basic financing for future infrastructure 
investments. However, given the strong constraints on public finances for the coming years, it can be 
expected that, where external equity investments are feasible, such equity injections will be sought as 
an alternative. However, it might prove difficult for the TSO sector to attract sufficient amounts of 
such investments, given the profile of relativ ely low returns (less than  10%) for low risks. 
In any case, even if there were sufficient debt a nd equity funds available under business as usual to 
meet the EUR 210 bn investment challenge, these mark et-based funds will not be sufficient to deliver 
the more complicated types of projects discussed a bove. But with a mere continuation of EU grants 
made available during the 2007-2013 period (exc luding the EEPR) and given the likely future 
evolution of (repayable) loans provided by financ ial institutions, far less than EUR 2 bn of (non-
research) grants would be available for the pe riod after 2013 up to 2020 under business-as-usual. This 
amount will be severely insufficient to satisfy the funding needs expected, given the identified 
investments and their urgency until 2020.  
As a result of these trends of the baseline scenario, the Commission estimates that a significant 
share of the needed investment of approximate ly EUR 200 bn until 2020 will not be delivered on 
time under the existing framework. This will make the achievement of the EU's energy and 
climate policy objectives in terms of renewables deployment and emission reduction by 2020 
impossible, but it will also seriously hinder market  integration, diversification and security of 
supply. Lack of interconnections will reduce o pportunities for system optimisation, increase the 
risk of disruption and trigger additional costly back-up and balancing generation investments. Supplying energy and balancing supply and demand will become more expensive, with the corresponding effects on the competitiveness of European industries, consumers and growth. 
                                                 
58  Grants, however, would not provide always the right in centives to invest.  Indeed, as mentioned in Chapter 2 
Article 109 of the EU financial regulation, grants may not  have the purpose or effect of producing a profit for the 
beneficiary. Consequently, while having a positive impact  on network tariffs as the corresponding costs are not 
passed through to the final consumer through the tariffs –,  grants could be perceive d as a missed opportunity to 
make business (by excluding the possibility for TSOs to earn revenues on the corresponding asset). 
59  See also conclusions from the 2009 TEN-E Impl ementation Report (COM(2010)203 and SEC(2010)505) and 
SEC(2010)1396. 
 
 225. KEY PLAYERS AND AFFECTED POPULATION  
All EU citizens are affected by future energy po licy as competitive, secure and sustainable energy 
supply is at the heart of any economic activity. Energy is a daily need in a modern world and is mostly taken for granted in Europe. More specifically, almo st all actors in the energy sector and beyond are 
affected by the proposal: 
• Transmission and distribution system operators will be first and foremost affected, as any new 
initiative will touch upon pla nning and realisation of new transmission infrastructure; 
• Promoters and operators of existing and new power plants as well as gas suppliers, both within the 
EU and in third countries, as a new policy will have an impact on the evolution of network 
capacity all across the EU and in its neighbour countries. 
• Member State governments, admini strations, specialised technica l and environmental authorities 
(at national, regional or local level) and regulat ors who will be in charge of implementing and 
applying any new rules related to the identificati on of projects of common interest as well as their 
implementation through planning, permit  granting, regulation and financing; 
• Energy consumers (both citizens and businesses), as energy infrastructure investments will 
negatively affect final energy prices, while bette r interconnected, optimised and smarter grids will 
contribute to better balancing of energy suppl y and demand and increasing competition and hence 
influence positively the final energy  price for electricity and gas; 
• Landowners as well as citizens in the neighbourhood of  new infrastructure, that might be affected 
temporarily (construction) or permanently (local  environmental, safety and health impacts or 
visual impairment etc.), and corresponding stake holder organisations (e.g. environmental NGOs). 
6. EU
 RIGHT TO ACT  
The EU's competence in the area of energy is en shrined in the Treaty on the Functioning of the 
European Union (TFEU), Article 19460. The EU's role needs to respect  the principles of subsidiarity 
and proportionality. 
Energy transmission infrastructure (including an  interconnected off-shore grid and smart grid 
infrastructure) has Trans-European or at least cr oss-border nature or impacts. Member State level 
regulation is not suited and individual national admi nistrations have no competence to deal with these 
infrastructures as a whole. From an economic perspec tive, energy network developments can best be 
achieved when planned with a European perspectiv e, encompassing both EU and Member State action 
while respecting their respective competences.  A bigger market can also better encourage 
development of innovative technologies for transmissi on and distribution of energy and financing of 
large-scale investments such as those foreseen among the energy infrastructure priorities.  
Energy networks are therefore c overed under Article 170 and 171 TFEU.  Article 170 specifies: 
“The Union shall contribute to the establishment and development of trans-European networks in the 
areas of transport, telecommunications and energy infrastructures”. Article 171 sets the obligation that 
“the Union shall establish a series of guidelines c overing the objectives, priorities and broad lines of 
measures envisaged in the sphere of trans-Europ ean networks; these guidelines shall identify projects 
of common interest”. 
Following the Commission's November 2010 communication on energy infrastructure priorities, the 
28 February 2011 TTE Council specifically asked th e Commission to present, in autumn 2011, an 
initiative covering the main areas of action foreseen  in the "Communication on energy infrastructure 
priorities for 2020 and beyond" and aiming in particul ar at "streamlining and improving authorisation 
procedures, facilitating public acceptance", and at "creating the necessary fra mework and incentives 
                                                 
60  “In the context of the establishment a nd functioning of the internal market and with regard for the need to preserve 
and improve the environment, Union policy on energy shall aim, in a spirit of solidarity between Member States, 
to: (a) ensure the functioning of the energy market; (b) ensu re 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.” 
 
 23for delivering infrastructure projects under the identifie d priorities, notably with regard to cross-border 
allocation of costs and benefits and their reflection in tariffs"61. 
Concerning more specifically permit granting procedures , Article 171-2 TFEU on trans-European 
networks states that "Member States shall, in liaison with the Commission, coordinate among themselves the policies pursued at national leve l which may have a significant impact on the 
achievement of the objectives referred to in Artic le 170". Moreover, Article 194-2 TFEU allows the 
EU to establish the measures necessary to prom ote the interconnection of energy networks. 
Furthermore, Article 171-2 states that "the Commis sion may, in close cooperation with the Member 
State, take any useful initiative to promote such [M ember State] coordination". Hence, the formulation 
of broad measures to create a framework, within which Member States carry out the permit granting procedures according to their national specificities,  to the aim of accelerating the permit granting 
process, falls in the remit of the EU. Frequent ca lls of industry as well as the acknowledgement of the 
European Council in February 2011 that "it is im portant to streamline and improve authorisation 
procedures, while respecting national competen ces and procedures, for the building of new 
infrastructure" demonstrated that most Member St ates have so far not been able to resolve the 
prevailing problems satisfactorily at national level. 
7. O
BJECTIVES  
7.1. General objective 
The general objective of this initiative is to ensure sufficient and timely development of gas 
transmission, storage and LNG/CN G infrastructure, electricity transmission, storage and smart 
grid infrastructure as well as oil and CO 2 transmission infrastructure across the EU  and in its 
neighbourhood in order to: 
• further develop the internal energy market by  interconnecting Member States and connecting 
island, landlocked and peri pheral Member States with the central regions of the Union, so as 
to ensure energy provision at afford able prices to European customers, 
• ensure security of supply, 
• meet the EU’s energy and climate goals, both in terms of binding targets up to 2020 and of 
longer term emission reduction. 
7.2. Specific objectives 
More specifically, this initiative aims at impl ementing, by 2020, the trans-European energy 
infrastructure priority corridors as defined by the February 2011 European Council conclusions. To 
this end, it wants to: 
a) Streamline permit granting procedures to significantly reduce their duration for projects of 
common interest and increase public involveme nt and acceptance for the implementation of 
such projects; 
b) Facilitate the regulatory treatment of projects of common interest in electricity and gas by 
allocating costs depending on the benefits provi ded and ensuring allowed returns are in line 
with risks incurred; 
c) Ensure implementation of projects of common interest by providing necessary market-based 
and direct EU financial support. 
7.3. Consistency with other European policies 
This inititiave subscribes to the Europe 2020 strategy62, which put energy infrastructures at the 
forefront as part of the flagship initiative "Resour ce efficient Europe". It underlined the need to 
urgently upgrade Europe's networks towards a Eur opean "smart supergrid", interconnecting them at 
the continental level, in particular to integrate renewable energy sources. The priorities identified and 
                                                 
61  http://register.consiliu m.europa.eu/pdf/en/11/st06/st06207-re01.en11.pdf   
62  COM(2010) 2020, 3.3.2010 
 
 24the measures proposed in this initiative with regard  to permit granting, regulation and financing are 
fully in line with these objectives. 
The upcoming legislative proposal forms a logical  package with the “Connecting Europe Facility” 
(CEF) proposed by the Commission, which will be th e subject of a separate regulation. This initiative 
will replace the existing TEN-E policy guidelines63. It will set the infrastructure priorities for the 
coming decade and provide for specific measures c oncerning permit granting and regulatory issues to 
ensure their implementation. 
With regard to financing, this initiative will only fi x eligibility rules for projects of common interest to 
receive EU financial assistance. The award of th is assistance will be governed by common rules for 
energy, transport and digital infrastructures in the C EF. The latter will in particular provide for the use 
of grants for studies and works concerning ener gy infrastructures. But it will also open up the 
possibility to use some of the EU budget allocated to energy infrastructures through different financial 
instruments, notably debt and equity instru ments and project bonds. These mechanisms will be 
presented separately under the EU's new financia l regulation for the next multi-annual financial 
framework. As a result, part of the budget which w ill be available for EU financial aid to energy 
projects would be earmarked to contribute to the cost of the bond enhancement mechanisms and other 
debt and equity instruments. As such, the CEF will complement the measures in the field of permit granting and regulation provided by this initiative. 
The CEF, thanks to this Regulation, will be able to concentrate all EU funding for industrial-scale 
energy transmission infrastructure of European releva nce (i.e. with significant cross-border impacts) in 
one instrument, including for projects that involve third countries. Available funds under the Cohesion Policy will be dedicated to infrastructure projects of national or regional importance, while funding 
under the Common Strategic Framework for Research  and Innovation will go to pre-industrial scale 
projects up to the demonstration level. 
Furthermore, the importance of strategic ener gy interconnections with  our neighbours and key 
suppliers was underlined in the Europe 2020 Strategy,  which notably highlighted the need to promote 
energy infrastructure projects in the Baltic, Balkan , Mediterranean and Eurasian regions. The Joint 
Communication of the Commission and the High Representative “A new response to a changing 
Neighbourhood” adopted on 25 May 2011
64 underlines the need to enhance energy cooperation, 
including on energy infrastructures, with neighbouring countries. The Joint Communication of the Commision and the High Representative "A Partnership for Democracy and Shared Prosperity" issued on 8 March 2011
65 calls notably for the establishment of "an EU-South Mediterranean Energy 
Community" and for an "EU-Mediterranean part nership in the production and management of 
renewables". Development of energy infrastructures of common interest is also a key objective of the 
Eastern Partnership Platform on Energy Security . All these developments fall within the policy 
objective of reinforcing the external dimension of our energy policy as called upon by the 4th February 
2011 European Council Conclusions. Key orientations , including as regards infrastructures, will be 
developed in the Commission Communication "The EU Energy Policy: Engaging with Partners 
beyond Our Borders" to be adopted in September 2011. 
This initiative is also a necessary pre-condition for th e achievement of the two binding targets of 20% 
share of renewables and 20% of greenhouse gas emi ssion reductions by 2020 and aims to be in line 
with the pathway set out in the Commission’ s Communication on a Roadmap for moving to a 
competitive low-carbon economy in 2050 and the EU's long term objective of an 80-95% reduction in 
greenhouse gas emissions by 2050 compared to 1990 levels66. Through the promotion of smart grid 
technologies, it also facilitates de mand-side efficiency and enables electrification of transport. The 
investments promoted by this initiative correspond to a "no regret strategy". As such, it provides an 
                                                 
63  Note that the Commission is preparing in paralle l a revision of the guidelines for Trans-European 
Networks in Transport and new guidelines for Trans-European Networks for information and 
communication technologies. 
64  COM(2011) 303, 25.5.2011 
65  COM(2011) 200 
66  COM(2011) 112 in combination with SEC(2011)288 
 
 25important contribution to the Energy Roadmap 2050, which is currently being prepared for adoption 
by the Commission in late 2011. In line with th e White Paper on adaptation to climate change67, the 
initiative aims at ensuring that due considerati on is also given to this important issue. 
The objectives of this initiative are furthermore consistent with EU policies on competitiveness and 
innovation. Finally, this initiative is without prej udice to and does not entail any formal amendment of 
existing EU environmental legislation. 
8. POLICY OPTIONS  
In order to better analyse solutions to the problem s identified above, policy options will be presented 
and discussed for each policy area below (see Table 3). All the options are coherent with the 
overarching EU objectives, strategies and priorities. A preliminary analysis will allow discarding those 
suboptions with the least positive impact. 
Policy area A: Permit granting, stakeh older involvement and compensation 
Option A.0 Business as usual 
Option A.1 Establishment of a regime of Common European Interest 
Option A.2 Organisation and limitation in  time of the permit granting process  
 Element A.2.1: Organisation of  the permit granting process 
 Suboption 
A.2.1.a Leading Authority without decision-making power at national level 
(“light one-stop shop”) 
 Suboption 
A.2.1.b Leading Authority with decision-making power at national level 
(“full one-stop shop”) 
 Suboption 
A.2.1.c Cross-border Leading Authority with European Authority of Last 
Resort and European permit granting procedure 
 Element A.2.2: Limitation in time of the permit granting process  
 Suboption 
A.2.2.a Requirement for Member States to  establish time limits for each 
individual PCI 
 Suboption 
A.2.2.b Legally-binding time limits established by stakeholders in the 
framework of the regional initiatives 
 Suboption 
A.2.2.c Legally-binding time limit established by the EU legislative act 
Option A.3 Establishment of a regime of Common European Interest and organisation and 
limitation in time of the permit granting process 
Policy area B: Regulation  
Option B.0 Business as usual 
Option B.1 Cost allocation 
 Suboption B.1.a EU transmission tariff 
 Suboption B.1.b Ex-ante cost allocation 
 Suboption B.1.c Ex-ante cost allocation with ex-post adjustment 
Option B.2 Investment incentives 
 Suboption B.2.a Risk-related incentives for PCIs 
 Suboption B.2.b Penalty and enforcement action for PCIs 
Option B.3 Ex-ante cost allocation and risk-related incentives for PCIs 
Policy area C: Financing  
Option C.0 Business as usual 
Option C.1 Risk sharing instruments 
Option C.2 Risk capital instruments  
Option C.3 Grant support for project construction 
                                                 
67  COM(2009) 147 
 
 26Option C.4 Combination of grants, risk sharing and risk capital instruments  
Table 3: Policy options  
8.1. Permit granting, stakeholder involvement  
This section presents the proposed policy options and suboptions regard ing permit granting and 
stakeholder involvement for electricity and gas PCI. The policy options are asse ssed with regard to the 
principles of subsidiarity and proportionality as well as their effectiveness and are reflected against the 
opinions of stakeholders conveyed in the context of  various public and stake holder consultations. Oil 
and CCS projects will not be subject to the proposed measures under the proposed legislative act. Only projects in electricity and gas are facing particular  urgency with a view to their contribution to the 
2020 objectives in terms of renewabl es generation and the prevention of climate change. This rationale 
does not apply to oil projects, and no major concer ns about lengthy permit granting procedures were 
raised by stakeholders. For CCS projects, there is lack of evidence for measures in the field of permit 
granting due to the relative novelty of the technology a nd the lack of concrete infrastructure projects at 
this stage, and the public debate on CCS is consid ered as not mature enough for measures to be put in 
place. 
OPTION A.0: Business as usual - best practice and information exchange 
Under this option, best-practice and information ex change to facilitate administrative permit granting 
procedures, including environmental assessments, and to improve transparency and public acceptance 
would be encouraged. The Commission would p ublish guidance documents and highlight best 
practices encountered in Member States. At Eur opean level, a communication campaign would be 
carried out, targeted at citizens to communicate bett er the costs and benefits of energy infrastructure 
and increase public awareness, which would co mplement activities at national level. 
Effectiveness, subsidia rity and proportionality  
This policy option is considered to be in line with the principles of subsidiarity and proportionality, as 
it would leave the implementation of measures to the Member States on a voluntary basis. The introduction of guidelines to enhance transparency  in the process and improve communication with 
citizens has been clearly advocated by the majority of respondents in public and stakeholder consultations, particularly by Member States and civil society. As however the majority of 
respondents also favoured the introduction of a one-stop shop concept and time limits, the 
effectiveness of guidelines without stronger implemen tation measures is clearly considered as limited. 
Several attempts (e.g. Commission Recommendation to improve permit granting procedures for TEN-
E projects
68, Commission guidance for environmental impact assessments for TEN-E projects69) were 
made to encourage Member States to shorten the duration of their permit granting processes, but the 
analyses conducted in the context of this impact  assessment, and the various Council conclusions 
mentioned in Chapter 6 demonstrate that prevaili ng problems have not been solved sufficiently at 
national level, with exception of a few Member States. Therefore, the effectiveness of voluntary measures is considered as limited, which w ould justify the need for binding rules.  
 
OPTION A.1: Establishment of a regime of common interest 
Under this policy option, a PCI would be allocated pr iority status compared to other projects in the 
field of energy infrastructure. This would include that, with the adoption of the list of PCI by all 
stakeholders involved in the competent fora, the necessity to implement a PCI would have to be 
                                                 
68  Commission Recommendation of 14 December 1998 concerning the improvement of authorisation 
procedures for trans-European energy networks, 
69  Commission staff working document - Accompanying document to the Communication from the 
Commission Trans-European Networks : Toward and integrated approach {COM(2007) 135 final}/ 
SEC/2007/0374 
 
 27acknowledged by all parties involved in the permit granting process70, such that it would not have to 
be demonstrated in dedicated tasks (such as writte n answers during public cons ultations) or procedures 
(such as the Déclaration d’Utilité Publique proce dure in France). In essence, after a PCI has been 
allocated a label of “common interest”, stakeholders  would not have the opportunity to question the 
necessity of a project anymore, but would be able to  focus efforts on the decision of the routing of the 
projects. This would be without prejudice to th e need of adequate communication with the public 
about the costs and benefits of a given project. In Me mber States where certain fast-track or priority 
procedures have been implemented, the highest priority level  possible would have to be applied, and 
authorities would have to give the most preferential treatment  possible in terms of resources when 
processing PCI related files. Responding to the cha llenges identified with regard to environmental 
legislation, Article 6(4)71 of the Habitats Directive and Article 4(7) of the Waterframework Directive 
would apply in that the least harmful route of a PCI could, despite negative implications for the site, be 
carried out for reasons of imperative public overriding in terest. Prior to the allocation of this status, the 
conditions of the environmental legislation in pl ace would have to be met: appropriate assessments 
would have been carried out, alternative soluti ons could not be identif ied, and all necessary 
compensatory measures would have to be taken. Th is rule would remove th e responsible authorities’ 
discretion to assess whether the project of imperati ve overriding public interest, as this would be 
decided by all stakeholders, including Member St ates, through the selection of the project in the 
context of the PCI identification process. A PCI coul d thus not be prohibited from being built due to 
negative impacts on the site, whilst the need to  carry out appropriate assessments is fully 
acknowledged so as to minimise the impact on pr otected habitats. Complementary guidelines would 
have to be prepared by the Commission regarding the significance of effects and scope of assessment 
as well as compensatory measures. 
Effectiveness, subsidia rity and proportionality  
These measures are considered to be of positive eff ectiveness regarding the de livery of projects, as 
PCIs would benefit from a priority treatment in Member States. Responses in public and stakeholder 
consultations stated that PCI should benefit from the same political support in the Member States as 
national priorities. Some Member States formally or  informally supported the allocation of the status 
of public overriding interest to PCI, although it was acknowledged that the question of compatibility 
with the EU acquis would have to be addressed. Ot her Member States as well as industry advocated at 
a more general level that the EU should take measu res to solve conflicts between environmental and 
energy/climate change objectives and not leave it to th e Member States’ authorities, and the European 
Parliament called on the Commission to present a corresponding proposal.72NGOs reacted rather 
reserved on particularly this rule, but some NGOs  signalled their willingness to support grid extension 
measures, provided that a coherent strategy with re gard to the integration of renewables is followed. 
Under this option, the allocation of the status of  "public overriding interest" would continue to be 
decided at national level, as the Member States are involved in the selection of projects and would have to approve the final list of PCIs. 
In conclusion, these measures are considered to be effective, solving the difficulties of environmental 
nature where necessary, giving the Member States appropriate stake in the decisions to take, and 
limiting the need to change national permit granting fra meworks. This option is thus considered in line 
with the  principles of subsidiarity and proportionality.  
 
OPTION A.2: Rules on the organisation and duration of the permit granting process 
                                                 
70  PCI defined as interconnection between points A and B, without prejudice to find the most suitable trajectory for 
this interconnection 
71  According to Article 6(4) of the Habitats Directive,  a project may be carried out for imperative reasons of 
overriding public interest in spite of a negative assessment of the implicati ons for the site, in the absence of 
satisfactory alternative solutions.  
72 European Parliament resolution of 5 July 2011 on energy infrastructure prirorities for 2020 and beyond 
(2011/2034(INI)) 
 
 28This option would establish concrete rules regard ing the framework within which permit granting 
procedures are carried out. These rules would comprise two main elements: organisation of the permit 
granting process and duration of the permit gran ting process. For each of these elements, three 
suboptions have been identified. 
Element A.2.1: Organisation of the permit granting process 
Suboption A.2.1.a:  Leading Authority without decision-making power at national level (“light 
one-stop shop”)  
MS would have to establish a single Leading Author ity at national level, responsible for the overall 
coordination of the permit granting process of the PCIs located in their respective territory. The 
Leading Authority would serve as the main interf ace for the project promoter, and would involve and 
aim at achieving a common understanding between a ll other authorities and stakeholders concerned, 
with the objective that the most appropriate decisi on or decisions are taken within the stipulated time 
limit. Concrete responsibilities would include the se t-up, implementation and monitoring of a permit 
granting schedule, scoping activities to  identify the issues to be covere d in the application documents, 
and the handling of consultation procedures, accord ing to guidelines for early and effective public 
involvement as part of the legislative proposal. These would include requirements to elaborate a 
manual of procedures for increased transparency for all stakeholders, and to agree on a consultation 
concept to be elaborated by the project promoters (providing for an informal public consultation 
before submission of the application file). Cr oss-border cooperation would be ensured through 
regional fora, regular meetings between Leading Authorities and th e elaboration of joint permit 
granting schedules. 
Suboption A.2.1.b:  Leading Authority with decision-making power at national level (“full one-
stop shop”) 
MS would have to designate a single Leading Aut hority at national level, which would have the 
responsibilities as outlined under Suboption A.2.1.a. At the end of the process, the Leading Authority would have to issue one comprehensive administ rative decision concerning the construction of the 
project.  
With regard to the decision-making competence of  the Leading Authority, Member States could 
choose between two schemes: 
Under the integrated scheme , the comprehensive administrative  decision issued by the Leading 
Authority would be the sole legally-binding deci sion resulting from the statutory permit granting 
procedure. Where other authorities are concerned, these could give their opinion as input to the procedure, which the Leading Authority would have  to take into account when taking the decision. 
The integrated permit granting scheme does not correspond to the concept of "integrated 
environmental assessments", as different environm ental authorities could give their opinion on 
different subject matters. 
Under the coordinated scheme , the comprehensive administrative decision could encompass multiple 
individual legally-binding decisions issued by the Leading Authority and other authorities concerned. 
The Leading Authority would have to establish, on a case-by-case basis, a reasonable time limit within 
which the individual decisions have to be issued . Provided that the provisions required by EU and 
national legislation are respected, the Leading Author ity could overrule an individual decision or take 
an individual decision on behalf of another authorit y concerned, if it is not delivered within the time 
limit and if the delay cannot be adequately justified,  or if it is not considered appropriate by the 
Leading Authority.  
Suboption A.2.1.c:
 Cross-border Leading Authority ("light one-stop shop") with European 
Authority of Last Resort and European permit granting procedure  
MS would have to establish jointly a cross-borde r Leading Authority which would coordinate the 
procedures for each PCI and be responsible for th e set-up, implementation and monitoring of the 
permit granting schedule. The national authorities involved in the process would retain their decision-
 
 29making competences.  In the event of an unjustified expiry of the final time limit for the final 
administrative decision, an Authority  of Last Resort at European level would take the final decision. 
At this stage, the PCI legislation, and a European  permit granting procedure would apply. It is the 
Authority of Last Resort to assess whether a delay is not justified. 
Effectiveness, subsidia rity and proportionality  
Consultations with stakeholders ha ve shown that the majority of respondents favours the concept of a 
one-stop shop  (79% of respondents of the public consultati on on permit granting). With regard to the 
competences of the one-stop shop concept, the pref erences of stakeholders were almost equally split 
between the options of a light one-stop shop versus  an authority with substantial decision-making 
power (full one-stop shop). Industry was slightly in favour of the centralisation of decision-making 
power. Of the Member States responses submitted, in cluding as reaction to the stakeholder workshops 
organised, seven explicitly supported the concept of the one-stop shop (with full decision-making 
power at national level: CZ, decision-making po wer at EU level: ES, LT, general support not 
specifying decision-making competence: CY, BE, FR, SE, no decision-making power: FI) whereas 
two opposed the idea (SL for fear of additional admini strative burden, DK due to subsidiarity). In six 
Member States, such concept already exists and w as explicitly advocated by most (UK, NL, IE, DE, 
IT, EL). Some of the latter advocated the need to introduce this concept (as well as other measures) 
across the EU, as in the case of cross-border projects delays in the neighbouring Member State 
significantly affect the domestic part of a project. It should also be noted at this point that the majority 
of respondents across stakeholder groups raised  public opposition as a major obstacle in the permit 
granting process, and that remedies to involve citi zens effectively and early in the process should be 
found. 
Responding to the various concerns raised, and in  light of the more detailed assessment of the 
suboptions in Annex 16, the introduction of a full one-stop shop with decision-making power has been 
identified as the most preferred suboption as it is c onsidered to strike the best balance between 
effectiveness in terms of reduction of the duration of the permit granting process and the principles of 
proportionality and subsidiarity. Th is suboption takes into account the experience in Member States 
where the introduction of a one-stop shop approach has been successful in reducing delivery times of 
the permits, and where decision-making power of the one-stop shop has been crucial for the authority 
to effectively drive the management process forward. Th e issues at stake, in particular with regard to 
environmental challenges, would continue to be ad equately addressed by this centralised approach, as 
under both the integrated and coordinated approach the authority in charge could continue to issue 
opinions/permits for its particular field of envir onmental competence. This has been proved in the 
Netherlands and in the UK. Cost-effectiveness w ould be given under this suboption as compliance 
costs would practically be the same for the designa tion of the Leading Authority under a light one-stop 
shop. However, the full one-stop shop would reduce the administrative costs spent on the handling of 
the procedures, as decisions could be taken more quickly.  
This suboption also reflects the concerns raised  with regard to issues of proportionality and 
subsidiarity, as decision-making remains with the Member States (no EU Authority of Last Resort), 
and it gives Member States the opportunity to choose one of two approaches (integrated vs 
coordinated scheme), therefore limiting the need for substantial reorganisation of the permit granting 
process. The one-stop shop is considered also as a crucial element in addressing the obstacles with 
regard to public resistance, as it would be respons ible to issue transparency guidelines and enforce 
certain rules related to public invo lvement which would be part of the legislative act, e.g. with regard 
to the appropriateness of the consultation strategy of  the project promoters, the enforcement of early 
public consultations and par ticipation in communication activities. It is expected that an authority with 
responsibility for the final decision has an intrinsic interest in effectively managing the communication 
process, for which e.g. the UK and the Netherlands , which have a similar approach to the proposed 
measures, provide good examples.  
Therefore, suboptions A.2.1.a, A2.1.c have been discarded at this stage. 
Element A.2.2 Duration of the permit granting process 
 
 30Suboption A.2.2.a: Requirement for Member States to establish time limits for each individual 
PCI 
Under this suboption, the legislative act would requi re Member States to establish time limits for each 
individual PCI, which allows to account for the national specificities of the permit granting processes 
and the characteristics of individual projects. Upon establishment of the Union-wide list of PCIs, the 
Leading Authority would have to define an adequa te time limit which it would communicate to the 
project promoter and other authorities concerned. In  the event that a time limit is not respected, 
sanction mechanisms could apply in those Memb er States where these are foreseen by national 
legislation. 
Suboption A.2.2.b:  Legally-binding time limits for PCIs established by stakeholders in the 
framework of the regional initiatives 
In the framework of the regional fora and in the context of the selection of PCI, MS, the national 
regulatory authority/ies, and possibl y the Leading Authority/ies and other relevant stakeholders invited 
(such as NGOs and citizens’ initiativ es) would have to jointly agree on individual time limits for the 
permit granting process as well as the completion of the project of the respective PCI. The stakeholders would consequently have to sign an intergovernmental  agreement, which would indicate 
the time limits agreed upon. This document woul d serve as the legal basis for possible sanction 
mechanisms to be initiated at EU level,  if the time limit is not respected .  
Suboption A.2.2.c:
 Legally-binding time limit for PCIs established by the EU legislative act 
Under this suboption, the time between the start of  the permit granting process and the final positive or 
negative administrative decision concerning the c onstruction of the PCI could not exceed about 3-4 
years , which corresponds to today's EU27 average duration for the statutory procedure. The start of 
the permit granting process would be identified as the agreement on the notification of the project by 
the Leading Authority and the project promoter. This time frame would not include any judicial 
processes. In MS where parts of the procedures, incl uding spatial planning, do  not result in a legally-
binding permit, Leading Authorities would be required to ensure that their duration is well-integrated 
in the overall time frame. The time between the a cceptance of the submitted application documents by 
the Leading Authority and the final ad ministrative decision should not exceed 1 year . 
No automatic approval or rejection of the project w ould be linked to the expiry of the time limit. To 
effectively enforce the timely delivery of the proj ects, sanction mechanisms could be applied at EU 
level if projects are subject to significant unjustified delays. The Commission would have discretionary margin to assess whether delays are unjustified and sanction mechanisms should be 
applied. These would include infringement proce dures where MS fail to take appropriate action, 
complemented by reporting requirements. 
Effectiveness, subsidia rity and proportionality
 
Regarding time limits, the majority of stakeholders  who responded to the public consultation favoured 
their introduction (60%), particularly representativ es from industry. Four Member States explicitly 
supported this measure (CZ, CY, (SCTL), BE, LT) whereas two opposed it (SE fears that time limits 
could lead to bad preparation of  assessments and permits, DK due to subsidiarity). In some Member 
States, time limits already exist for the statutor y procedure (e.g. UK, IE, NL). Particularly NGOs 
warned of the risks of introducing time limits, as these could jeopardise democratic principles and 
lower environmental standards if procedures cannot be  carried out appropriately. A central issue raised 
was the consequence of the expiry of a deadline. Whereas it was mainly considered that time limits 
without appropriate implementing me asures and legal consequences in case of their expiry would not 
have substantial effects, automatic approvals or rejections of the project were mainly considered as not 
viable options.  
Taking into account the range of opinions conveyed, as well as one of the overall objectives of the 
proposal, i.e. the achievement of the 2020 targets, th e prescription of time limits at EU level has been 
assessed as the most preferred suboption. As explai ned more in detail in Annex 16, the suboptions 
leaving more flexibility to Member States prove to be not practical in terms of their implementation, 
as the decision process on individual time limits would be too cumbersome, and as sanction 
 
 31mechanisms, which are considered  as necessary for the enforcement of time limits, would only be 
applied in Member States where these sanctions exist (the option of automatic approval or rejection of 
projects has been assessed as not feasible in line with  stakeholders' views). The legal grounds for the 
EU to act would be missing. However, taking into  account concerns especially raised by Member 
States with regard to subsidiarity, the preferred suboption would leave flexibility to the Member States 
to define individual time limits, including for the various stages of the process, and to set more ambitious deadlines if considered appropriate. As the time limit envisaged is expected to 
accommodate well already existing time limits in some  Member States, including for EIA procedures 
(average duration 1 year) and public  consultations (average duration 4-8 weeks), no substantial change 
of procedural law should be necessary (for more  explanations on the impacts see Chapter 9). 
Therefore, suboptions A.2.2.a, A2.1.b have been discarded at this stage. 
In conclusion, the preferred suboptions would set  a framework within which Member States could 
carry out their procedures according to national speci ficities, and are considered as most appropriate 
with regard to the effectiveness of the prescribed measures as well as ambitions with respect to the 
principles of proportionality and subsidiarity. 
OPTION A.3 Establishment of a regime of common European interest and rules on the 
organisation and duration of the permit granting process 
This option would include both option A.1 on the establishment of a regime of European common 
interest and selected suboptions under A.2 on the organisation and duration of the permit granting 
process. 
Effectiveness, subsidia rity and proportionality  
See explanations above. 
An overview establishing the link between the pr oblems identified in Chapter 3 and the policy 
measures  proposed in this Chapter is provided in A nnex 17, highlighting, inter alia, the benefits of a 
centralised approach through the establishment of a one-stop shop, as this con cept addresses most of 
the challenges described. 
8.2. Regulation 
OPTION B.0: Business as usual 
Under this option, no legislative action would be ta ken on regulatory issues related to investment in 
new electricity and gas infrastructures. Third p ackage guidelines already under preparation on capacity 
allocation and congestion management  would be completed and applied,  but no further attempts would 
be undertaken to establish cross-border cost alloca tion rules for new infrastructure and to provide 
specific incentives for certain  types of projects.  
Effectiveness, subsidia rity and proportionality  
The business as usual option relies on the future fu ll implementation and application of the third 
internal market rules by the Member States. As the Commission Communication of November 2010 
showed, given the urgency of the 2020 objectiv es, the business as usual is not an option.  
The public consultation of national regulatory auth orities, the ENTSOs and its network operators and 
investors illustrated that national incentive schemes ar e not necessarily oriented towards the EU wide 
climate and energy objectives, e.g. the rate of retu rn do not sufficiently re flect the risks faced by 
project promoters, and that the investment challenge  is not sufficiently taken into account by national 
regulatory authorities.  
The internal market framework is to provide fo r common cross-border rules on capacity allocation, 
tariffs and others, and is to give NRAs the compet ences to approve tariffs or methodologies. However, 
tariff structures and regulatory frameworks are likely to remain national in scope. The IEMP does not 
provide for a mechanism at EU level on how costs incurred in one country but for the benefit of 
another country should be recognized in the tariff systems. While today's tariffs are effective for 
 
 32national network expansion, they are not effective to  advance energy infrastructure investments with a 
view to the implementation of the EU energy and climate objectives. There is no top-down approach 
on the identification of costs and benefits from an EU  energy wide system perspective. There are no 
EU wide rules on sharing the costs of complex cross-border projects in particular where they are asymmetric (cost allocation) and deviating from 50-50 agreements between TSOs. In the light of the 
slow progress in past investments as outlined in the Annex Figures , without reinforced cooperation 
among all parties, including NRAs, networks opera tors, Member States and the Commission, the 
deployment of energy infrastructure will not be secure d from the third internal market package alone.  
 
OPTION B.1: Cost allocation 
To solve the cost allocation problems outlined above , rules are necessary to properly allocate costs as 
a function of the benefits or positive externalities obt ained and reflect this allocation accordingly in the 
network access tariffs paid by the beneficiaries. 
Suboption B.1.a:  EU transmission tariff 
  
Under this option, a small percenta ge of national tariffs in each Member State would be collected to 
fund PCIs. Such an EU wide tariff would require substantial harmonisation of tariff structures, a 
separate regulatory asset base under EU regulation- This risks creating distortions by establishing a 
distinction between tariffs for PCIs  and tariffs for other projects.  
Effectiveness, subsidia rity and proportionality  
While operators and academia consider an EU wide  transmission tariff as an effective solution, its 
degree of harmonization seems to be not proportiona te and is also likely to generate significant 
opposition from Member States and national regulators.  Such harmonisation seems premature, given 
the limited benefit provided compared to the likely difficulty to implement it and the possible 
distortion effects. Depending on the design, it could be perceived as a new EU energy tax added to the final energy prices which raises not only subsidiarity  concerns but ignores the differences with regard 
to the current level of development of grids in th e various Member States, notably as a result of past 
investment efforts, and hence the fact that some countries will have to invest much more over the 
coming 10 years than others.  
In the light of this, option B.1.a is therefore discarded and not assessed further .
 
 
Suboption B.1.b:  Ex-ante  cost allocation mechanism 
Under this option, PCIs would also be funded by national tariffs. However, TSOs and NRAs of 
directly concerned Member States and immediate neighbours would have to agree in a coordinated 
approval process, for each PCI , on an ex-ante cost allocation solution, which would, based on a cost-
benefit analysis73, identify how benefits are allocated between these Member States and distribute 
investment costs for the project among national ta riff schemes. To further accelerate the process, the 
time to agree on a common procedure and time sche dule for the regulatory treatment of such cross-
border PCIs would be limited and ACER be tasked to intervene in case of persistent disagreement. 
NRAs as represented by CEER and within ACER t askforces contributed to the examination of the 
scope for cost allocation with dedicated working papers (see Annex list). NRAs underlined that the 
principle should be a three-step-approach: costs s hould be levied on the users, beneficiaries and only 
then on taxpayers. Within the North Sea Countri es' Offshore Initiative a working group on regulatory 
issues concluded that cost allocation issues may arise with regard to advance capacity and the 
                                                 
73  This cost-benefit analysis will serve as a harmonised tool at EU level to evaluate the global optimality of 
infrastructure projects, based on common input data, grid  and market modelling and identify benefits overall 
benefits and costs, taking into acc ount various social, economic, environmental and climate externalities, including 
climate proofing. 
 
 33asymmetry of costs and benefits, in particular the benefits from RES support schemes. A procedure 
involving TSOs, NRAs and ACER was considered to  suit the purpose. NRAs underlined that existing 
cost allocation principles (ITC mechanism, congestion rents) and regulatory practise (e.g. open seasons for gas) largely suffice. The overall conclusi on was therefore that there is only a need for a 
general cost allocation principle along the three-st ep-approach and a framework  for an agreement.  
 
Suboption B.1.c:
 Ex-ante  cost allocation mechanism with ex-post  adjustment possibility 
This option would be identical to the previous one, but each agreement would have to contain a 
revision clause outlining the rules for ex post  adjustment. This would allo w changes in the allocation 
of variable benefits and costs to be take n into account during the lifetime of a project. 
NRAs suggested that some fixed cost element could be allocated ex-ante and that variable elements 
could be adjusted ex-post, depending on the regulat ory framework and its approach on how such ex-
post adjustments or risk sharing is done.  
OPTION B.2: Investment incentives 
Suboption B.2.a:  Risk-related incentives for PCIs 
In the workshops with NRAs it was repeatedly underlined that NRAs' independence needs to 
be respected to decide on the incentives and th at any incentive mechanism needs to be based 
on the tariff system and limited only to PCIs co mmensurate to the risks of the project. These 
views were also supported by Me mber States. These concerns were taken on board as this 
option would oblige NRAs to provide PCIs, wh ich have demonstrated higher risks than 
business-as-usual projects, adequate incentives for their implementation, in line with the principle of risk-adjuste d return and the requirement to provide for long-term incentives via 
tariffs under the third package. 
Eligible risks would be: 
- Technology risks for new transmission technologies; 
- Risks related to offshore transmission grid development; 
- Specific risks related to operations and revenue streams, notably for pr ojects with long-term 
benefits. 
There would be no automaticity for these specific  incentives, but TSOs would have to provide 
sufficient justification for the reasonableness of th e chosen technology and proof for the extra risks 
claimed. This should also ensure that the incentive covers an action that can be controlled by the TSO. 
Regulators would be able to choose from a set of options to trigger investments, including notably: - Equity adders to match risks and regulated re turns: The mark-up of such adders should be 
commensurate to the risk effec tively incurred by the operator. 
- Rules for anticipatory investment: These rules could involve capacity payments, regulated 
auctions, mandatory capacity obligations and other long-term incentives. 
- Early recognition of efficiently incurred pre-ope ration costs not already covered under existing 
regulation. 
Regulators would have to justify their choice. Th is decision-making at national level would also 
reflect the fact that financial incentives for TSO s differ across the EU depending on the regulatory 
framework, the unbundling regime, the ownership as well as shareholder structures. The 
appropriateness of a particular incentive schem e will therefore depend on the country, TSO and 
project in question. 
Effectiveness, subsidia rity and proportionality
 
This option is considered to be the most effective option to provide the market participants with the 
incentives to make the necessary investments. In order to ensure proportionality of such incentive 
schemes and their compliance with state aid rules,  the incentives should be only limited to the cases 
 
 34where PCIs are affected (limited number of EU ad ded value projects) AND in relation to the risks 
incurred and set via tariff regulation. In line with the principle of subsidiarity, the NRAs are to decide 
on the choice of incentives on the basis of the justif ications provided by operators in line with the 
country specific regulatory framework and network a nd industry structure. In line with the market-
based approach and confirming NRA views, the po ssible use of public funding under the Connecting 
Europe Facility to address specific project risks, s hould only be envisaged once the market operators 
and regulatory measures have be exhausted.  
 
Suboption B.2.b:  Penalties and enforcement action for PCIs 
As the alternative to incentive regulation under option B.2.a this option would build on 3rd IEMP 
legislation and aims giving NRAs  and ACER the regulatory powers to enforce the implementation of 
all PCIs 74 In case of persistent non-delivery of a PCI by  one or several TSOs, despite their inclusion 
in the TYNDP, NRAs would be enabled to impos e penalties on the concerned TSOs, e.g. by reducing 
their regulated revenues, or ensure project implem entation, e.g. through application of the measures 
under Article 22. In case NRAs cannot agree, AC ER would ensure the mediation.Article 22 of 
Directive 2009/72/EC and 2009/73/EC gives NRAs the ri ght, with regard to independent transmission 
operators (ITO), to ensure the implementation of a ll projects considered to be necessary in the short 
term according to the TYNDP. If an investment is not carried out by the TSO, the NRA can either 
force the TSO to execute it, organise a tender pro cedure open to any investor or oblige the TSO to 
accept a capital increase to finance the said investment and allow investors to participate in the capital. 
The 3rd IEMP strictly provides for such enforcement only for the ITO unbundling model and does not 
address the question of how cross-border projects would be jointly enforced. 
Effectiveness, subsidia rity and proportionality  
Such enforcement would be effective for the im plementation of the PCIs, proportionate and fully 
respect the subsidiarity of the NRAs and in line with  internal market rules. However, in practice NRAs 
may refrain from implementing such penalties, in part icular the tender procedure or equity increase for 
other investors, due to the main characteristics of the TSO ownership structure with high state 
involvement.  
 
OPTION B.3: Ex-ante cost allocation and risk-related incentives for PCIs 
This option would combine option B.1.B for an ex ante  cost allocation mechanism and option B.2.a 
introducing risk related incentives for projects of common interest. 
8.3. Financing 
OPTION C.0: Business as usual – continuation  of the TEN-E with similar budget under the 
Connecting Europe Facility  
Under this option, the financial support under the Connecting Europe Facility to energy infrastructures 
would be limited to mainly co-financing feasibility and project preparation (front-end engineering and 
design and similar) studies (continuation of the pr inciples of the current TEN-E programme). No 
support would be available under the TEN-E budge t for projects outside the EU, which would 
continue to benefit from various other EU pr ogrammes. Targeting EU support on major energy 
infrastructure in third countries that would contri bute to improving the EU’s security of supply, 
connecting renewables or increasing the EU’s ener gy systems’ flexibility will not be possible. 
Structural funds would provide very limited suppor t to energy infrastructure projects in eligible 
Member States, without the possibility to channel funds  to projects of the highest European relevance. 
The range of financial facilities availa ble through the EIB would not evolve. 
                                                 
74  The Commission argues in its interpretative note on the role s of NRAs that the rule of Article 22 should not prevent 
NRAs from applying the mechanism to all TSOs  independently from the unbundling option chosen. 
 
 35OPTION C.1: Risk sharing instruments 
Under this option, the EU financ ial support under the Connecting Eur ope Facility would be channelled 
to projects through financing instruments and f acilities made available jointly with financial 
institutions, for example the EIB. The instrument s proposed would be under the debt and equity 
platform principles proposed by the European Commission75. By accepting to share certain risks with 
financial institutions, the Commission would enable them to address more exhaustively the financing 
needs of energy projects. Projects could benefit from an improved access to bond and loan financing 
on favourable terms (extended duration, targeted gua rantees, and increased debt financing volumes). 
The risk sharing mechanism will require that the EU provides a financial institution with budgetary 
resources to provision for portions of statistica lly possible losses that operations under such 
instruments could generate. Normally, the risk taking would be compensated via a risk premium 
charged to the benefiting projects. The Union cont ribution would be capped at an agreed budgetary 
amount, thereby strictly limiting budgetary exposure  and determining the size of such a facility. 
The following instruments or facilities could be inter alia envisaged: 
• project bond credit enhancement: This would be  particularly suited for larger projects; 
• lending enhancement (enabling a fi nancial institution to provide e.g. loans with longer repayment 
period better aligned with the economic lifetime of energy assets; increased lending volumes; 
construction phase bridging loans): Such measures would suit projects of all sizes; 
• enhancement facility (enabling a fina ncial institution to issue guarantees76 addressing individual 
project needs, including capacity utilisation guarantees77). 
OPTION C.2: Risk capital instruments 
Under this option, the EU financ ial support under the Connecting Europe  Facility would take the form 
of an investment in specific projects of common interest or a special purpose vehicle developing 
projects with the two-fold objective of a) providing  equity capital needed to attract investors and 
financiers, and/or b) kick-starting certain ri skier projects. Support could take the form of: 
• Equity support: The EU would provide capital to equity fund(s) (directly or via a financial 
institution) which actively invest in targeted pr ojects. In order to make co-investment more 
attractive to third party investors and provide them with fair returns, the return target on the EU 
share could be subordinated vis-à-vis other inv estors even though the reward structure should 
reflect the risk taken as far as feasible. The EU part icipation in the funds woul d be in line with the 
main principles of the debt and equity platform proposed by the European Commission. 
• Seed capital: In order to accelerate more complex, innovative or multi-stakeholder projects, EU 
financial aid would be used as seed capital to help  moving a project from the “studied concept” to 
the project phase. Depending on the individual needs of each project, seed capital could also fund 
the preparation of design, legal assistance for necessary agreements, the setting-up of dedicated 
project development companies, or the process to obtain permits or launch procurement. In return for providing such seed capital, the EU would r eceive an equity share in the project, which could 
be bought back by other shareholders at a pre- determined future date (compulsory put option). 
OPTION C.3: Grant support to project construction 
Under this option, the EU would be able to suppor t projects of common interest with the Connecting 
Europe Facility in the electricity (transmission, st orage, smart grids) and gas sector (transmission, 
storage, LNG/CNG) for construction works (inc luding procurement of construction material), 
                                                 
75  European Commission, “A Budget for Europe 2020: th e current system of funding,  the challenges ahead, the 
results of stakeholders cons ultation and different options on the main horizontal and sectoral  issues”, Commission 
Staff Working Paper accompanying the Communicati on "A Budget for Europe 2020", SEC(2011) 868. 
76  Such a guarantee would be an on-budget instrument like LGTT and not imply any contin gent liability for the EU 
budget. 
77  This would guarantee that, in case the downside scenario  in capacity use materialis es after project commissioning, 
the promoter will be able to benefit from a liquidity facility  to cover the revenue shortfall and to serve its obligation 
towards debt providers. The mechanism would reflec t the LGTT instrument al ready existing under TEN-T. 
 
 36provided it has been demonstrated that the socio-ec onomic cost-benefit analysis yields a positive result 
(also taking into account various externalities) and th at the regulatory solutions proposed (notably cost 
allocation and risk-related incentives) alone are not sufficient to make project delivery possible. The 
EU could support up to 50% of the eligible cost of  projects and in case of security of supply projects 
up to 80%. The optimal rate of support would be assessed individually for each project. This option 
builds on what is already now possible under the existing TEN-E scheme (with a contribution capped 
at 10% of a project's eligible costs) and the precedence set by the EEPR programme. 
EU grants could also be made available on a repaya ble basis, to address the ri sk of advanced capacity 
provision. Such a grant would cover a portion of th e project's eligible construction costs and be 
repayable if the actual use of the infrastructure exceeds the short-term expectations and therefore 
ensures commercial viability of the project. In excep tional cases, if there is no interest (or even 
opposition) by operators to develop a project clear ly identified as being of common interest, an 
international tender could be la unched where grant financing could be offered as an incentive to 
interested investors.In addition to constructi on support, the EU would continue to co-finance 
feasibility and preparatory studies at co-financing rates of up to 80%, as is already the case under TEN-E today. Such support would be available to both mature and less mature projects, which need 
further feasibility studies to assess their viability and common interest. Grants would be distributed via 
calls for project proposals. 
OPTION C.4: Combination of grants, risk sharing and risk capital instruments 
Under this option, all the above forms of EU supp ort would be made available at EU level in the 
Connecting Europe Facility. The combination of mark et-based and direct financial support created this 
way would provide flexibility of providing the most cost-effective remedy to specific project risks and features at the various stages of development of the project. It should be noted that in case EU support 
is accompanied by national co-financing, or if Me mber States can decide upon the use of EU funding, 
the State aid rules (if applicable) must be respected, notably to ensure necessity and proportionality of 
the measure. 
9. A
NALYSIS OF IMPACTS  
This chapter analyses the impacts of the various po licy options and their sub options. We will thereby 
insist on the most relevant impacts for each policy ar ea. It should be noted that the evaluation of all 
business-as-usual options is done in chapter 4. 
9.1. Permit granting, stakeholder involvement and compensation 
In the following, we present an assessment of the economic, social and environmental impacts of the 
each of the short-listed suboptions78. 
OPTION A.1: Establishment of a regime of common European interest 
In terms of overall impact , this option is expected to have intermediate positive effects  as it would 
contribute to the timely delivery of significantly more projects than under BAU, provided appropriate measures on regulation and financing are in place. This result is based on the assumption that fast-track/priority procedures exist in 10 MS, but in onl y 5 MS this procedure is linked with a one-stop 
shop and/or time limit. In MS with fast-track/pri ority procedure alone the observed reduction in delays 
has been only of a few months
79. This option would also address those PCIs not realised under BAU 
because of lack of recognition of their necessity or public overriding interest, as e.g. written objections 
during public consultations on this matter would not have to be fo rmally answered and grounds for 
appeals would be more restricted. 
                                                 
78  Regarding economic impacts, on costs, a distinction is made between compliance costs and administrative costs. 
Since the permit granting process as such is defined as an  information obligation (according to IA Guidelines), all 
costs related to activities pursued within the permit gr anting process are classified as administrative costs. 
Compliance costs are classified as those costs related to the adaptation of national legislation and the establishment 
of the necessary structures by MS, as well as ad aptation of processes established by promoters. 
79  Roland Berger, 2011b. 
 
 37Concerning social impacts , citizens would be affected in that they would not have the possibility to 
formally question the necessity of a project  in the context of the permit granting procedures, e.g. in the 
form of written objections or in litigation procedures in  the form of appeals. However, this rule would 
be without prejudice to discussions related to the r outing of a particular PCI, and potentially necessary 
explanations about costs and benefits of a project, such that citizens would not be deprived of their 
right to be adequately informed. Further, a number of citizens will be affected by visual impacts of 
electricity overhead lines on their property and in their vicinity . Regarding safety and health issues, 
thresholds for electro-magnetic fields implemented by MS have to be respected when constructing 
electricity overhead lines, which are often lo wer than the recommendations given by the EU80. 
The impacts on the environment are not expected to increase greatly under the new regime  vis-à-vis 
the current one, given the assumption of earlier completion of projects rather than significantly increasing the overall volume. Impacts affect the local flora and fauna
81. Some short-term disturbances 
to animals and destruction of plants and habita ts may occur during construction work, and some 
permanent displacements of animals and destruction of  plants might take place due to the existence of 
underground cables, gas pipelines and electricity pylons. Further, overhead electricity lines might make it necessary to keep open vegetation in  corridors in wooden areas and cause habitat 
fragmentation to animal and plant species and di sturbances to birds. These impacts will vary 
depending on the project, but are considered to be rath er limited for electricity line projects, as, due to 
the size of electricity pylons only small areas are affected, and underground impacts of gas pipelines 
and cables are expected to be less important due to the limited existence of wildlife there. As regards 
specifically the impact of electricity lines on birds, there is only a minor risk of electric shocks of birds with high voltage lines
82. However, collision risks for large bodied  soaring bird species may be serious 
if no adequate mitigation measures are taken. A mi cro-level assessment of impacts on the environment 
cannot be carried out at this stage, as this is s ubject to the analysis to be carried out by project 
promoters under the relevant legislation in place. 
As regards particularly the measure related to the a llocation of the status of public overriding interest 
to PCIs in the context of the Habitats Directive, th e impact on the local flora and fauna is expected to 
be relevant for only a subset of the 20 projects identified as possibly in c onflict with Natura2000 areas, 
which are, however, crucial for the achievem ent of energy and climate policy objectives83. As 
explained in Chapter 4, a preliminary analysis h as been conducted to identify projects which may need 
to make use of the Lex Specialis, by matching, at an aggregate level, the possible route of the cross-
border projects taken up in the existing TYNDP with Na tura2000 areas. Yet, the final list of PCIs is 
subject to a selection process, and the identification of  possible conflicts with protected areas is subject 
to the environmental assessments to be carried out by project promoters. This means that the exact 
route of the PCI and the concrete alignment will be determined in the process comparing all 
alternatives and not before that. Therefore, a more detailed assessment of the impacts is not possible at 
this stage. With regard to legislation in the field of water policy, problems re lated to water issues have, 
in contrast to problems related to Natura2000 areas, not been stated as a major concern by stakeholders. Only limited use, if at all, is expected  to be made of the Lex Specialis in the framework 
of the Waterframework Directive, such that the impacts on inland surface, transitional, coastal and 
groundwater are expected to be minor. However, if  necessary, the legislative act would allow for the 
prioritisation of energy projects consistent with pr ovisions on the Habitats legislation. A more detailed 
analysis cannot be provided at this stage for th e same reasons valid for the assessments on flora and 
fauna, and since a comparison of aggregate data with the routing of relevant projects is not possible, as 
information on neither data nor the characteristics of  the project (whether surface, underground etc.) is 
sufficiently available at this stage. Overall, due to the requirement to carry out appropriate assessments 
                                                 
80  Council Recommendation 1999/519/EC on the limitation of exposure of the general publ ic to electromagnetic 
fields (0 Hz to 300 GHz). 
81  Short-term disturbances to animal s and destruction of plants and habita ts during construction work, permanent 
displacements of animals and destruct ion of plants due to the existence of underground cables, gas pipelines and 
electricity pylons. 
82  Haas, Dr. Dieter and Bernd Schürenberg, "Stromtod von Vögeln", p.16, January 2008. 
83  Immediate and strong impacts would only be expected if  PCIs were completely exempted from the obligation to 
carry out appropriate assessments. However,  this is not considered as viable with regard to bi odiversity objectives. 
 
 38as established by environmental legislation, the oblig ation to choose the least harmful route, and the 
necessity to undertake adequate mitigation and compen sation measures, it is expected that the above 
described limited negative impacts will be offset. 
Where the urgent need of integrating renewables a nd preventing climate change make the balancing of 
environmental and climate change objectives necess ary, this rule could set a precedent for non-PCI 
projects in the field of energy, in that Member  States could choose to extend the scope of this 
provision. However, it is expected that no preceden t is created for other sectors, as the energy sector 
faces particular urgency regarding the delivery of projects due to the 2020 objectives. 
Strong positive effects with regard to climate policy objectives  are expected – if the EU cannot meet 
its energy and climate objectives climate risks will fu rther grow and deteriorate the environment. The 
construction of electricity lines enables the large-scale deployment of renewable energies, with its positive impacts in terms of reduction of CO2 emissi ons. Whilst it is difficult to quantify impacts and 
compare effects on the local environment with th e contribution of energy infrastructure to the 
prevention of climate change, it is expected that th e overall balance of impacts is positive. In addition, 
the fight of climate change has positive effects on the preservation of biodiversity, as global warming 
could extinct certain species not adapted to higher temperatures
84. 
Regarding economic impacts,  the assurance that the necessity of a project is acknowledged and that 
projects can be built despite potential conflicts w ith Natura2000 areas will increase investors' certainty  
and positively contribute to the projects' commercial viability. Minor impacts in terms of compliance 
costs  are expected: In MSs where the necessity of a pr oject or the application of any other priority 
scheme is established by law, r esources would be needed on the au thorities' side to adapt national 
legislation, such that PCIs are accounted for in these. 
Regarding administrative costs , the reduction of resources needed  for processing a given number of 
projects is estimated at about 3% on the promoters' side, and 12% on the authorities' side. As described 
in Annex 16, this results from the fact that less resources would be needed to handle objections related 
to the necessity of the project, and that existing fast-track procedures would be applied. Additional 
savings to be expected in the context of litigati on procedures are not taken into account here, as these 
are not subject to the legislative act85. 
In terms of the  legal feasibility of this option, some adaptation of national legislation would be 
necessary in those countries where priority or fast -track regimes and/or the acknowledgement of the 
necessity of a project are established by a legisla tive act (e.g. UK). In countries where the necessity of 
a project is established by a procedure on a case-by case basis (e.g. France), this procedure could serve to define the concrete routing of a PCI. In other countries, the EU legislative act would serve as legal 
basis. It is expected that the measure related to the Habitats and Waterframework Directives would not 
require an explicit amendment, but would rather  constitute a Lex Specialis, which is not in 
contradiction with the rules established. However, th e analysis of this measure has not been entirely 
concluded to date and will be subject  to a more detailed legal analysis as part of the elaboration of the 
legislative act. 
OPTION A.2: Rules on the organisation and duration of the permit granting process 
(suboptions A.2.1b "full one-stop shop" and A.2.2.c "legally-binding time limit established by 
legislative act") 
The overall impact  of this option is expected to be strong and positive , as it would allow a large 
majority of projects needed by 2020 to be de livered on time, provided appropriate measures on 
regulation and financing are in place. The number of projects realised on time would be higher than with option A.1, under which fast-tracking with one -stop shop and time limits  would only be possible 
in those Member States where it is already established.  Analysis has shown that the existence of a one-
stop shop is positively correlated with the duration of the permit granting procedure
86 (see Annex 7). 
In countries where one-stop shops exist (EL, IE , IT, NL, UK), the entire permit granting process 
                                                 
84  Some species adapted to higher temperat ures could however be positively affected. 
85  See Annex 17 for more detail s on methodology and assumptions. 
86  Note that one-stop shops identified have different de grees of decision-making power. 
 
 39including pre-application efforts has an average duration of 4-5 years87. Legally-binding time limits 
will reinforce the positive impact of the one-stop shop measure on durations, as they are crucial to 
incentivise promoters and authorities to complete th e permit granting process in a timely fashion, and 
for sanction mechanisms to be taken at EU level if considered appropriate and justified. Regarding the 
two-step approach (2-3 years fo r pre-application efforts and 1 year for the statutory permitting 
procedure, experience in MS where one-stop shop con cepts and time limits have been introduced has 
proven that this two-step approach is effective and feasible, and leaves ample time for promoters to 
complete assessments (for more details on the e ffectiveness of the one-stop shop and time limits, see 
Annex 16), which was also confirmed by a study carried out in the context of this Impact Assessment.
88 
In Member States where the current time frames ar e significantly longer than the four years proposed, 
it is expected that the measures foreseen under th is policy option reduce the duration of the process, 
whilst legal requirements, particularly with rega rd to public consulta tions and environmental 
assessments, can continue to be respected. In essence, the time li mit would incentivise authorities as 
well as project promoters to work against a given time line, which generally has positive effects on the 
delivery of projects.  
The time limit can however not be considered as a stand-alone measure, but has to be assessed in 
combination with the full one-stop shop, which wo uld hold the final responsibility of implementing a 
permit granting schedule, controlling the process and identifying intermediary milestones, and whose 
introduction would reduce the friction losses and delays  occurring when a number of parties handles a 
project in an uncoordinated manner. Complementar y measures regarding mandatory scoping activities 
(the identification of issues to be covered in th e application) would further make it possible for 
promoters to have certainty regarding the issues to be assessed, including environmental impacts. 
However, the time limit would force the relevant parties to limit the content of assessments to the 
necessary issues, based on rea listic scenarios, without demanding assessments for improbable 
consequences as it is in some cases reported practice. Public co nsultations will under the proposed 
measures continue to be held according to national rules, but where opposition due to NIMBY 
phenomena delays projects outside the framework of formal public consultations and where 
responsible authorities avoid decisions due to e.g. upcoming elections, the time limits, together with 
the full one-stop shop and appropriate sanctions, w ould accelerate decision-taking. It should be noted 
that decisions can be either positiv e or negative. Concerns that, unde r the coordinated approach, local 
authorities defer their decision to the national level have proven to be not valid, as the local authorities 
try to keep the decisions at their level to retain the maximum influence possible, as has been shown in 
the Netherlands. 
The measures foreseen would only be binding for elect ricity and gas projects, but could however have 
positive spill-over effects, as Member States could choose to apply these to other infrastructure projects. Particularly in the field of renewables ener gy integration, this coul d have even more positive 
implications for the delivery of the 2020 objectives. 
However, it is expected that not all projects woul d be completed on time despite these measures. Some 
PCIs would not get the fast-track/priority treatment , while others would be stopped in cases where a 
public authority does not grant the status of overri ding interest when it comes to the crossing of 
Natura2000 areas, or if long debates on necessity prevent the project before the start of the statutory process. 
Concerning social and governance impacts , this option would significantly improve conditions for 
citizens to participate in the decision-making process  regarding the routing of a PCI. The time limit 
introduced by the legislative act to be binding on the project promoters would not jeopardise 
                                                 
87  In the Netherlands for instance, the one-stop shop as main  feature of the new permit granting regime has resulted in 
the reduction of the entire process from an average of 10- 15 years to 6 years (including realisation of about 2 
years), whereas in some other countries where only loose or no coordination mechanisms exist, the completion of 
procedures can take significantly longe r. Acknowledging the difficulties rela ted to a fragmented permit granting 
process, Germany has just adopted a law (NABEG) to shift permit granting competence fro m state to federal level. 
88  Roland Berger study on permitting (2011). 
 
 40democratic principles and touch upon existing rights, as statutory public consultations have an average 
duration of between 4 and 8 weeks and project promoters will have to respect them.. These time 
frames can be well-integrated in the time frames fo reseen under the legislative act, as has been proved 
in several Member States. The measures foreseen woul d rather be beneficial to citizens, as the Leading 
Authority and/or promoters would be responsible  to give clear indications about intervention 
possibilities for citizens (e.g. manual of procedur e, project website) and elaborate consultation 
concepts at the start of the permit granting process.  Further, an early (informal) public consultation 
would be required also in Member States where such  consultations are not already carried out, thereby 
enabling citizens to raise their concerns at an early  stage of the process. Hence, the implementation of 
time limits would not prevent citizens from actively participating in the procedure, but instead, by 
"frontloading" the process through early information and consultation, give th em more opportunity to 
participate when decisions about altern ative routes can still be influenced.  
Some authorities might face effects on their aut onomy in areas for which they are competent89. This 
would be the case if a Member State chooses to impl ement an integrated approach (Alternative 1), as 
all authorities other than the Leading Authority wo uld lose their responsibility of issuing a legally-
binding permit. Yet, they would still give their opini on to the Leading Authority, which would have to 
take it into account to prevent litigation procedures. 
But Member States could also implement a coordinated approach (Alternative 2), where authorities 
may retain their responsibilities and continue to issue their permits. In this case, only Leading 
Authorities at federal level would be affected in  their autonomy, as well as authorities which are 
responsible to issue consolidated permits for a particular area of expertise. The Leading Authority 
would take over coordination tasks, but the respons ible authorities could continue to issue technical 
permits. Other authorities involved in the procedure would only be affected if the Leading Authority 
had to step in because of unjustified time overruns. Evidence is only available to a limited extent, as, 
according to the analysis carried out, this approach  has only been implemented in the Netherlands. 
Table 4 gives an overview of the type of authoriti es typically involved in the permit granting process 
across Member States and the consequences of the ne w regime (under both alternatives) in terms of 
decision-making power for each of them.  
Type of authority / 
Alternatives Alternative 1: integrated 
approach  (only leading 
authority issues permit) Alternative 2: coordinated 
approach  (individual 
authorities issue respective 
permits) 
Leading Authority  at national 
level - full national one-stop 
shop (e.g. NL, UK, IE, IT, EL, 
DE (taking into account new 
legislation (NABEG)) No impact No impact 
Leading Authorities at federal 
state level  (AU, partially BE) No competence under new 
regime No competence under new 
regime 
Authorities responsible to issue 
a consolidated permit for a 
particular area of expertise 
(Responsible Authorities ) (e.g. 
FR, HU) Input in form of opinion to the 
permit granting procedure, no consolidated permit Input in form of technical 
permit possible, main coordination and consolidation tasks to be taken over by Leading Authority  
Other technical, environmental, 
regional and local authorities 
giving input to the permit 
granting process or issuing 
individual permits ( Other Input in form of opinion to the 
permit granting procedure, no individual permit No impact 
                                                 
89  The particular authorities involved vary across Member States. They generally include national ministries 
responsible for energy and for environm ent, regional technical a nd environmental authoritie s, municipalities and 
other local authorities, etc. 
 
 41authorities involved ) (all MS) 
Table 4: Consequences of new permit gr anting regime on authorities involved 
 
Environmental impacts  are not expected to considerably differ from the impacts described under 
policy option A.1. They would be slightly stronger  from the perspective of impacts on local flora and 
fauna as well as on climate change, as more projects are expected to be completed under this policy 
option. 
Concerns that environmental impact assessments are not adequately carried out  and reviewed due to 
the introduction of time limits are considered as not valid. The time frame envisaged would well 
accommodate the time needed for the EIA procedure (a  study estimated the average time needed from 
notification to decision as 1 year)90 and further assessments required according to other environmental 
legislative acts, as proved in Member States wher e streamlined procedures have been introduced. 
Regardless whether an integrated or coordinated approach is chosen by the respective Member State, it would not be compulsory to harmonise envi ronmental assessment procedures. Autonomous 
assessments may continue to be carried out, as indi vidual permits or opinions could continue to be 
given by the authorities responsible for their particular field of competence.  
With regard to economic impacts , compliance costs would be higher
 than under option A.1. MSs 
would have to adapt national legislation to acco mmodate (re)assignment of coordination and decision-
making powers, and would have to set up the necessary administrative structures and to transfer staff from authorities previously responsible and/or recr uit additional staff. As only a limited number of 
PCIs will be subject to the measures envisaged  (about five per Member State), the number of 
additional staff needed is not expected to be sign ificantly high. Under the coordinated approach, it is 
expected that one person can process two projects, such that about 2.5 FTE would be needed. Thus, 
compliance costs are considered to be limited under the assumption that Member States choose the 
coordinated approach under this policy option, wher e authorities retain most of their responsibilities, 
and that an existing authority will be designated as Leading Authority, such that no entirely new 
structures will have to be created.
91 Promoters will have to familiarise themselves with the new 
regime.  
Positive impacts on administrative costs are also expected to be more significant  under this policy 
option. As shown in Annex 18, it is estimated that under the new regime, 25% of administrative costs 
can be saved per project on the promoters' side, with a reduction from EUR 114.5 million in the time 
frame 2014-2020 to EUR 85.9 m, assuming a total of 150 electricity projects to be authorised. On the 
authorities' side, 34% of administrative costs c ould be saved, with a reduction from EUR 22.6 m under 
BAU to EUR 15 m. This accumulates to total savings of 26% of administrative costs  from EUR 
137.1 m to EUR 100 m for both authorities and promoters in the period 2014-2020.92 
It should at this point be noted that the reducti on of administrative costs and the alleviation of 
administrative burden on promoters is not the main objective of the legislative act  subject to this 
impact assessment as it would constitute only a mi nor part of the overall construction costs. This 
proposal rather aims at ensuring the realisa tion of the infrastructure investments on time. 
In terms of  legal feasibility, the need to adapt national legisl ation depends on the one-stop shop 
approach selected by a Member State, being more ex tensive for the integrative approach than for the 
coordinated approach. Feasibility of this suboption has been proved in those Member States where full 
one-stops with different forms of decision-ma king power have been established. Respect of 
                                                 
90  GHK, "Collection of information and data to support the IA study of the review of the EIA Directive", 2009. Note 
that notification in this context means application for screening. 
91  Austria with planning and permit granting competence at federal state level would be, according to the analysis 
conducted, an exception, such that a new author ity would be responsible at national level.  
92  Results are based on the relatively conservative assump tion that two authorities ar e responsible for the permit 
granting process under BAU, which are coordinating othe r technical, regional and/ or local authorities and 
stakeholders involved. However, this is only one type of permit granting regime ex isting in the different MS. 
Impacts would be greater if there were, as it is in ma ny MS the case, more respons ible authorities, or if the 
responsible authority was not or only pa rtially coordinating other authorities a nd stakeholders involved. In the latter 
case, a shift of administrative costs (not more than 2%) from promoter to authority is expected. 
 
 42requirements in place is inherent to the permit granting process as authorities have to ensure that 
permits can withstand administrative or judicial re views. Regarding time limits, adaptation of national 
legislation is expected to be necessary in Memb er States where national rules foresee different time 
limits, but these adaptations are expected to be of limited extent. However, according to the analysis 
carried out, the time limits established by some of the Member States for the entire statutory permit granting procedure, which are generally shorter than one year, or for individual steps of the process 
can be well accommodated within the time limit, su ch that there would be no need for adaptation of 
national procedural law. Member States would not be prevented from setting more ambitious 
deadlines than the ones fo reseen by the legislative act. The time limit established by the EU would 
only define the point in time when EU sanction mechanisms apply, but leave Member States the 
flexibility to set and enforce time limits according to their national practice (for more explanations see 
Annex 16). In conclusion and as stated in Chapter 8, it is considered that the measures foreseen are in 
line with the principle of proportionality, as the need  to adapt national legislation is limited compared 
to the positive impacts described above, and as this  policy option would set conditions for a general 
permit granting framework, within which Member St ates will be able to carry out their procedures 
according to national specificities. 
. 
OPTION A.3 Establishment of a regime of common European interest and rules on the 
organisation and duration of the permit granting process 
The overall impact  of this policy option, which combines the impacts of options A.1 and A.2, is 
considered to be the most positive of all options,  as it would lead to the on-time completion of almost 
all the needed projects by 2020, provided appropria te measures on regulation and financing are in 
place. It would make compulsory in all Member States those measures, which are crucial for the 
facilitation and acceleration of permit granting pro cedures, not only those where fast-track regimes 
and one-stop shop approaches have been implemented, and prevent projects from being stopped due to 
issues related to the necessity or public overriding interest of the project. Environmental impacts , 
social impacts  on employment and economic impacts  on GDP are expected to be stronger under this 
policy option as all projects would be completed. Regarding compliance and administrative costs, 
effects would accumulate, with a reduction of admini strative costs of 28% on the promoters' side, and 
46% at the authorities' side, equalling a reduction of 31% in total from EUR 137.1 m under BAU to 
EUR 95 m. 
Table 5 illustrates the compatibility of the main m easures envisaged with a typical permit granting 
process, particularly with regard to EU environm ental requirements. The only deviation from existing 
practice would consist in the automatic allocation of the status of "public overriding interest" to the 
least harmful route of a PCI, in that the environm ental authorities' discretion to allocate such status 
would be removed. 
 
 43
 
Table 5: Compatibility of measures under Policy Option  A.3 with existing permit granting practice and 
EU environmental legislation 
 
Resulting from this analysis, policy option A.3 is the preferred option , combining the measures 
necessary to achieve the 2020 target. 
9.2. Regulation 
OPTION B.1: Cost allocation 
Suboption B.1.b:  Ex ante  cost allocation mechanism 
The economic impact  of such a measure would be significant, as it would make possible certain 
investments, for which no viable cost sharing would be possible under BAU. It would do so by changing the way, in which costs for cross-border i nvestments are allocated. Costs would have to be 
allocated as a function of the expected benefits. In  theory, this mechanism could potentially support up 
to 150 projects in electricity and up to 50 projects in gas
93. It can however be expected that an 
effective cost allocation solution will be only fo und for a certain number of projects, leaving a 
significant volume of projects with too co mplex or uncertain benefits unsolved. 
It is difficult to assess precisely the distributional or social impacts  of this option, i.e. how the new 
mechanism would affect various market participan ts, but some of them will pay less than under the 
                                                 
93  This estimation is based on the assumption that in el ectricity, there would be about 100-120 cross-border projects 
between now and 2020 (the 2010 TYNDP contains 76) and an expected maximum of 30 internal line projects with 
significant cross-border impa ct. In gas, there would be about 30 in terconnections (without  final investment 
decision), a limited number of reverse fl ow projects and very few LNG and stor age projects with significant cross-
border impact. Note that these numbers could be signi ficantly smaller in the case of project clustering. 
 
 44current cost sharing scheme, while others will pay more. As a general rule, one can expect that TSOs 
from Member States with large amounts of new va riable generation capacities and large consumption 
needs, notably from electricity imports, are likely to  contribute more than before, as these will be the 
main beneficiaries from cross-border infrastructure development. Those building grids for the needs 
generated in other Member States are likely to co ntribute less. In any case, such cost allocation is 
likely to deliver a more equitable burden shari ng among Member States. It should be noted that 
Member States would be free to compensate for the distributional or social impacts created on their 
territory, subject to compliance with existing EU legislation in this field. 
This option would have a large positive environmental impact  by delivering projects that are crucial 
for reaching the 20% share of renewables in 2020.  Given the higher number of projects delivered, 
limited negative impacts, both temporary and perman ent, can be expected from this measure on the 
immediate environment and neighbourhood of projects. 
Ex ante  cost allocation will have limited administrative impacts . NRAs will be required to get 
involved in the regulation of projects not situated on their territory and to cooperate more in groups 
with several other NRAs and TSOs from several diff erent Member States. This could create additional 
needs for human and technical resources. Given its  role in assisting NRAs and providing compromise 
solutions for cost allocation if necessary, it is es timated that ACER would have additional resource 
needs equivalent to about 1 full time position for ev ery 15 cost allocation cases. Such additional costs 
would have to be covered under the budget allocated to energy infrastructures. 
Concerning the feasibility  of such a measure, implementing an ex ante cost allocation mechanism 
would require legislative action at EU level to establish the principle, according to which national 
tariffs might cover costs incurred outside of the terr itory of the concerned Member State. It is not 
expected that it would require any national tran sposition in Member States, but it might require 
regulatory adaptations in the way, in which NRAs approve investment costs. The establishment of a 
clear cost allocation principle and a procedure w ould ensure the framework for cross-border cost 
allocation negotiations which are done today on a case-by-case agreement with high potential for 
difficulties or resistance from national TSOs and NRAs  to agree on a common cost allocation solution. 
The overall effectiveness of this measure is cons idered to be positive, but insufficient to fully 
address the investment challenge.  
Even assuming a smooth functioning of this new mechanism, ex ante  allocation will prove impossible 
for certain projects, leaving a limited number of very complex projects without funding solution. Cost allocation would also not address the problem of insufficient market demand for security of supply 
projects, notably in gas. 
Suboption B.1.c:
 Ex ante  cost allocation mechanism with ex post  adjustment possibility 
The impacts of this suboption would be largely identical to the ones of the previous one. The ex ante  
cost allocation mechanism with ex post  adjustment would however have slightly different  economic 
and distributional impacts , as it would allow for changes in the allocation of costs over a given 
period of operation of the considered infrastructur e. This would notably allow to take into account 
significant changes compared to initial assumptions on generation and load (e.g. if new capacities are 
added or existing ones withdrawn) or existing tran smission capacities (e.g. if a new infrastructure is 
built in the immediate neighbourhood). 
While such a possibility would increase the precision of  the allocation mechanism, it would also create 
financial uncertainty for TSOs and external invest ors and lenders who will ha ve to take on a downside 
revenue risk. While such a risk is considered to be acceptable for larger TSOs who fund their projects 
on a corporate finance basis, it could be unacceptably high for smaller TSOs and for projects funded a 
non recourse project finance basis. Such risks woul d in any case have to be covered by a dedicated 
mechanism. 
Implementation of this suboption could also trigger additional administrative costs , as TSOs and 
NRAs could have to re-evaluate be nefits and renegotiate cost alloca tion. . This sub-option may deter 
 
 45in particular other investors, such as third parties, as they may risk the guarantee for cost recovery if 
ex-post adjustments will take place. 
Because of these shortcomings,  suboption B.1.b is the preferred suboption. 
OPTION B.2: Investment incentives 
Suboption B.2.a:  Risk-related incentives for PCIs 
Incentives for PCIs with higher risks would link hi gher return to higher risks, thereby creating a 
positive economic impact  for infrastructure delivery in line with  general regulatory principles, while 
recognising the challenges posed by certain investment s. It is expected that PCIs without these higher 
risks would be implemented would be implemented regardless of the existen ce of such a scheme and 
would therefore not be affected. Tailoring incentives for a limited number of projects would reduce the 
risk of general overinvestment that TSOs would ha ve, in case incentives were offered for all PCIs. 
The financial impact  of such an adder on network tariffs woul d remain very limited, given that the 
expected volume of eligible inv estments is low. Assuming new a nnual investments of EUR 10 bn (an 
amount likely to be much larger than the value of new high-risk PCIs every year) and 30% of equity 
financing for these assets, Roland Berger has calcula ted that a premium of 2 percentage points would 
result in an EUR 60 m cost on an annual basis, or ab out 0.3% of overall transmission costs in Europe, 
which account for about 5-10% of final electricity  and wholesale gas prices only (see Annex 18). The 
real impact would therefore most certainly be much smaller than EUR 60 m. 
As these incentives will mainly benefit offshor e grid development and innovative onshore long-
distance transmission projects (because of the specific risks related to them), they would also provide 
significant positive environmental impacts  in the medium to long term, as such infrastructure would 
enable deep GHG emission reductions and a much higher share of renewable energy. 
Once established, the administrative impact for such measures would be limited, given the small 
number of eligible projects, especially if covered by national tariffs. If paid for by a dedicated fund 
filled with contributions from nationa l tariffs or congestion rents in electricity, an entity at EU level 
would have to be tasked with collec ting and managing these funds (e.g. ACER). 
In terms of feasibility , this suboption would need EU legislative action establishing the precise 
conditions triggering the obligation for NRAs to o ffer such incentives and rules for the recovery of 
corresponding costs. In the case of equity adders , national regulators could have to adapt their 
investment remuneration rules to prevent any cumula tive effects with mark-ups existing under national 
regulation. This could require additional measur es, including the modification of national adders. 
Suboption B.2.b:  Penalties and enforcement action for PCIs 
This suboption could in theory, by forcing TSOs to deliver agreed priority projects, increase social 
welfare  on European level. The economic impact for the concerned TSOs however could be negative, 
either because of reduced revenues through the penalties in case of non delivery, or because of 
additional uncovered risks taken up in case of project de livery. This in turn coul d affect the capacity of 
the TSO to deliver on other projects. 
Administrative impact  of such a measure would be limited. Enforcement of investments would 
require significant additional work from NRAs and possibly also ACER, though such cases are likely 
to be very rare, if the penalty/enforcement sch eme is designed in a sufficiently dissuasive way. 
Concerning feasibility , such measures would require conferring new powers to NRAs, which some 
Member States might resist. They would also tri gger strong opposition from TSOs. The added value of 
such a compulsory scheme comp ared to a scheme based on incen tives seems therefore limited. 
However, if a future review of these incentive inst ruments concludes that they are not sufficiently 
successful in leading to project delivery, a so lution based on penalties and enforcement could be 
studied in more detail. 
As a result, suboption B.2.a is the preferred suboption. 
OPTION B.3: Ex-ante cost allocation and risk-related incentives for PCIs 
 
 46This option would be the preferred option , as it would combine the positive impacts of both 
preferred suboptions and allow cove ring the largest number of PCIs. 
 
9.3. Financing 
OPTION C.1: Risk sharing instruments 
Concerning economic and social impacts , this option would improve access to capital, as project 
promoters would be able to use new sources of financing (e.g. bonds), financing on more adapted 
terms and risk mitigating measures (e.g. guarantees) . It would improve the commercial viability of 
projects and lead to positive investment decisions. Furthermore, the introduction of such instruments 
will contribute to the extending capital market financing (bonds) to infrastructure and create 
opportunities in the energy sector for new classes of  investors. This overall positive impact will 
however not apply to projects lacking commercial viability94. The decreased cost of financing made 
possible would also translate into a lower overall cost of PCIs, thereby having a positive impact on 
network tariffs. 
The financial impact  can only be measured once concrete PCI are identified and their individual 
characteristics are known. For PCIs with low market  demand, risk sharing instruments will not help. 
Like risk capital instruments, such a form of s upport would come at a lower expense to the public 
budget than direct grants. The  multiplying effect  of EU funds used this way could be particularly 
high: it is estimated that EUR 1 from the EU bu dget could facilitate up to EUR 25 of overall 
investment. An assumed EUR 500 m allocated to such  instruments could facilitate implementation of 
projects worth up to EUR 12.5 bn. 
Introduction of risk sharing instruments can only be  done in cooperation with financial institutions 
charged with the administration of thes e instruments. This would reduce the administrative burden  
of the Commission, but additional resources would be needed within the financial institutions for set-
up and day-to-day management. 
In terms of feasibility , this option should be relatively easy to implement, as it would not require 
particular legal acts at national level and it not expected to raise opposition from stakeholders95. 
Implementation would need to be in line with  the Commission's debt and equity platform. 
OPTION C.2: Risk capital instruments 
The economic and social impact  of such a measure would positive, as provision of equity would 
result in increasing financing capability of projects an d additional stimulus for attracting investors and 
new investor groups. By assisting projects in their early phase, it would contribute to increase and substantially accelerate the pipeline of mature projects, especially if they are more complex, innovative and involve a large number of stakeholders , thereby contributing to delivery of projects of 
European relevance. However, such instruments are unlikely to help projects lacking commercial 
viability. They would also require ring-fenced, dedicated project structures, which remain the 
exception in energy infrastructures. It seems therefor e likely that they would only be applicable to a 
small subset of the needed investments. 
As for option C1,  the financial impact  can only be measured once conc rete PCIs are identified and 
the individual characteristics of t hose projects known. For many PCIs, risk capital instruments will not 
be the adequate form of support. For suitable projects, a high leverage  of the EU budget could be 
expected with a multiplying factor between 1 and 10
96. Assuming EUR 500 m of dedicated EU 
budget, up to EUR 5 bn worth of project s could be delivered this way. 
                                                 
94  Risk sharing instruments might however help projects clos e to the point of viability: measures such as e.g. lower 
cost of financing may make these projects bankable. 
95  Some stakeholders have however argued that such in struments should be made avai lable for all infrastructure 
projects, not only projec ts of common interest. 
96  Every euro from the EU would genera te between EUR 1 and 10 of investment. The effect could be even higher in 
case of re-cycling of the budgetary re sources during the budgetary period. 
 
 47The administrative impact  (for the Commission) will be substantial if equity investments were to be 
done directly, i.e. without an intermediary financ ial institution. In line with the equity platform 
proposal that the Commission is currently prepari ng, indirect investments (i.e. outsourced to a 
financial institution) are the more likely solution. This will create substantial resource needs within 
these financial institutions, equivalent to sev eral full-time positions. Providing seed capital and 
accelerating project development would also require  additional Commission resources, especially for 
bigger and more complex projects. 
In terms of feasibility , implementing this option should not pose particular difficulties, as the 
Commission has previously implemen ted similar risk capital instruments both directly and indirectly 
(Marguerite Fund, Galaxy Fund). No substantia l opposition from stakeholders is expected. The 
implementation would need to remain in line with  and draw on the preparatory work done for the 
Commission's equity platform. 
OPTION C.3: Grant support to project construction 
The main economic and social impact  of option would be its very po sitive contribution to delivering 
PCIs otherwise not developed by market forces alone as described in section 3.2.1. This would 
particularly apply to the project categories with hi gh positive externalities but at risk as summarised in 
Annex 12. The economic impact would be particularly high as the grant intervention would only target 
the most relevant projects of European relevance, which, if not realised, would seriously hamper the 
achievement of the 2020 energy and climate policy objec tives. Grants will also in particular help those 
MSs, which contribute most to building PCIs, while  not necessarily benefiting most from them. As EU 
grants are normally excluded from the project value reflected in the Regulated Asset Base (RAB), they 
will contribute to keeping network tariffs lower th an if costs were fully included in the RAB. 
The financial impact  will depend on the amount of projects see king such support, but our analysis 
suggests that demand for funds will exceed the amounts th at can realistically be made available. It will 
also depend on the co-financing rate applied to i ndividual PCIs. The underlying principle would be to 
keep the rate of support at the absolute minimum ne eded to trigger investment in a PCI. Nevertheless, 
for some security of supply projects, up to 80%  of support compared to eligible costs may be 
necessary, compared to only about 10% in the lowest cases, thereby reducing the leverage effect of EU 
funds. Assuming about EUR 8 bn of dedicated EU budget and an average co-financing rate of 30%, 
grants deliver about EUR 24 bn worth of projects. In addition, grant support would ensure implementation of projects having previously be nefited from co-financing for studies, thereby 
delivering greater overall effectiveness of EU funds
97. 
The administrative impact  for the Commission will be directly correlated with the number of project 
and the budget available to support them. Su ch a grant programme would imply centralised 
management (potentially with the support of an  executive agency) and hence require significant 
additional resources98. 
Finally, this option, as all previous financing options, would have a significant positive 
environmental impact  by delivering projects that are crucial for reaching the 20% share of 
renewables in 2020 and preparing the infrastruct ure for the longer term EU energy and climate 
objectives including decarbonisation of energy supply, which could otherwise suffer from the 
environmental externality problem described above. 
In terms of feasibility , implementation of this option should not  pose problems. It directly builds on 
the experience with the implementation of TEN-E and EEPR. The modalities for such a grant instrument are already specified in the existing fi nancial regulation and its implementing rules. Some 
limited adaptations would be nevertheless requi red in case of tendering and repayable grants. 
OPTION C.4: Combination of grants, risk sharing and risk capital instruments 
                                                 
97  Under the current TEN-E framework, many projects receiv e co-financing for their studies, but are never realised 
afterwards, thereby creating substantial sunk costs. 
98  For the management of the 44 projects selected unde r the EEPR, the Commission needs an average of 5 full-time 
equivalents over a period of 7 years. 
 
 48As this option combines options C1, C2 and C3, its impacts derive from the combination of the 
impacts of the individual options . But providing a toolbox of market-based instruments (C1 and C2) 
and direct financial support (C3) will also lead to synergies and  efficiency gains, as it will be 
possible to flexibly provide th e most cost-effective solution for specific project risks and features. 
The implementation of some projects will be sufficientl y stimulated by risk sharing and/or risk capital 
instruments, whereas for a limited number of PCIs , grants will be only solution. Consequently the 
economic, social and environmental impact would be highest , as all investments could be 
supported as necessary in view of implementing the de fined infrastructure priorities by 2020, provided 
the overall amount of about EUR 9.1 bn av ailable EU budget is confirmed. The financial impact  of 
this toolbox could be optimised on a project-by-project basis99. 
In terms of administrative impact , the combination of various fo rms of EU level support would 
inevitably require additional resources within the Commission and for financial institutions. 
Nevertheless, economies of scale between the diffe rent instruments could be achieved through 
efficient coordination, thereby keeping the burden be low the burden level reached if each option were 
implemented separately. Finally, this option, desp ite being the most comprehensive response to the 
identified challenges, would not be more difficult to  implement than any of its individual components. 
As a result, this option is the preferred one. It reflects the proposals concerning the future EU 
budget as made by the European Commission on  29 June 2011. It fully reflects the proposed 
Connecting Europe Facility. 
10. COMPARISON OF POLICY OPTIONS  
From the analysis in the previous chapter, the following options have been identified as preferred 
options: 
• Concerning permit granting: establishment of a regime of common European interest, full one-
stop shop and time limit for projects of common interest; 
• Concerning regulation: ex ante  cost allocation and risk-specific incentives for PCIs; 
• Concerning financing: combination of grants, risk sharing and risk capital instruments. 
While the establishment of a regime of common Eur opean interest is a pre-condition for accelerating 
the premit granting process, only a full one-stop shop with a unified time limit defined for all projects 
of common interest can ensure timely delivery of the needed infrastructure investments and thereby 
also reduce administrative burden. 
Ex ante cost allocation and incentiv es targeted at the most risky pr ojects would ensure delivery of a 
significant share of projects of common interest, which have assymmetric costs and benefits across 
borders, use innovative technologies or feature other kinds of specific risks. By keeping the ex ante  
allocation process rather simple, with responsibility for finding solutions first and foremost in the 
hands of TSOs and NRAs, and by  not introducing a complicated ex post  adjustment mechanism, it 
strikes the right balance between effectiveness and efficiency. 
Finally, only the full combination of all market-based risk sharing and risk capital instruments together 
with EU grants will allow addressing in the most efficient way the individual needs of projects and 
theerefore delivering the highest number of projects of common interest, including commercially viable projects with specific risks that can be addr essed by risk sharing facilities, complex project at 
early stage that need to be triggered by seed  funding, and commercially non viable, but socio-
economically beneficial projects that necessite direct support. The provision of significant amounts of 
EU grants will be vital to guarant ee implementation of all projects at risk identified in chapter 4, as 
proposed by the European Commission in its Co mmunication on the future budget for Europe. 
From the previous analysis, it can be concluded that none of preferred measures in the different 
policy areas taken alone is capable of delivering the necessary investments, given the multiplicity 
                                                 
99  The precise allocation of the total budget amount available to risk sharing in struments, risk cap ital instruments and 
grants cannot be specified at this stag e, as it will require further analysis and be subject to the results of the 
proposed selection and evaluation process (i ncluding cost-benefit analysis) for PCIs. 
 
 49of obstacles faced. This calls for policy action combining the preferred options identified in each 
policy area. Indeed, the preferred options can only provide their full benefits in conjunction with 
the preferred options in the other two policy areas. With more efficient and transparent permit 
granting, the project pipeline ready for cost alloca tion or financing will simply not be sufficient to 
meet the 2020 target. Without appropriate regulatory me asures, there is a high risk of delays for cross-
border coordination, even if permit granting goes smoot hly. It may also imply an inefficient spending 
of EU funds, as grants could be provided to projects that might have simply required proper cost 
allocation, or seed capital involvement in project s who could have gone ahead with a regulatory 
incentive alone. Without appropriate financing instru ments at EU level including direct grants, the 
projects providing large benefits to the EU as a wh ole without being commercially viable will not be 
built, leaving also the permit granting and regulator y measures applied before without final success. 
Realising the needed investments between now and 2020 will have a significant impact on the cost of 
transmission , notably in electricity. According to ENTSO-E estimations, EUR 100 billion of new 
investment would represent on average about 1.5-2€ per MWh (0.15-0.2c€/kWh) of power 
consumption in Europe over the next 10 years or about 2% of the bulk power prices. This calculation 
does not take account of possible variations between  Member States and the cumulative effect that 
these investments will have together with the cost s for grid refurbishment necessary to replace old 
infrastructure. According to Commission estimations , total electricity infrastructure investments for 
the period 2011-2020 could amount to about one to two times the value of the TSOs' existing 
regulated asset base (RAB)100. But this average hides big variations, with certain Member States facing 
investments worth more than thr ee times their current RAB. Network tariffs could double in certain 
Member States101. Even if the share of transmission costs in overall electricity and gas prices is 
limited, the impact of this RAB increase on final prices could be significant102 and compounded by the 
expected increase of electricity prices due to th e cost of national renewa bles support schemes and 
could become politically sensitive in different Memb er States in various parts of the EU. This 
underlines the benefit expected from providing EU grants to projects with high European but insufficient commercial value. 
With the chosen package of preferred option s, the negative impacts on the environment, 
individual citizens and tariffs will be largely outweighed by the benefits expected from the completion of the trans-European networks.  This completion will allow achieving the energy and 
climate targets agreed at EU level, notably th e 20% renewables share and the 20% GHG emission 
reduction by 2020. Adequate infrastructure will also f acilitate the full integration of the internal energy 
market in electricity and gas, thereby crea ting new opportunities for system optimisation and 
efficiency, competition and choice for the final cons umer and hence exerting a overall lowering effect 
on energy prices. But it will also make our energy supplies more secure, by providing diversification 
of sources, routes and counterparts and by increasing system stability, but also by improving the the security and climate resilience of our networks. All this will contribute to the significant positive 
overall effect on GDP and employment already identi fied in the 2010 impact assessment (+0.42% of 
growth and 410,000 additional jobs compared to  the baseline scenario over the period 2011-2020). 
The preferred package of options is therefore cons idered proportional, effective and efficient with 
regard to the objectives pursued. Table 6 below su mmarises the impacts of all options and suboptions. 
Options Economic and social 
impacts Environmental 
impacts Other impacts 
A.1 Regime of Common + = Legal feasibility: - 
                                                 
100  The RAB is a valuation concept to determine the value of  assets detained by a TSO. The closing regulatory asset 
base at the end of a period is equal to the opening asse t base at the start of that period plus any new capital 
expenditure less any depreciation that occur during the regul atory period. Several TSOs have confirmed that their 
RAB is set to double over the period 2010-2020. 
101  Commission calculation. While the relationship between an increase in investments and the corresponding increase 
in tariffs is complex, depends on many factors (evolution of electricity consumption, operational expenses, losses, 
system services and other costs) and differs from Member State to Member State, it is possible to make 
approximations with regard to the tariff impact. 
102  In a Member State where network costs make up for 10% of  the total electricity bill, a 100% increase of these costs 
would increase electricity prices by 10%. 
 
 50Options Economic and social 
impacts Environmental 
impacts Other impacts 
European Interest 
A.2 full one-stop shop 
and time limit of 4 years ++ + Legal feasibility: - 
A.3 Regime of Common 
European Interest, full one-stop shop and time 
limit of 4 years +++ ++ Legal feasibility: - 
B.1 Ex-ante cost 
allocation ++ + Administrative: - 
B.2 Risk-related 
incentives for PCIs ++ + Tariff impact: - 
B.3 Ex-ante cost 
allocation and risk-related incentives for 
PCIs +++ ++ Administrative and 
tariff impact: - 
C.1 Risk-sharing 
instruments +++ +  
C.2 Risk capital instruments ++ + Administrative: - 
C.3 Grant support for 
project construction +++ ++ Administrative: - 
C.4 Combination of 
grants, risk sharing and risk capital instruments +++ ++ Administrative: - 
Tariff: + 
A3 & B3 & C4 +++ +++ Legal, administrative: - 
Tariff: + 
Table 6: Summary of impacts  (= equivalent to baseline; + to +++ impr ovement compared to baseline; - to - - - 
worsening compared to baseline) 
11. MONITORING AND EVALUATION  
In line with the measures proposed in the precedi ng IA, the following specific indicators would be 
used to monitor the evolution of the policy: 
Concerning the general implementation, by 2020, of projects of common interest necessary to 
implement the trans-European energy infrastructure pr iority corridors as defined by the February 2011 
European Council conclusions: 
• The general progress achieved for each project of  common interest selected under the defined 
priority corridors (number of projects planned,  under construction or commissioned; installed 
capacity and, if applicable, length of lines): Th is will be monitored on the basis of regular 
reports from project promoters and national regulators. 
• The interconnection level between Member Stat es and the corresponding evolution of energy 
prices: Concerning electricity, interconnector capacity defined as the ratio between import capacity and installed generation capacity in a given Member State could be used, as well price differentials observed between interna tional interconnectors. Concerning gas, price 
differentials between major European hubs coul d be used. Price monitoring is already being 
done by DG ENER’s Energy Market Observatory; 
• For electricity, the installed capacities for electricity generation from renewable sources, with 
a specific focus on offshore wind generation. Th is will be monitored through the biennial 
reports Member States must submit to the Commission under article 22 of the renewables 
directive; 
 
 51• For gas, the share of each import source in overall imports (at national, re gional and EU level) 
and the compliance with the N-1 and reverse fl ow. The latter two will be monitored under the 
Security of supply Regulation. 
a) Concerning permit granting procedures a nd public involvement and acceptance: 
• the average and maximum total duration of authorisation procedures for projects of 
common interest in electricity and gas; 
• the duration of each step of the authorisation procedure for projects of common 
interest, compared to the timing foreseen by  the initially agreed project milestones; 
• the level of opposition faced by projects of common interest (number of written 
objections during the public consultation pr ocess, number of legal recourse actions). 
The data in this section will be monitored on the basis of regular reports from project promoters 
and Member States. 
b) Concerning the regulatory treatment of projects of common interest: 
• The number of projects of common interest having reached a cost allocation 
agreement among TSOs and NRAs; 
• The average duration for reaching an cost allocation agreement; 
• The number and type of projects of common interest having received specific 
incentives and/or support by NRAs; 
The data in this section will be monitored on the basis of regular reports from project promoters 
and national regulators. 
c) Concerning market-based and direct EU financial support: 
• The total value of annual investments in el ectricity and gas transmission, storage and 
LNG/CNG, compared to total investments during the period 2007-2013; 
• The annual value of EU funds engaged comp ared to the total value of beneficiary 
projects of common interest, for each instrument and as a whole; 
• The timeliness of disbursing engaged EU funds, both for market-based instruments 
and EU grants, compared to initial project milestones and corresponding reasons. 
The Commission would ensure monitoring and evalua tion via an implementation report on a bi-annual 
basis, a mid-term evaluation in 2017 and a final evaluation. In addition, the Commission proposes to 
set up a transparency platform allowing the general public to follow the advancement of individual 
projects of common interest. 
 
 52ANNEX 1 
GLOSSARY  
 
ACER   Agency for the Cooperation of Energy Regulators 
BAU   Business As Usual BEMIP   Baltic Energy Market Interconnection Plan CCS   Carbon Capture and Storage CNG   Compressed Natural Gas EBRD   European Bank for Reconstruction and Development 
EIA   Environmental Impact Assessment 
EEPR   European Energy Plan for Recovery EIB   European Investment Bank ENTSO-E  European Network of Transmission System Operators in Electricity ENTSOG  European Network of Transmission System Operators in Gas 
ERGEG  European Regulators' Group for Electricity and Gas 
ETS   Emission Trading Scheme GDP   Gross Domestic Product GHG   Greenhouse Gas GIE   Gas Infrastructure Europe 
GW   Giga Watt 
IA   Impact Assessment ICT    Information and Communication Technology ITC   Inter-Transmission System Operator Compensation LNG   Liquefied Natural Gas MS   Member State 
NRA   National Regulatory Authority 
NSCOGI  North Sea Countries Offshore Grid Initiative PCI   Project of Common Interest RAB   Regulated Asset Base RES   Renewable Energy Sources 
TEN-E   Trans-European Networks for Energy 
TFEU   Treaty on the Functioning of the European Union 3
rd IEMP Third Internal Energy Market Package 
TPA Third Party Access TSO   Transmission System Operators TWh   Tera Watt hour 
TYNDP  Ten-Year Network Development Plan 
WACC Weighted Average Cost of Capital
 
 53 
ANNEX 2 
INPUT DOCUMENTS  
 
 
The impact assessment builds on the results of the foll owing studies, some of which have already been 
used for the 2010 impact assessme nt (marked by an asterisk): 
1. General 
− "Adaptation and Mitigation Strategies (ADAM) – Supporting European Climate Policy", project 
funded by the European Commission, final report, June 2009. http://www.adamproject.eu/   
− * Arup, "Feasibility of Europe-wide CO2 infrast ructures", study for the European Commission 
DG Energy, 2010. 
− * Boston Consulting Group "Electricity Storage:  Making Large-Scale Adoption of Wind and Solar 
Energies a Reality", study by Cornelius Piper and Holger Rubel, March 2010. 
− CEER, "European Infrastructure Package: Inv estment needs and financing mechanisms – 
Financing Task Force conclusions", Reference C11-FTF-02-01, 23 March 2011 
- * Centro Elettrotecnico Sperimentale Italiano, Instituto de Investigación Tecnológica, Mercados 
Energeticos, Ramboll, "Energy Infrastructur e 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 emphasi s on investments on renewable energy sources 
and their integration into the Trans-European energy networks, including an Inventory of the 
Technical Status of the European Energy-Network  for the Year 2003" (TEN-Energy-Invest), study 
for the European Commission DG Energy and Transport, October 2005. 
− * COWI, Cambridge Econometrics and KEMA, "The revision of the trans-European energy 
network policy (TEN-E)", impact assessment study for the European Commission DG Energy, 
October 2010. 
− * ENTSO-E, "Ten-Year Network Development Plan", 2010. https://www.entsoe.eu/index.php?id=232  
− * ENTSO-E, "System Adequacy Forecast 2010-2025", 2009. https://www.entsoe.eu/resources/ 
publications/system-development/  
− ENTSOG, "Ten-Year Network Devel opment Plan", February 2011. 
http://www.entsog.eu/publications/index_g_investment.html  
− * European Commission, Joint Research Centre (JRC), "Evolution of size and cost of a trans-
European CO2 pipeline network", 2010. 
− European Commission, "The implementation of the Trans-European Energy Networks in the 
period 2007-2009", report pursuant to Article 17 of  Regulation (EC) 680/2007 and Articles 9(2) 
and 15 of Decision 1364/2006/EC, COM(2010)203, May 2010. 
− European Commission, "Annex to Report on the implementation of the Trans-European Energy 
Networks in the period 2007-2009", Commissi on Staff Working Document, SEC(2010)505, May 
2010. 
− European Commission, "Energy infrastructure priorities for 2020 and beyond – A Blueprint for an 
integrated European energy netw ork", COM(2010)677, November 2010. 
− European Commission, "Impart assessment on Energy infrastructure priorities for 2020 and 
beyond – A Blueprint for an integrated European energy network", Commission Staff Working 
Document, SEC(2010)1396, November 2010. 
 
 54− European Commission, "Smart Grids: from innovation to deployment", COM(2011)202, April 
2011. 
− European Commission, “Energy Infrastructure In vestment needs and financing requirements”, 
Commission Staff Working Document (SEC(2011)755 final), June 2011. 
− European Commission, “2009-2010 Report on progress in creating the internal gas and electricity 
market”, Commission Staff Working Document, 2011. 
− European Commission, “DG ENER Staff Worki ng Document: Report on Progress in Creating the 
Internal Gas and Electricity Market – Technical Annex”, 2011. 
− European Parliament, "Energy Infrastructure Prior ities", Directorate-General for Internal Policies, 
Policy Department Economic and Sc ientific Policy – Industry, Research and Energy, Briefing 
Paper, March 2011. 
− * EWI, "Model-based Analysis of Infrastructure Projects and Market Integration in Europe with 
Special Focus on Security of Supply Scenarios", University of Cologne, May 2010. 
− * "EWIS – European Wind Integrati on Study", final report, March 2010. http://www.wind-
integration.eu/  
− * High-Level Advisory Group on ICT for Smart Elec tricity Distribution Networks: “ICT for a low 
carbon Economy – Smart Electricity Distributi on Networks”, supported by the European 
Commission, DG for Information Society and Media, July 2009. 
− * ILF, Purvin&Gertz, "Technical Aspects of Vari able Use of Oil Pipelines coming into the EU 
from Third Countries", study for the European Commission DG Energy, 2010. 
− * OffshoreGrid study, various presentati ons and interim reports, July 2011. 
http://www.offshoregrid.eu/  
− * Ramboll Oil and Gas, "Study on natural gas storage in the EU", October 2008. 
− * Supponen, Matti, “Influence of national and company interests on European electricity 
transmission investments”, PhD thesis for the Helsinki University of Technology, 2011. 
− US National Research Council, "Hidden Costs of  Energy: Unpriced Consequences of Energy 
Production and Use", 2010. http://www.nap.edu/openbook.php ?record_id=12794&page=R1  
− Van Ierland, E.C., K. de Bruin, R.B. Deli nk, A. Ruijs (eds.), "Routeplanner naar een 
klimaatbestendig Nederland – A qualitative assessm ent of climate adaptation options and some 
estimates of adaptation costs", Study performed wi thin the framework of the Netherlands Policy 
Programme ARK, 2007. 
− Vattenfall, "Höchstspannungs netze: Freileitungen oder Kabel? Ei ne Analyse der Vattenfall Europe 
AG mit dem Beispiel des 380-kV-Kabelprojekts  in Berlin", Vattenfall Europe, 2006. 
2. Selection process and criteria 
− Awad, M., K.E. Casey, A.S. Geevarghese, J.C. Mille r, A.F. Rahimi, A.Y. Sheffrin, M. Zhang, E. 
Toolson, G. Drayton, B.F. Hobbs, and F.A. Wolak, "Economic Assessment of Transmission 
Upgrades: Application of the California ISO Appr oach", Ch. 7, in X.-P. Zhang, Restructured 
Electric Power Systems: Analysis of Electricity Markets with Equilibrium Models, Power Engineering Series, IEEE Press, July 2010. 
− Proost, S., F. Dunkerley, S. Van der Loo, N. Adle r, J. Bröcker, A. Korzhenevych, "Do the selected 
Trans European transport investments pass the Co st Benefit test?", Center for Economic Studies – 
Discussion papers, Katholieke Universiteit Leuve n, Centrum voor Economische Studiën, February 
2010. 
− "REALISEGRID – Research, Methodologies and T echnologies for the effective development of 
pan-European key grid infrastructures to support the achievement of a reliable, competitive and 
 
 55sustainable electricity supply", project supported by the European Commission, various reports 
and final conference, February 2011. http://realisegrid.rse-web.it/default.asp : 
− D3.7.2: Improving consensus on new transmission infrastructures by a thorough 
presentation of the benefits given by priority projects, Final, 2011-03-29. 
− D3.3.1 Possible criteria to assess technical-economic and strategic benefits of specific 
transmission projects 2010-04-29. 
− D3.3.3 Tool for the assessment of benefits  given by the expansion of transmission 
infrastructures 2011-06-13. 
− D3.4.2 Tool for a coordina ted assessment of investments in electricity and gas 
infrastructures 2010-12-10. 
− Rebours, Y., M. Trotignon, V. Lavier, T. De rbanne, and F. Meslier, “How much electric 
interconnection capacities are needed within W estern Europe?”, Conference on European Energy 
Markets (EEM), June 2010. 
3. Regulation and financing 
− CEER, "Energy Infrastructure Package – Draft Po sition Paper on Cost Allocation", Reference 
C11-IBP-30-03, 25 March 2011. 
− ENTSO-E, "Overview of Transmission Tariffs in Europe: Synthesis 2010", September 2010. 
− EUI THINK project, "Transition towards a low carbon energy system by 2050: What role for the 
EU?", draft report, 18 April 2011. 
− Faruqui, Ahmad, Dan Harris, Ryan Hledik, "Unl ocking the €53 billion Savi ngs from Smart Meters 
in the EU", The Brattle Group Discussion Paper, October 2009. 
− Glachant, Jean-Michel, Haikel Kalfallah, “Iden tifying Benefits and Allocating Costs for Cross-
Border Electricity & Gas Infrastructure Project s”, European Commission and  Florence School of 
Regulation workshop conclusions, 4 May 2011 
− Helm, Dieter, "Redefining the models for privat e sector investment in infrastructure – The RAB 
Model", 9th February 2011 presentation, Slides for the UK Infrastructure Summit. 
− Helm, Dieter, and Tom Tindall, "The evolution of infrastructure and utility ownership and its 
implications, Oxford Review of Economic Polic y, Volume 25, Number 3, 2009, pp.411–434. 
− IEA, "Technology Roadmap Smart Grids", April 2011. 
− * KEMA, REKK, "Methodologies for Gas Transmission Network Tariffs and Gas Balancing Fees 
in Europe", study for the European Commi ssion DG Transport and Energy, December 2009. 
− Meeus, Leonardo; Saguan, Marcelo; Glachant, Jean-Michel; Belmans, Ronnie, "Smart Regulation 
for Smart Grids", European University Institute  (EUI), Robert Schuman Centre for Advanced 
Studies, EUI Working Paper RSCAS 2010/45 
− Pelkmans, Jacques, Lionel Kapff, “Interconnect or Investment for a Well-fuctioning Internal 
Market: What EU regime of regulatory incen tives?”, Bruges European Economic Research 
Papers, BEER n°18, 2010. 
− Rious, Vincent, Jean-Michel Glachant, Philippe D essant, "Transmission network investment as an 
anticipation problem", EUI Working Paper RSCAS 2010/04, January 2010 
− Roland Berger, "Study on the structuring and fi nancing of energy infrastructure projects, the 
financing gaps and recommendations  regarding the new TEN-E financial instrument", study for 
the European Commission DG Energy, May 2011 (2011a). 
− Observatoire Méditerranéen de l’Energie, "Rea lisegrid – D3.6.2: Incentive schemes and regulation 
framework for transmission development in Europe", final report, 29 April 2010. 
 
 56− Rothschild, presentation at the Hungarian EU Council Presidency / European Commission high-
level energy infrastructure conference, May 2011. 
− SAP, "Smart Grids for Europe: Benefits, Challenges, and Best Practices", 2011. 
− Union of the Electricity Industry (Eurelectric), Subgroup Regulation for Smart Grids – Networks 
Committee, Manuel Rodrigues Da Costa (PT) Chair, "Regulation for smart grids", 2011. 
4. Permit granting, stakeholder involvement and compensation 
− ENTSO-E, "Position Paper on permitting procedures for electricity infrastructure, 2010. 
https://www.entsoe.eu/fileadmin/user_upl oad/_library/positio n_papers/100629-ENTSO-
E_response_permitting_procedure.pdf   
− ERSE, "Realisegrid: Preliminary results on str eamlining planning and approval procedures of 
electricity transmission infrastructures", interim report, 2 July 2010. http://realisegrid.rse-
web.it/content/files/File/Publications %20and%20results/Interim%20report.pdf   
− ETSO, Overview of the administrative procedures for constructing 110 kV to 400 kV overhead 
lines, 2006. https://www.entsoe.eu/fileadmin/user_uploa d/_library/publications/etso/others/ 
procedures%20400%20kv%20lines.pdf  
− EWEA, "Wind Barriers", 2010. http://www.windbarriers.eu/index.php?id=3  
− Haas, Dieter; Schuerenberg, Bernd, "Stromt od von Vögeln, Grundlagen und Standards zum 
Vogelschutz an Freileitungen", 2003. http://www.birdsandpowerlines.org/  
− Ramboll, Mercados, "TEN-E Priority Corridors fo r Energy Transmission", study for the European 
Commission DG Energy and Transport, 2008. 
− Roland Berger, "Permitting procedures for energy in frastructure projects in the EU: evaluation and 
legal recommendations", study for the European Commission DG Energy, May 2011 (2011b). 
− UK Department for Communities and Local Gove rnment, "Localism Bill: major infrastructure 
projects, Impact assessment", 2011. http://www.communities.gov.uk/publications/ 
localgovernment/localismi mpactassessmentsum  
 
 
 57ANNEX 3 
RESULTS FROM THE PUBLIC CONSULTATION ON PERMIT GRANTING  
 
 
Executive summary 
 
Adequate, integrated and reliab le energy networks are a crucia l prerequisite for EU energy 
policy goals and for the EU's economic strategy . The European Commission has therefore, in 
its Communication "Energy infr astructure priorities for 2020 and beyond - A Blueprint for an 
integrated European energy network" put fo rward a strategy for a new European energy 
infrastructure policy. In autumn 2011, th e Commission will table a legislative proposal, 
identifying the tools necessary for the implementation of this policy. As widely acknowledged, one of the main obstacles impeding and delaying energy infrastructure 
development are long and non-transparent permit granting processes, along with a lack of 
public acceptance. Therefore, the Commission has been assessing possible solutions to ensure effective and time-efficient planning and coordi nation, good administrative practice as well as 
a more transparent and inclusive deci sion-making and communication approach. 
 In this context, as part of the process of preparing the legisl ative proposal, a public 
consultation was launched, which was open from 1 March - 30 April 2011.
103 81 replies were 
received – 13 from Member States, 57 from  the industry and related organisations, 1 
academic contribution and 10 from civil societ y, namely citizens and NGOs. Contributions 
from the industry were provided by system op erators (transmission as well as distribution), 
producers, the renewable industry and chambers  of commerce as well as other industry 
associations. This report summari ses the contributions received. 
 
Public consultation questions  and summary of replies:  
 
Question 1  Measures to facili tate the administrative procedur es: "one-stop shop", time limits, 
and rewards and incentives:  
The introduction of binding time limits and a " one-stop-shop" (of some form) were welcomed 
by an overwhelming majority of resp ondents (60 % and 79 % respectively104).  Issues raised 
were national competence, the degree of deci sion-making power of the competent authority 
and the avoidance of additional administrative structures. 30% of respondents supported the 
provision of rewards and incentives to facilita te project development while 20 % opposed this 
measure.    
Question 2 Guidelines to increase the transparency and predictability of the permit granting 
process:  
Guidelines were mostly considered useful. The th ree issues that were raised most often were a 
better communication strategy for the economic and so cial benefits of infr astructure projects, 
the full and early provision of environmental in formation and thus an earlier involvement of 
the public in infrastructure planning (e.g. pr oviding and explaining gr id expansion plans). 
Member States stressed that especially in  communicating with the public the subsidiary 
principle has to be respected. 
                                                
 
103 http://ec.europa.eu/energy/infrastructure/consu ltations/20110430_infrastructure_projects_en.htm 
104 with  approximately 20 % not expressing a clear preference 
 
 58 
 
Question 3 Improving public acceptance of  infrastructure projects:   
Overall responses indicated that the main res ponsibility for communication should be with the 
project developer, but th at local, regional, national and Euro pean authorities should facilitate 
these measures (depending on the project) and pr ovide political support . An early discussion 
of possible environmental and health risks, a better comm unication of the purpose of 
infrastructure projects by the TSOs and the in clusion of more stakeholders in the planning 
process were considered suitable measures by several respondents. 
 
 
Question 4 Compensation mechanisms to facilitate infrastructure projects: 
Roughly half of the respondent s were opposed to the harm onisation or standards for 
compensation mechanisms across the EU and believed that the competence here should 
remain within the Member States. Other respo ndents, mainly from the industry, believed that 
some form of standardisation can be helpful, es pecially with respect to  cross-border projects. 
  
Question 5 Experience with national best practices: 
Several best practices were reported that were  successfully addressing different issues, e.g. 
longer pre-application procedures, a central co ordination body within th e ministry, a national 
grid development plan or non-monetary compensation measures for affected communities.   
Detailed summary 
 
Adequate, integrated and reliab le energy networks are a crucia l prerequisite for EU energy 
policy goals and for the EU's economic strategy . The European Commission has therefore, in 
its Communication "Energy infr astructure priorities for 2020 and beyond - A Blueprint for an 
integrated European energy network" put fo rward a strategy for a new European energy 
infrastructure policy. In autumn 2011, the Comm ission will table a legislative proposal which 
will put forward the tools necessary for the implementation of this policy.  A long and uncertain permit granting process wa s indicated by many ma jor stakeholders as 
one of the main reasons for dela y of infrastructure projects. The time between the start of 
planning and final commissioning of a power lin e is frequently more than ten years, 
assumingly preventing up to 50% of commercially viable projects from  being realised by 
2020. Reasons are manifold: Non-transparent perm it granting procedures, coupled with lack 
of political support as well as the opposition of affected citizens. Cross-border projects face 
additional opposition, as they are frequently per ceived as mere "transit lines" without local 
benefits.  The Commission is therefore assessing how to improve the administrative procedures existing 
in the Member States, to ensure an efficien t upfront planning of the permits, time-efficient 
coordination and good administrativ e practice. The permit granti ng process should also be 
made more transparent for all stakeholders and the general public, and communication with 
the affected population needs to be improved.  
 
 59In this context, as part of the process of preparing the legisl ative proposal, a public 
consultation was launched, which was open from 1 March - 30 April 2011.105 The public 
consultation was based on a questionnaire of five open questions a ddressing the following 
issues: 1. measures to improve administrative procedures  ("one-stop shop", time limits, rewards 
and incentives) 
2. introduction of guidelines to increase transparency and predictability  
3. improving communication with citizens to ensure higher public acceptance 
4. requirements for compensation mechanisms at individual and community level 
5. existing best-practices  at national level to facilitat e the permit granting process. 
 81 replies were received – 13 from Member States , 57 from the industry and related 
organisations , 1 academic contribution  and 10 from civil society , namely citizens and 
NGOs . Contributions from the indust ry were provided by system operators (transmission as 
well as distribution), producers, the renewable industry and chambers of commerce as well as 
other industry associations. Th e individual contributions have  been published on the public 
consultation's webpage.
106 
 The broad spectrum of respondents offers an insight into a large range of stakeholder 
opinions.  
Question 1:  As explained above [see consultation document], a complex and non-
transparent procedural framework as we ll as poor administrative practice are 
major reasons for delays. There are different options which could help to facilitate administrative procedures. These include, as outlined in the Communication "Energy infrastructure  priorities for 2020 and beyond - A 
 Blueprint for an integrated European energy network", the establishment of a 
national contact and coordination body ("one-stop shop") per cross-border 
project, the introduction of a time limit, and the provis ion of rewards and 
incentives to regions or Member States which facilitate the permit granting process. Would you consider these me asures as useful? If so, under which 
conditions? Are there any additional measur es you would propos e to facilitate 
the administrative procedures? 
 
The proposed measures were generally welcomed as an attempt to tackle the existing 
problems and delays in administrative proced ures. Whilst agreeing wi th certain suggested 
provisions, different stakeholders  pointed out that such facilitation was necessary not only at 
European level but at national level as well. Projects of Common Interest should similarly 
enjoy the same political support in the Me mber States as national priorities.  
 
"One-stop-shop"
 
 
The idea of a central contact and coordi nation body for the permit granting procedures 
received overwhelming support (79 % of respondents supporte d the measure while only 2 
respondents (~ 2.5%) opposed it).  The advantages of a sing le entry point for permit 
applications were pointed out across all differe nt stakeholders. This would limit the number of 
required permissions significantly and enable a coordinated publication of environmental and 
                                                 
105 http://ec.europa.eu/energy/infrastructure/consu ltations/20110430_infrastructure_projects_en.htm 
106 http://ec.europa.eu/energy/infrastructure/consu ltations/20110430_infrastructure_projects_en.htm 
 
 60other information. The communication with th e public would become smoother, which can 
benefit the acceptance of infrastr ucture projects among the population. 
 It was pointed out that projects at national level should clearly remain national competence 
and in this context half of the Member Stat es opposed a standardisat ion of procedures as 
different approaches already exist in a numbe r of countries. EU-coordi nation for cross-border 
projects exclusively received support.   Another question that was often addressed wa s the competence of the proposed "one-stop-
shops". Here the preferences were almost equa lly split between a pure c oordination centre and 
a body with significant decision- making power with industry re sponses slightly favouring 
more centralised decision-making power. Many  proponents made clear though that either 
measure should not create additiona l administrative structures.  
 
Time limits
 
 
Time limits were supported by a majority of respondents, with 60 % being in favour and 10 % 
opposing the idea. Particularly NGOs warned of  the risks of introducing inappropriate time 
limits.  Several supporters of time limits sugge sted maximum limits for each individual step 
of the application procedure or at least benchm arks to make the process more transparent.  
 A central issue that was also raised were the consequences if a deadline was not met by the authorities. Automatic acceptances could d ecrease public acceptance significantly, while 
automatic rejections shift the consequences ba ck to the project developer. Other examples 
have a higher decision-making authority reviewing the files in case of a bureaucratic delay.  
 Some critics state that simply introducing time limits, though possibly beneficial, will not 
erase the root causes of  slow administrative processing. It has to be ensured that the 
authorities' staff capacities are sufficient to  guarantee smooth permit granting process. 
 Arguing along those lines, many of the opposi ng respondents called for appropriate time 
frames to guarantee a thorough and correct pe rmit granting process and enough time for an 
adequate consultation process. Some Member St ates saw general maximum time limits as an 
obstacle when dealing with more complicated projects (e.g. new technologies). A diligent 
examination of the environmental impacts was also considered to be beneficial.  
Rewards and incentives 
 
 
Rewards and incentives as a means to encour age smoother administrative processes faced 
more opposition, particularly from Member St ates and NGOs. In contrast most industry 
responses expressed a positive attitude toward the measure.  The reasons for opposition stemmed mainly from 3 reasons:  
− Stakeholders see a problem in defining obj ective criteria to assess the permitting 
agency's work. In this light rewards a nd incentives might be perceived as buying 
consent and be detrimental to public acceptance. 
− The introduction of rewards and incentives  cannot replace a diligent consultation and 
permit granting process and hence does not cont ribute to alleviating the root causes of 
administrative delays. 
− Some responses queried the source of funding for this measure. 
 
 61 
Instead of financially incentivising smoot h processing respondents emphasized that 
administrative capacities of the authorities involved should be st rengthened and best practices 
and benchmarks should be encouraged.   
Additional issues
 
 
The already existing European  coordinators for cross-bor der projects were mentioned 
positively. In this context, maintaining the possibi lity to resort to coor dinators as political 
support for crucial cross-border connections was suggested by several stakeholders. 
 A discrepancy was noted between the existing European environmental, urban planning and 
industrial hazards laws and th e objective to develop a European energy infrastructure. 
Therefore some Member States and individual industry responses called for a joint effort of 
the different Directorates-General to prom ote and facilitate the framework for energy 
infrastructure development. It was pointed out that a better c oordination and clear priorities 
among the different objectives could shorten the permit granting pr ocess significantly. 
  
Question 2:  To increase the transparen cy and predictability of the permit granting process 
for all parties involved, guidelines targ eted at ministries, local and regional 
authorities, project developers and affe cted citizens could be developed. 
 Would you consider them useful? Which issues should they address? 
 
The introduction of guidelines to foster transparency and predicta bility was considered useful 
by a clear majority of respondent s, especially among Member St ates and stakeholders from 
civil society. Several Member States stressed that the subsidiary principle has to be respected, particularly when comm unicating with the public. 
 Many respondents emphasised that the wider econom ic and social benefits of infrastructure 
projects need to be better communicated. The si gnificance of transmission lines in general and 
each specific project has to be highlighted in order to increase public acceptance and achieve 
better compromises. Environmental organisa tions highlighted that the purpose of the 
connection (e.g. integration of renewable ener gy sources) should be communicated to the 
wider public. The specific benefits of a connect ion (e.g. decarbonisation, security of supply) 
could also have favourable or in other cases negative effects on the public opinion.  
 The full and early provision of environmental a nd technical information was also considered 
an important measure to facilitate public accep tance. In this respect a minimum standard of 
communication – regarding the amount and the timing during the process – was suggested by 
several stakeholders. This appro ach enables earlier involvement of the different stakeholders 
in the process, which was widely favoured by respondents. Reconciling a more transparent 
process (with possibly more stakeholder involv ement) with the need to speed up existing 
procedures was named as a major challenge for these measures.  To guarantee more transparency regarding network development, the requirement for a 
national development plan or a network strate gy was proposed. Plans similar to ENTSO-E's 
TYNDP would make further netw ork expansions more predictable and comprehensible. The 
UK's National Policy Statements (NPS) set a clear strategy for furthe r network development 
 
 62and also explain the evaluation process of applic ations in more detail. Laying open all steps of 
the process and the evaluation criteria can foster  trust in the permit gr anting process and thus 
support in projects.  Procedural reliability was valued  as very important for all st akeholders. A clear prescription 
of responsibilities and tasks for each stakeholder at the different moments of the process was 
suggested in this respect. For cross-border projects a solid method for cost-allocation was 
called for, as well as a harmonisation of pro cedures to enable these projects further. 
 
 
 Question 3:  The lack of public accept ance poses a major hindran ce for the implementation 
of energy infrastructure projects, and the associated achievement of energy 
and climate policy objectives. What s hould be done, apart from efforts to 
increase general transparency, to im prove communication with citizens at an 
early stage of the project and to ensure that the environmental, security of 
supply, social and economic costs and be nefits of a project are correctly 
understood? Who should be responsible fo r /involved in this communication? 
  
Next to a more transparent process (covered in question 2) respondents addressed 3 main 
areas:  A more proactive information policy regard ing energy infrastructure development, 
particularly from the TSOs' side: A further expl anation of their activit ies and the purpose of 
new projects were deemed highly important. The different stakeholders agreed that creating 
awareness for the necessity of grid expansion is  going to be a key factor. The projects have to 
be better linked to the wider be nefits, a sustainable energy futu re – connecting grid expansion 
to security of supply, the integr ation of the internal market and efforts to tackle climate 
change.  In this regard responde nts were in favour of a more inte grative planning procedure, also 
encompassing NGOs, academia and other stake holders. Some environmental NGOs pointed 
out that in light of a coherent  strategy they were willing to support grid extension measures 
and their promotion, which could prove crucia l for public acceptance. Furthermore it was 
suggested that independent research institu tes could play a role, examining the actual 
environmental and health risks of power lin es and informing the public. Recognising and 
addressing the population's concerns seriously was also named as a measure to foster trust and 
a higher acceptance in the long run.  Respondents were very clear th at the main respons ibility of communica tion should be with 
the project developer but many stakeholders also  advocated more direct political support for 
grid expansion to further stress the necessity of the measure. This was particularly mentioned 
for the European level, but also local and regional support for individual projects was 
considered helpful and relevant.   
Question 4: Requirements for compensation mechanism s: In your opinion, could minimum 
  or harmonised requirements on compen sation of affected populations, targeted 
  at individual or community level, he lp to increase public acceptance? Which 
 
 63  compensation schemes would you deem useful, and who should provide for the 
  compensation?  
 
Compensation mechanisms were broadly seen as he lpful or necessary, if fair and transparent. 
Industry responses stressed th at the additional costs connect ed to compensation measures 
were to be included in higher tariffs and hen ce carried by the consumer. A question that arose 
is an acceptable method to calculate compensati on for intangible negative effects (e.g. visual 
impediment).  
Respondents believed that compensation shou ld be exclusively a national decision and 
opposed any standardization du e to diverging circumstances (e.g. land prices, public 
involvement, specific projects) in the Member States. This rejection was the clearest among 
Member States. It was also mentioned seve ral times that compensation measures should 
remain exceptions and thus dealt with case by case in cooperation with local authorities. 
Individual industry responses on the other hand were favourable toward some form of 
minimum standards and guidelines.  Compensation targeted at individuals and co mmunities were seen differently. Individual 
compensation measures for landowners were per ceived as unavoidable in  order to have the 
right to use one's property. If community comp ensation proved to be beneficial to public 
acceptance, it was seen as a fair and good appr oach to reimburse communities for negative 
impacts. A majority of respondents preferre d a case by case approa ch – with local and 
regional authorities playing a major role in agreements  – and were opposed to any 
automatism. Concerns of not creating some sort of business were also expressed.  The issue of adequate compensation for environmental impact, though addressed by 
environmental directives, was raised by several respondents.  
 
 
Question 5:   Have you encountered any national be st-practices which have helped to 
facilitate the permit granting process? Wh ich measures were taken in view of 
administrative procedures, transparency and communication with  citizens, and 
how has the public responded? 
 
A wide array of examples was na med, pointing to approaches in different Member States that 
proved to be successful in alleviating ch allenges in the administrative procedures, 
transparency and communication. These ex amples included national "one-stop-shop" 
approaches as well as a tran sparent central planning strate gy. They underlined beneficial 
results of introducing time-limits and othe r streamlining measures (e.g. a thorough pre-
application process). Furthermore they also  pointed to successf ul efforts to better 
communicate benefits to the public  and better integrate their con cerns via a transparent public 
debate. Examples showed that certain m easures can improve public acceptance of 
infrastructure development. These best practi ces will be studied and taken into account.  
 Not completely accounting for every measure mentioned, a few of the submitted examples are briefly presented in the following:   
- In the Netherlands the RCR ("Programma Rijkscoordinatieregeli ng") makes the Dutch 
Ministry of Economic Affairs, Agricultur e and Innovation the central coordination 
 
 64body for projects of national interest. Permits  are still granted by local and regional 
authorities but the ministry sets deadlines and publication dates. In certain cases, the ministry can grant the permit on behalf of the local or regional authorities. Besides 
coordinating the permit granting process it ta kes the decision on the spatial planning. 
This coordinated process allows for the pub lication of all information at the same 
time, enabling transparency and providing ci tizens the opportunity to engage at a 
central point of the process. One-stop-shop approaches in other countries were also 
praised for facilitating the permit granting process (e.g. Greece, Ireland and Austria). 
 
- The National Policy Statements (NPS) in the United Kingdom are an example of an 
overarching infrastructure de velopment strategy setting out  the Government’s energy 
policy. It explains the need for new ener gy infrastructure and contains further 
instruction on how to assess  project applications an d the impacts of energy 
infrastructure projects. The NPSs thus incr ease the transparency and predictability of 
the permit granting process by defining the ma in issues and objectives considered for 
granting the permit. Setting a clear and l ong-term oriented energy policy is also 
described as a facilitatin g measure in Slovakia. 
 
- Organised public debates by a national comm ission gives the genera l public in France 
the opportunity to voice thei r opinion and influence major planning and construction 
projects in advance of any decision being taken. Although it prolongs the process up-
front it can prove beneficial for public ac ceptance and help to avoid subsequent 
appeals and other hold-ups. The Swedish experience similarly shows that spending more time and attention in the pre-applicati on phase – consulting with all stakeholders 
concerned by the project and making all documents releva nt to the decision process 
public – can speed up the overall process. 
 
- In Portugal a cooperation  between environmental NGOs , the national conservation 
agency (ICNB) and power line construction companies agreed to include rules for mitigation of impacts on bird populations  in their planning and construction 
guidelines. 
 
- To change the fact that the broader populat ion is often unaware of  the TSOs activities 
and goals, the Belgian TSO, ELIA, launc hed several successful media campaigns. 
They inform the general public about its activities, policy goal s and ongoing projects 
and explained the reasoning and benefits of  further infrastructure development. 
 
 
 65ANNEX 4 
OUTCOME OF STAKEHOLDER CONSULTATION AMONG TRANSMISSION SYSTEM OPERATORS  
 
1. ENTSO-E  
ENTSO-E carried out a survey among 41 European TSOs in 34 countries. Six main barriers to 
investments are considered by TSOs: social accepta nce, planning delays, few investment incentives (in 
particular for R&D and innovation), and the lack of  stable return on investment as well as the 
uncertainty about future regulatory regime change . Cross-border projects require a reinforcement of 
the national grids. Public funding should be target ed to address specific project/country risks and with 
a competitive approach to the label and support. 
 
More detailed responses were provided by: 
• Amprion (Germany) 
• Eirgrid (Ireland) 
• Elia (Belgium) 
• EMS (Serbia) 
• 50 hertz (Germany) 
• HTSO (Greece) 
• MAVIR (Hungary) 
• REE (Spain) 
• RTE (France) 
• Statnett (Norway) 
• Swissgrid (Switzerland) 
• Terna (Italy) 
• Transelectrica (Romania) 
 
Financing of infrastructure in the past 
 
For past investment mainly corporate financing was used and projects were implemented together with adjacent TSOs, investment expenditure being covered in the CAPEX of the TSOs concerned. Next to 
debt and equity financing, auction revenues from cr oss-border capacity allocation are used to fully or 
partially finance interconnectors (only one TSO refe rred to this financing). Upfront pre-construction 
investments are mainly financed by 100% equity. Debt  capital can hardly be attracted for this type of 
investment. Among the main constraints to i nvestment, TSOs raised the following issues: 
− Time-lag in the remuneration of invested capita l during the construction phase (pre-financing and 
start-up losses, of particular importance when pr ojects are delayed by permitting or acceptance 
problems) 
− Transmission fees do not cover all costs linked to the internal reinforcement of the grid linked to 
connection of new RES generation (s hallow transmission fees, 1 TSO), 
− Lack of incentives for technology innovation and R&D or other risks,  
− Projects that will face particular challenges rela te to offshore developmen ts or submarine cables 
and for some countries interconnector investments. 
 
Recommendations for future financing and EU support 
 
In the light of the new and urgent investment cha llenges, TSOs will need to attract equity and debt 
financing and new investors. Asked about the ad ded value of EU support, TSOs recommend financial 
support to the construction phase. Some TSOs note th at the most effective measure is to ensure 
sufficient rate of returns for all projects and rate of return markups for projects of major importance 
and to align the RORs to the risks faced by project owners.   
 
 662. ENTSO-G  
The consultation of TSOs among ENTSO -G included detailed responses by: 
• GAZ SYSTEM 
• Gasunie 
• National Grid 
• Thyssengas 
• GEOPLIN PLINOVODI 
• RAG 
• DESFA 
• ENGAS 
• GRTgaz 
• OMV 
• Wingas 
• Fluxys 
• FGSZ 
• NET4GAS 
 
Financing of infrastructure in the past 
 
Past investments were financed on the basis of corp orate financing within the structure of the parent 
company on the basis of equity and shareholder loans complemented by EU direct grants and EIB 
loans. Depending on the degree of ownership unbundli ng and international expansion, the experience 
with credit ratings, corporate bonds, project financi ng and direct exposure to capital markets differs 
widely. Project financing was mainly used fo r new LNG terminals and new interconnectors in 
Western Europe.  Project bonds and project financing via special project vehicles are being examined 
for future investment by TSOs outside of the na tional network. The attractiveness of these bonds will 
largely depend on the costs.  
 
Recommendations for future financing and EU support 
ENTSOG Members underlined that new gas projects ai ming to increase diversification, competition, 
market integration and security of supply, thus re moving market Imperfections, will not come forward 
by relying on market (shippers) commitments alone . While volume risk is covered in regulated gas 
networks, fluctuating utilization, th e short-term tariff setting and cap acity allocation do not fit to the 
long-tem investment cycles.  Future EU support should minimize investment l ead times and construction risks, reduce the 
administrative burden on project promoters, offer coordinated political support to decrease country 
risks in geopolitically difficult regions, enhance cros s-border cooperation and the coordination of open 
seasons. The EU should support should be targeted to the entire investment cycle including feasibility 
and routing studies, environmental impact assessme nts (EIA), land and building permit design as well 
as the construction of projects.   
Cost allocation should be enhanced  by multilateral negotiations of investment projects at regional 
level between operators and regulat ors with strategic guidance by ACER and ENTSOG. In practical 
terms, TSOs in the respective Member States c ould book the capacities needed for security of supply 
and include these costs in their respective transm ission tariffs. Other options include settlements 
through direct cash transfers between TSOs or thr ough netting system using EU  funds granted to the 
Member States concerned. 
 While ENTSOG members unanimously call for instru ments to make projects bankable along the long 
term investment cycle, they consider various in struments depending on the particular needs of the 
TSOs. These range from credit enhancement, to public/private guarantees (for example through the 
 
 67EIB), European public private investment funds, harmonized investment conditions and performance-
related incentives as well as direct EU grants and a dedicated EU fund for infrastructure.  
  
3. Gas Infrastructure Europe (GIE)
 
Investment in regulated and non-regulated infrast ructure in the gas sector requires a long-term 
commitment either by regulators or users. Given the regulatory and market trends towards short-term 
capacity, GIE underlines that tariffs and investment  regulation should give long-term signals for 
investment. New financing instruments should be beneficial to all projects. Costs of stranded assets 
remain with consumer in the case of regulated ne tworks. Risk profiles change as gas TSOs are about 
to unbundle or restructure the ownership. Gas TSOs will need to invest in IT and human resources to 
handle the growing capacity and congestion manage ment with short- and long-term products.  
Among the measures suggested by GIE are the following: 
− Cost-allocation mechanism is mentioned in cases, where the lack of user commitment could be 
substituted by cross-border compensation. 
− Adequate risk/reward ratios and tariff to ensure long-term signal and not only short-term low rates 
of return 
− Incentives for operators – performance-relate d rewards for implementation of network 
development measures, independent  of and on top of the allowed revenues, including shortened 
amortization period in order to limit risks.  GIE sees higher risks for cross-border projects due to inconsistent regulatory frameworks on two si des of the border and higher complexity. 
 
 68ANNEX 5 
ENERGY INFRASTRUCTURES PRIORITIES  
 
 
The priorities for the period up to 2020 are the following: 
 a) In electricity: 
• Developing an offshore grid in the North Sea, the Irish Sea, the English Channel and the 
Baltic Sea and reinforcing and building new ons hore North-South interconnections in Central 
Europe; 
• Developing interconnections in South-Western Europe; 
• Strengthening the electricity networks in Centra l Eastern Europe and South Eastern Europe in 
North-South and East-West electricity flow directions; 
• Developing interconnections between the Baltic  Member States and their Union neighbours 
and reinforcing internal grid infrastructures accordingly; 
• Implementing the deployment of smart grid technologies across the Union; 
 b) In gas: 
• Developing the transmission of gas in the Southern gas corridor; 
• Developing interconnections between the Baltic  Member States and their Union neighbours 
and by developing interconnections in Centra l Eastern and South Eastern Europe in North-
South direction; 
• Increasing interconnection capacities for Nort h-South gas flows in Western Europe; 
 c) In oil: 
• Reinforcing the interoperability of the oil pipeline network in Central Eastern Europe. 
 
The two longer-term priorities are the development of electricity highways and CO2 transport 
networks.  
 
 69ANNEX 6 
TYPICAL PROJECT DEVELOPMENT PROCESS FOR AN ENERGY INFRASTRUCTURE PROJECT 
AND EXAMPLES OF PROJECTS HAVING FACED PERMIT GRANTING DELAYS  
 
 
 
Figure 1: Typical project development process 
 
 
 
 
Table 7: Projects having faced permit granting problems 
 
Member State Project Duration of the 
permitting procedureProblems 
encountered 
Steiermarkleitung, 380 kV electricity line 1982-2007* Lengthy 
administrative 
procedures, public 
opposition Austria 
Salzburgleitung, part 
St- Peter – Salzburg, 380 kV electricity line 1995-2010* Introduction of EIA 
requirement throughout the 
procedure, delays in 
administrative and litigation procedures 
Ulvila, Kangasala, 400 kV electricity line 2003-2008 Public opposition and 
lengthy litigation procedures Estonia – Finland 
Estlink  2001-2006 n/a 
 
 70Member State Project Duration of the 
permitting procedureProblems 
encountered 
Nantere – Nourottes, 
225 kV electricity line 2001-2009 Lengthy 
administrative 
procedures France 
France – Lyon – 
Chambery connection, 400 kV electricity line 1999-2006 Lengthy 
administrative procedures 
France-Spain French-Spanish 
interconnector, 380 kV electricity line 1970s-2014* 
(expected, including construction) Lengthy 
administrative procedures for some parts of the project, 
strong public 
opposition 
Interconnector 
Halle/Saale-
Schweinfurt, 380 kV electricity line 2006-2013 (expected) Public opposition, 
lengthy administrative 
procedures, environmental requirements Germany 
Windcollectionline 
Mecklenburg Vorpommern – Schleswig Holstein, 
380 kV electricity line 2005-2013 (expected) Lengthy 
administrative proceedings with differences across 
federal state borders – 
one part of the project is constructed, the other part waiting for permission 
Germany/ Netherlands Niederrhein – 
Doetinchem, 380 kV 
electricity line 2009-2014+ 
(expected, including 
construction) Delays due to cross-
border issues in 
planning procedures 
(cross-border point not fixed in NL – necessary to start the procedure in DE) 
Greece High pressure gas 
pipeline to Aliveri 2006-2011 (expected) Lengthy 
administrative 
procedures, 
environmental requirements, lack of resources 
Hungary/Romania Hungarian-Romanian 
400 kV electricity line 2003-2009 Land acquisition 
issues, including administrative formalities 
Hungary/Slovenia Hungarian-Slovenian 
400kV electricity line 2000-2012 (expected) Lengthy procedures 
due to environmental requirements 
Italy Sorgente-Rizziconi, 
380 kV electricity line 2004-2009 Public opposition due 
to environmental 
concerns 
 
 71Member State Project Duration of the 
permitting procedureProblems 
encountered 
Turbigo-Rho, 380 kV 
electricity line 1994-2004 Conflicts with regard 
to routing through 
densely populated and environmental protection areas 
Spain Martorell-Figueras 
high pressure gas 
pipeline 2006-2011 Lengthy procedures, 
particular complexity 
of the projects needing consents from several regions 
Sweden Stenkullen Lindome 
400kV electricity line 2004-2010 Lengthy 
administrative procedures and high number of authorities 
involved 
Beauly-Denny, 400kV 
electricity line 2005-2010 Public opposition, 
environmental requirements UK 
Second Yorkshire 
Line Project, 400 kV electricity line 1991-1998 Lengthy 
administrative procedures, public opposition 
*including planning and pre-application efforts. For all projects where these efforts ar e not included, an average 
of 2 years for pre-application has to be added. 
 
 
 72ANNEX 7 
KEY DATA ON PERMIT GRANTING PROCEDURES IN SELECTED MEMBER STATES  
Country AT BE BG CZ DE DK  EE EL ES FI FR HU 
                 
Duration and delays                
time limits for statutory process Y N na Y partly N na Y partially N N Y 
real average duration 3 years* 4 years na 4 years 8 years 10 years na 5 years 3* years 6 years 5.5 years* 2 years* 
                 
Authorities and permits                
number of permits >1 5 na 3 1 2-3 na 1 >3 3 3 3 
responsible authorities >1 na na na >2 2-3 na 1 >10 8-10 1-2 3-10 
                 
Fast-track procedure existing Y N na N Y N na Y Y N N N 
 
Country IE IT LT LV NL PL PT RO SE SK Sl UK 
                 
Duration and delays                
time limits for statutory process Y  Y N partially partially partially partially NNNN  Y  
real average duration 4 years 5 years 4 years* 3 years*1.5 
years* 4 years*1.5 
years*3.5 
years 9.5 years 4 years* 7.5 years 4 years 
                 
Authorities and permits                
n u m b e r  o f  p e r m i t s  1   1331 > 32 > 4244  1  
responsible authorities 1 1 several >5 1 >3 >1 25 >2 >2 4 1 
                 
Fast-track procedure existing Y  YNNYYN YNNN  Y  
*pre-application efforts to be added (average 2 years)  
Time limits  (partially or entire procedure) 13 MS 
1 responsible authority at national level 5 MS SUMMARY:  
Fast track schemes 10 MS 
Sources: Consultation of TSOs, Roland Berger study on permitting, individual interviews 
 
 73 
ANNEX 8 
MAIN REASONS FOR PUBLIC OPPOSITION TO ENERGY INFRASTRUCTURE PROJECTS  
 
 
• Unclarity about the added value of a project : The public generally questions the necessity of a 
project. Usually, it is up to the promoter to communicate the benefits and costs of a project, 
without support from authorities. The efforts needed to communicate and convince the public 
about the necessity and the benefits of a project can lead to major delays of up to one year. 
• Impacts on the environment and land scape, health and safety concerns:  Public opposition is 
particularly strong for electricity overhead lines,  because of the (at times perceived) impact of 
power lines on the environment, and landscape (the notion of the "Not in my Backyard" (NIMBY) 
phenomenon has in the past been frequently quoted , where citizens agree to the general objective 
of a project but refuse its construction in their vicinity), as well as safety and health concerns, especially with regard to electro-magnetic fields . Additional resistance arises as cross-border 
projects are perceived as mere "transit lines" withou t local benefits. Gas installations are usually 
less affected by public resistance, but difficulties have occurred with some LNG and storage sites 
and gas pipelines. 
• Late and insufficient involvement of the public and stakeholders : An effective dialogue with 
the public, i.e. landowners/citizens and stakeholde r organisations, is essential to gain public 
acceptance. However, in many case s, the public is not consulted at the very beginning of the 
project and is hence not adequate ly involved in the decision-making process. The perception to be 
confronted with precooked decisions has in ma ny cases provoked substantia l opposition. Further, 
due to the complexity of the process it is often unc lear for citizens at what stage and how they can 
intervene, particularly when public consultations  are carried out repeatedly on the same issue but 
within different procedures. 
 
 74ANNEX 9 
NATIONAL ELECTRICITY AND GAS MARKET STATISTICS  
 
 
Figure 2: Electricity transmission tariffs – sum of generation and load fees (in €/MWh) 
0510152025
Austria
Belgium
Bosnia and …
Bulgaria
Croatia
Czech Republic
Denmark
Estonia
Finland
France
Germany
Great Britain
Greece
Hungary
Ireland
Italy
Latvia
Lithuania
Luxembourg
FYROM
Netherlands
Northern Ireland
Norway
Poland
Portugal
Romania
Serbia
Slovak Rep
Slovenia
Spain
Sweden
Switzerland
400-380 kV 220-150 kV 132-50 kVDenmark
GrecceFrance
Italy
Romania
SpainNorway
SwedenBosnia and Herz. 
Source: ENTSO-E, 2011 
(Those countries, for which certain elements of the 201 0 transmission tariffs are estimates are marked in red.) 
 
  
Figure 3: Infrastructure components of electricity transmission tariffs (in €/MWh) 
051015202530
Austria
Belgium
Bosnia and Herzegovina
Bulgaria
Croatia
Czech Republic
Denmark
Estonia
Finland
France
Germany
Great Britain
Greece
Hungary
Ireland
Italy
Latvia
Lithuania
Luxembourg
FYROM
Netherlands
Northern Ireland
Norway
Poland
Portugal
Romania
Serbia
Slovak Rep
Slovenia
Spain
Sweden
Switzerland
Other regulatory charges Losses System Services Infrastructure
 
Source: ENTSO-E, 2011 
 
 
 75Figure 4: Electricity prices for household customers, 2nd semester 2010 / 2010s2 (in €/kWh) 
0,0000,0500,1000,1500,2000,2500,300
BA BG EE LV RO HR EL LT FR FI TR PL CZ SI UK HU SK PT NL MT EU-
27LU EA ES IE NO IT A T SE BE CY DE DK
W ithout taxes Other taxes VAT 
Source: Eurostat (data for Italy provisional). EA designates the euro area. 
 
 
 Figure 5: Electricity prices for household customers, 2010s2 (in PPP/kWh) 
0,0000,0500,1000,1500,2000,2500,300
FR FI EL NO UK LU EE NL SE IE LV EU-
27HR BE SI A T BG IT DK CZ LT ES PT RO TR CY PL MT DE SK HU
 
Source: Eurostat (not available for Bosnia and Herzegovina) 
 
 76Figure 6: Percentage change in electricity prices for household consumers, 2010s2-2009s2 
-10%-5%0%5%10%15%20%25%30%35%
NL
LU
IT
CZ
HUUK
HR
LV
IE
AT
BG
PLPT
EA
SK
EU-27
TR
BE
DK
DE
FI
SI
SE
FR
RO
EE
ES
MT
NO
EL
CY
LT
 
Source: Eurostat 
 
 
 
Figure 7: Share of network costs in electricity price for household consumers, without taxes, 
2010s2 (in %) 
0%20%40%60%80%100%
RO CZ NO EE LT DK LU BE SI A T LV SK SE PL ES FI PT HU HR DE NL IT BG EL UK CY TR MTEnergy and supply Network cost 
Source: Eurostat 2011 (data for Italy provisional, no disaggregated price data for Ireland, France and Bosnia 
and Herzegovina) 
 
 77Figure 8: Electricity prices for households in Europe (December 2010) 
 
Source: DG Energy, Market Observatory, 2011 
 
 
 78Figure 9: Electricity prices for indus trial consumers in Europe (December 2010)  
 
Source: DG Energy, Market Observatory, 2011 
 
 79Figure 10: Natural gas prices for household consumers, 2010s2 (€/GJ)  
05101520253035
RO TR HR EE LV UK BG SK BA LT LU PL CZ IE ES HU DE EU-
27FR A T BE PT EA SI NL IT DK SE
W ithout taxes Other taxes VAT 
Source: Eurostat (data for Italy provisional)  
 
  Figure 11: Gas average quarterly wholesale prices (Q4 2010) 
 
Source: DG Energy, Market Observatory, 2011 
 
 80ANNEX 10 
ELEMENTS OF NATIONAL REGULATORY FRAMEWORKS FOR ELECTRICITY AND GAS 
INFRASTRUCTURE  
 
Table 8: Remuneration of electricity infras tructure investments in selected Member States 
 
Country Type of remuneration Calculation Rate 
Austria 
 WACC  pre-tax nominal 6.32% 
 
Czech Republic  WACC  pre-tax nominal 7.65% 
Germany RoE (pre 2006) 
RoE (post 2006) pre-tax real 
pre-tax nominal 9.29% 
7.56% 
Greece WACC pre-tax  8% 
Spain WACC post-tax  7.6% 
Finland WACC (electricity)  pre-tax, status 2006 6.5% 
France WACC (electricity) pre-tax 7.25% 
Hungary RoE  4.5% 
Ireland WACC pre-tax 5.95% 
Italy  WACC (electricity) pre-tax 6.9% 
Lithuania WACC (electricity) Pre-tax nominal 5% 
Netherlands WACC (electricity) Pre-tax nominal 
Pre-tax real 6.9%-8.4% 
5.3%-6.7% 
Portugal WACC (electricity)  7.8% 
Great Britain  WACC post tax cost of equity 5.05% 
Source: Roland Berger, 2011 
 
WACC: Weighted Average Cost of Capital 
RoE: Return on Equity 
 
 
Table 9: Overview on investment related aspects of the national regulatory frameworks for gas 
 
Country Type  Length of 
regulatory 
period TOTEX 
approach Investment 
allowances CAPEX 
time shift 
gap RAB 
based on 
replac-
ement 
cost RAB 
based on 
historic 
costs RAB 
based on 
indexed 
historic 
costs 
Austria Rate-of-
Return      x  
Belgium Revenue cap 4 years    x x  
Bulgaria Rate-of-
Return 
        
Czech 
Republic Revenue cap 5 years      x 
Denmark Rate-of-
Return       x 
Estonia Price cap        
Finland Revenue cap 4 years     x  
France Revenue cap 5 years  x x   x 
Germany Revenue cap 5 years (as 
of 2013) x x x x x x 
depending 
of the  
 
 81Country Type  Length of 
regulatory 
period TOTEX 
approach Investment 
allowances CAPEX 
time shift 
gap RAB 
based on 
replac-
ement 
cost RAB 
based on 
historic 
costs RAB 
based on 
indexed 
historic 
costs 
year of 
purchase  
Great Britain Revenue cap 5 years      x 
Greece Revenue cap       x 
Hungary Revenue cap 4 years    x   
Ireland Revenue cap 4 years      x 
Italy Revenue cap 5 years     x  
Lithuania Price cap 5 years     X 
financial 
accounts   
Luxemburg Rate-of-
Return       x 
Netherlands Price cap / 
yardstick  4 years x x x   x 
Portugal Rate-of-
return      x – 
standard 
cost  
Romania Revenue cap 5 years      x 
Slovakia Price cap 
 3 years   x Tariffs based on price 
benchmarking 
Slovenia Price cap 1 year (3 
years in the 
future)     x  
Spain Price cap 4 years x x   x  
Source: KEMA study 2009. 
 
 
Table 10: Remuneration of gas infrastructure investments in selected Member States 
Country Type of remuneration Calculation Percentage 
Austria WACC post-tax  
(pre-tax  6.97% 
(8.3%) 
Belgium WACC pre-tax real 6.21% 
Czech Republic WACC  (pre-tax nominal) 
post-tax nominal (8.289%) 
6.13% 
Germany RoE (pre 2006) 
RoE (post 2006) pre-tax real 
pre-tax nominal 9.29% 
7.56% 
Finland WACC  pre-tax nominal  
status 2006 9-10% 
France WACC  pre-tax real 7.25% 
Greece WACC (pre-tax nominal) 
pre-tax real (10.06%) 
6.56% 
Great Britain WACC  pre-tax real 6.25% 
Hungary WACC pre-tax real 6.9% 
Ireland WACC pre-tax real 5.2% 
Italy WACC  pre-tax real 6.7% 
Lithuania WACC  pre-tax real 6.87% 
Luxemburg WACC pre-tax nominal 8.5% 
Netherlands WACC  pre-tax real 5.5% 
Portugal WACC  pre-tax real 8.0% 
Romania WACC pre-tax real 7.88% 
Slovenia WACC  pre-tax real 5.87% 
Spain WACC post-tax nominal 5.48-5.68% 
Source: KEMA study 2009  
 
 82ANNEX 11 
PROJECT CASE STUDIES CONCERNING REGULATORY AND FINANCING ISSUES  
 
1. ELECTRICITY 
 
1.1. Offshore grid 
 
The development of an offshore grid  in the Northern Seas poses speci fic challenges by combining the 
connection of offshore wind (or other) energy sour ces and cross-border interconnection for electricity 
trade107. The benefits of such a grid can be measure d e.g. according to installed wind generation 
capacity in each country or electricity flows to coastal countries, with both methodologies yielding 
very different results in terms of cost alloca tion. Existing national regulatory frameworks do not 
provide adequate rules for such allocation and rea lising synergies by combining connection projects or 
connection and interconnection projects. Nor do th ey regulate appropriately onshore connection, 
prioritisation between electricity in-feed and trade fl ows or the offshore grid’s added value in ensuring 
onshore system security and ancillary services. 
• According to the OffshoreGrid study, a total of about 320 offshore wind projects are 
forecasted to be online by 2030, totalling about 150 GW in Northern Europe. Based on its analysis of 
optimal connection solutions for offshore wind farms depending on their distance to shore, 
concentration and size, the OffshoreGrid study concl udes that more than one third or almost 55 GW 
should be connected via hubs rather than radially as is the case today (cf. Figure 12), mostly in the 
North Sea and, to a lesser extent, the Baltic Sea108. Moreover, opportunities for T-connections of 
offshore wind parks to interconnectors have been identified for the following development areas: 
− North and Irish Seas: BorWin, HelWin and SylW in (DE); Idunn and Sorlige Nordsjoen (NO); 
Irish Sea R9, Firth of Forth and Dogger Bank (UK) for a total of about 30 GW; 
− Baltic Sea: Baltic 1 (DE); Kriegers Flak (DE, DK and SE); Blekinge Taggen and Södra 
Midsjöbanken (SE); several wind farms in Po lish waters for a total of about 6 GW. 
Figure 12: Projects connected radially and via hubs in 2030 (Source: OffshoreGrid study) 
 
 
                                                 
107  See Annex 4 of SEC(2010) 1395 for a more detailed description. 
108  While Germany would host by far the biggest number of these hubs (about 60), Member States benefiting from 
such a solution could include Belgiu m, Denmark, Finland, Netherlands, Poland, Sweden and the United Kingdom. 010 20 30 40 50 60 70 
020 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 Mor
e 
Project distance to connection point (km)Number o project sProjects with radial connections  
Projects in hubs
 
 83Already for the period up to 2020, the study has identified about 30 offshore wind projects in Germany 
and the Netherlands, but also Finland – totalling a bout 9 GW –, for which a hub connection would be 
the optimal socio-economic solution. These numbers  can be compared with those of national 
regulators of the North Seas Countries Offshore Grid Initiative who foresee installed offshore wind generation capacity to increase from about 4 GW to  40 GW by 2020, of which about 22GW should be 
further out to sea. As regards offshore interconnector s – most of which are or would be regulated –, 
new projects to be implemented by 2020 total 15  GW, compared to current total interconnection 
capacities of about 7 GW in the region
109. 
 
As stated by the NSCOGI working group on regulat ory and market aspects: "Typically, at present, 
new interconnectors or shared lines are developed on a 50:50 shared cost basis between the connected 
TSOs. While this traditional approach works at pr esent while lines are between two countries, it may 
be more challenging to develop appr opriate and fair cost allocation rules when lines begin to connect 
more than two countries or are connected to offshore generation. This issue is not specific to offshore 
grid development, but will arise more generally as more cross-border infrastructure is built on land 
across Europe."  The Kriegers Flak project is an excellent example of the conc rete difficulties encountered when 
trying to develop offshore transmission infrastructure in an integrated manner. It initially envisioned 
the development of three wind farms within Ge rman, Swedish and Danish waters, linked by a 
combined offshore grid connection, which would al so serve as an interconnection between the three 
countries. The three-country solution has in the m eantime been abandoned with Sweden's withdrawal, 
and the development of the project has been dela yed because of regulatory challenges, despite EUR 
150 million of EU funding received in the context of the European Energy Program for Recovery. 
 
Three different TSOs were involved (Vattenfall, En erginet.dk and Svenska Kraftnätt), as well as two 
market systems and two synchronous zones, posi ng a huge challenge regarding regulation on cross-
border infrastructure. The feasibility study, publishe d in a joint report of the three TSOs, concluded 
that the combined solution would generate positive net benefits compared to the separate solution 
(reduced price differentials between markets, spot market development, security of supply), but also 
imply higher upfront costs (EUR 1.36 bn compared to EUR 1.29 bn for a smaller solution) and more risks and require close coordination between the transmission companies in the area. The current regulatory framework does not incentivise this, as it is mainly national in scope and targeting the 
improvement of internal services and cost savi ngs instead of promoting a regional approach. 
Additionally, there are other regulations that might  also distort the incentives to cooperate, such as 
different rules for renewables connection, balanc ing or renewables support in the three countries
110. 
 
1.2. Lithuania-Poland interconnection (LitPol link) 
 
The planned 150 km DC interconnec tion between Lithuania and Poland aims at connecting the Baltic 
States to the EU continental system with a cap acity of 2x500 MW. Total investment costs are 
estimated at EUR 237 m. 100 km of this DC line will  run through Polish territory while 50 km will be 
on Lithuanian territory. The participating TSOs have  set up a special purpose vehicle, LitPol Link. 
 The interconnection will considerably enhance the security of supply of the Baltic States and end the 
isolation of the entire region. The link is essential fo r the integration of the Baltic States to the EU 
electricity market. 
 Major obstacles for the LitPol link are related to the difficult discussions with land owners on the 
Polish side, where on average 50 to 80 owners are involved per km on average, and to the potential 
environmental impacts of an overhead line. The busin ess case of the project is also closely linked to 
the Polish participation in the NPP project in Lithuania. 
                                                 
109  NSCOGI Working group 2, "Report to the Steering Committee", June 2011. 
110  Meeus et al., 2010 
 
 84 
1.3. Smart grids 
 
For the deployment of smart grid technologies, di stribution system operators could in many Member 
States bear the major part of costs for a the corr esponding investments, while not necessarily being the 
only or even main beneficiaries. Smart metering ha s developed most in those Member States, where 
the benefits arising from two-way communication are clear and go directly to the party bearing the 
investment cost111. The deployment of smart networks on a larger scale however has proven to be 
difficult, as the benefits they provide are spread  among multiple actors of the system. According to 
analysis of demand response schemes in the United States, about 80% of the value created by such 
schemes go the savings in generation capacity costs, 10% to savings in energy costs and 10% to the 
reduction of transmission and distribution costs (through e.g. the delayed need for new investments)112. 
This translates cost-ben efit asymmetries among the actors concerned by smart grid developments. 
Eurelectric estimates that distribution system ope rators who will pay for the vast majority of 
investments needed, might only reap around 60% of the benefits. As long as no cost allocation solution can be found, which includes other beneficiar ies such as final consum ers or generators, rapid 
deployment of smart grids will be seriously impaired.   2. GAS 
 
2.1. MidCat Pipeline – North-South Gas corridor in Western Europe 
 
MidCat is a 800 km natural gas interconnector linking the French and Spanish gas markets from 
Barbaira (France) to Catalonia (Spain) including bi -directional flow (ES-FR 7.2 bcm/y and FR-ES 5.6 
bcm/y). MidCat promoters TIGF (France) and En agas (Spain) decided to build a fully regulated 
interconnector on a corporate financing basis invol ving a total investment volume of 1,550 million 
Euros. The connection consists of a 600 km pipeline in France and 200 km in Spain which results in an investment volume for TIGF of 1,300 million Euros and 250 million Euros for Enagas. 
 
The project development and investment decision were conditioned by two main factors: the open 
season process and the agreement between the Span ish and French regulator on the cost/benefit 
allocation. The economic test via an open season procedure caused delays in the process as well as the lengthy regulatory negotiations. The France-Spain 2015 open season, involving  four operators from 2 
countries on 6 interconnection points, showed a lack of  interest by shippers to commit to long-term 
capacity. The cost allocation process faced a number  of difficulties linked to the cost allocation, 
including differences in the accreditation, recovery  and valuation of costs and the tariff setting. 
 The open season failed to reflect the wider socio-ec onomic benefits of the MidCat pipeline for the 
development of the North-South Gas Corridor in West ern Europe. The benefits of market integration, 
increased competition in Southern France, the optimi sed use of developed Iberian LNG infrastructure 
and pipelines from North-Africa as well as greater s ecurity of supply for the continent were not taken 
into account by the market participants.  MidCat was also supported by co-financing tota lling 175 765 000 million Euros from the European 
Energy Programme for Recovery. 
 
2.2. Slovakia-Hungary Interconnector – North South Gas Corridor in Eastern Europe 
 
The 115 km natural gas interconnector between Slova kia and Hungary is to connect Velké Zlievce 
(Slovakia) and Vecsés (Hungary) with an annual capac ity of 5 bcm/y. The project promoters Eustream 
and FGSZ decided for a fully regulated interconnector  with a total investment volume of 192 million 
                                                 
111  Italy's ENEL Distribuzione successfully introduced sm art meters to reduce unpaid  electricity consumption. 
112  Ahmad Faruqui et al., 2009 
 
 85Euros. The interconnector consists of a 21 km pi peline in Slovakia and 94 km pipeline in Hungary 
with bi-directional capacity. 
 
Two open seasons were organised without yieldi ng sufficient market demand through long-term 
capacity commitments. The first open season did no t reach the threshold of 10mcm/d, but only 
5mcm/d (while total capacity is 14mcm/d). Th e open season indicated only limited capacity booking 
for short-term contracts (1/3 of capacities for the fi rst 5 years) despite the interest from the Slovakian 
side. 
 
Key difficulties for the project relate to the cost a llocation (based on the length of the pipeline in each 
of the country) which is not sufficiently taking in to account the wider benefits. The interconnector 
brings significant EU wide benefits for market in tegration in Central Eastern Europe on the North-
South axis, but also benefits to the Hungarian gas market thanks to bringing in new sources of gas. 
The project enhances security of supply of Slovaki a by providing access to Hungarian gas storages in 
case of emergency.  The project received support from the European Energy Programme for Recovery totalling 30 million Euros.  
 
 86ANNEX 12 
EXTERNALITIES FACED BY ENERGY INFRASTRUCTURE PROJECTS  
 
 
 
• Regional or Union-wide integration of shared el ectricity or gas resources , like large-scale 
renewables or gas from new sources or an inte grated offshore electricity grid: The benefits 
provided have a global public good character, which is not sufficiently reflected in the revenues individual operators can earn from the corresponding investments. 
• Use of  innovative technologies: Projects can  involve technological and operational challenges 
and other "first of their kind" and first-mover ri sks and uncertainties. While the investment costs 
incurred fall upon the project promoter in the sh ort term, the benefits provided in terms of 
technological and operational progress as well as the sy stem benefits and future cost savings for a 
region or the EU as a whole only materialise in the medium to long term
113. Examples include 
high voltage direct current (HVDC) electricity  lines, both on- and offshore, or smart grid 
developments, but also innovative large-scale electri city storage. Such projects are currently not 
covered under the public funding available for r esearch, development and deployment, notably at 
EU level (cf. the 7th Framework Programme and the Strategic Energy Technologies Plan). Being 
industrial-scale applications; they are supposed to be paid for by tariffs. In the current regulatory 
environment, such innovative projects might be  shelved and replaced by suboptimal standard 
solutions, for which the risks and revenues are better known.  
• Regional or Union-wide security of supply  provided e.g. through increased capacity of the 
electricity or gas transmission network towards isolated or semi-isolated systems. Project 
examples include the Poland-Lithuania electricity interconnectors, the Estonia-Finland gas 
pipeline or the projected common LNG terminal in the Baltic region aiming at ending their isolation, but also many gas storage and reverse flow projects in Central Eastern Europe. Such projects can be difficult to realise, as regulators are reluctant to take on costs for a security of 
supply benefit, which might only realise very rarely  if at all – as is the case for the Hungarian-
Slovakia interconnector. 
• Reduction of electricity loop flows  through transit countries by reinforcing networks in the 
transit countries or increasing transfer capaciti es on the direct route between a generator and a 
consumer: As these flows are physical, not commerc ial, there is not necessarily a natural incentive 
for investments in form of achieving increased cr oss-border trading capacity. This would typically 
be the case for new transmission lines in Germany to  transport wind energy generated in the North 
towards the South of the country and reducing fl ows through the electricity networks of Poland, 
the Czech Republic, Slovakia, Hungary or Austria to the East or the Netherlands, Belgium and 
France to the West. Loop flows occur also in othe r regions such as Slovenia following commercial 
flows from France to Italy. 
• Increased  market competition provided by adding new or additional electricity or gas 
interconnection capacities and thereby creating the possibility for potential new entrants to access 
markets, lowering market concentration and possi bly contributing to price convergence: Market 
incumbents often resist the implementation of such  projects, which makes them difficult to realise. 
• Long-term optimal capacity  (or “advanced capacity”)  provided by "oversizing" gas pipelines 
or offshore electricity hubs and other shared network components compared to the short-term 
demand they cover: Infrastructure in place creat es new opportunities, stimulates demand and 
enables increased competition. According to Rious  et al. (2010), proactive behaviour of a TSO 
that anticipates connection of new generators with  short construction durations compared to the 
time needed to reinforce the network is the socially  optimal solution. However, due to the risk of 
sunk costs in case the generator never realises its investment in electricity or the supplier never 
                                                 
113  Cf. “new wave projects” as defi ned by Glachant and Kalfallah, 2011 
 
 87offers the quantities anticipated in gas, the costs for such a dvanced capacity provision are 
generally not accepted by national regulators, making such projects impossible to realise. 
• Internalisation of  environmental externalities:  The 2006 Stern Review on the Economics of 
Climate Change114 report has described climate change as biggest market failure or externality 
currently existing, mainly due to its supra-re gional nature and its long time horizon. Energy-
related emissions constitute ar ound 80% of total EU GHG emissions. New or improved energy 
infrastructures are necessary to en able the widespread provision of low carbon energy supplies, for 
which demand and supply and costs and benefits w ill be unevenly distributed across EU Member 
States115. In addition, by enhancing the climate res ilience of infrastructures of common interest, 
possible external costs of power outages or network disruptions can be reduced116. 
                                                 
114  http://webarchive.na tionalarchives.gov.uk/+/http ://www.hm-treasury.gov.uk/ sternreview_index.htm 
115  A first assessment of possible impacts from decarbonisation of the electricity sector by 2050 on the European 
electricity network and in particular interconnectors a nd net transfer capacities between Member States will be 
published in the Impact Assessment for the Energy Roadmap 2050. 
116  External costs of transmission system disruptions can exceed several times the impacts to the transmission system 
itself. As investments in reducing the risk of transmi ssion reduction are only made co mmensurate to the expected 
damage costs incurred by the system's operator, th e investment level can be  (socially) sub-optimal. 
 
 88ANNEX 13 
FINANCING CONTEXT FOR GAS AN D ELECTRICITY INFRASTRUCTURE  
 
  
Table 11: Corporate versus project fina nce in energy infrastructures 
 
 
 
Source: Roland Berger 
 
 89Figure 13: Revenue and size of EU TSOs  (based on 2009 revenues in EUR m) 
Source: Roland Berger  
 
  
Figure 14: Financial standing of EU TSOs  (solvency ratio in %, 2007/2009 average) 
 
Source: Roland Berger  
 
 90Figure 15: Ownership structure for EU TSOs in electricity 
 
Source: Roland Berger  
 
Figure 16: Ownership structure for EU TSOs in gas  
 
 
Source: Roland Berger  
 
 91 
Figure 17: Regulated Asset Base increase and funding constraints for EU TSOs 
 
Source: Rothschild, Presentation “Financing issues fo r European energy infrastructure”, 10 May 2011  
 
 92ANNEX 14 
THE CURRENT REGULATORY FRAMEWORK FOR INFRASTRUCTURE DELIVERY  
 
 
 
The 2010 impact assessment already presented the new regulatory framework of the Third Internal Energy Market Package (3
rd IEMP)117, applicable as of 3 March 2011, and the regulation on security 
of gas supply118 in terms of infrastructure development across borders, which will facilitate the 
implementation of grid investments in electricity and gas. Measures provided for by this framework 
would be implemented under the baseline scenario. 
1. The third internal energy market package 
The 3rd IEMP places the obligation on TSOs to operat e, maintain and develop secure, reliable and 
efficient transmission. The unbundling rules will pr ovide further incentives for TSOs to operate their 
networks efficiently and to expand them as necessary.  As described in the 2010 impact assessment, it 
has become clear that the ten-year network develo pment plans to be developed under this framework 
will not, in the short to medium term, be able to clearly prioritise among their projects to select those, 
which provide the highest European added value in view of implementing the infrastructure priorities 
endorsed by the European Council. 
Internal market legislation also provides a legal basis for implementing netw ork tariffs, which ensure 
the secure and efficient operation of the network. NRAs have the obligation to provide for a tariff 
framework, which allows for investment to take pl ace to maintain adequate network operation. Article 
37(8) of Directive 2009/72/EC and Article 41(8) of Directive 2009/73/EC in particular stipulate that 
NRAs "in fixing (…) tariffs (…) shall ensure that transmission and distribution system operators are 
granted appropriate incentive, over the short and lo ng term, to increase effici encies, foster market 
integration and security of supply an d support the related research activities".  
The 3rd IEMP more specifically obliges TSOs to build su fficient cross-border capacity to integrate the 
European transmission infrastructure. Article 16 of Regulation 714/2009 provides that revenues, 
which TSOs collect from marketing scarce cross-borde r capacities, i.e. congestion revenues, shall be 
primarily used for either guaranteeing the availability  of the allocated capacity or investing in new 
interconnectors before serving for reducing network tariffs. The table below shows past electricity 
congestion revenues earned by ENTSO-E members in the period 2006-2010. 
Table 12: Electricity congestion revenues 2006-2009 (in EUR m) 
TSO Country   2006 2007 2008 2009 2010 Variation 
first data 
year to 2010 
(%) 
APG Austria AT 26,25 44,46 63,20 49,45 32,54 24% 
Elia Belgium BE 58,13 40, 33 29,24 28,61 23,73 -59% 
NOS BiH Bosnia 
Herzegovina BA N/A N/A 0,38 0,20 0,78 105% 
ESO Bulgaria BG 0,00 2,32 23,60 19,13 19,55 742% 
HEP-OPS  Croatia HR N/ A N/A 5,86 4,91 12,87 120% 
CEPS Czech 
Republic CZ 101,96 59,78 34, 62 26,18 18,52 -82% 
Energinet Denmark  DK 79, 46 95,15 129,89 58,25 90,78 14% 
Elering OU Estonia EE 0, 00 0,00 0,00 0,00 0,22 N/A 
Fingrid Finland FI 11,87 22,60 23,20 4,86 9,05 -24% 
                                                 
117 Including Directives 2009/72 for electricity and 73 fo r gas and Regulations 713/2009 on ACER, 714 electricity and 
715 gas 
118  Regulation No 994/2010. 
 
 93TSO Country   2006 2007 2008 2009 2010 Variation 
first data 
year to 2010 
(%) 
RTE France FR 342,00 376,50 380,60 256,98 260,37 -24% 
TSO of 
EnBW+Amprion+50 
Hertz+Tennet+TIWAG 
Netz+VKW Netz Germany DE 316,30 220,56 222,46 167,90 141,00 -55% 
National Grid Great Britain GB  N/A N/A 106,00 66,10 61,60 -42% 
HTSO Greece GR 22,00 5,06 31,32 35,47 29,29 33% 
Mavir Hungary HU 29,44 47, 09 76,44 48,98 15,38 -48% 
EirGrid Ireland IE 6,20 13,14 0,00 0,00 0,00 -100% 
Terna Italia  IT 89,82 333,82  294,61 187,83 211,65 136% 
AS Augstsprieguma 
tikls Latvia LV 0,00 0,00 0,00 0,00 0,22 N/A 
MEPSO FYROM MK N/A N/A 1,16 6,71 4,40 279% 
AD Prenos Montenegro ME N/A N/A 1,77 3,67 4,32 144% 
Tennet Netherlands NL 107,63  53,96 105,90 59,00 34,00 -68% 
Statnett Norway NO 17,96 31,90 112,90 45,60 112,70 527% 
PSE Operator Poland PL 70, 16 40,92 28,08 13,43 6,43 -91% 
REN Portugal PT 0,00 23, 22 32,30 5,52 6,07 #DIV/0! 
Transelectrica Romania RO 10,68 17,69 36,66 22, 09 6,92 -35% 
EMS Serbia RS N/A N/ A 29,04 18,85 17,22 -41% 
SEPS Slovak 
Republic SK 22,48 44,39 36,17 27,90 5,10 -77% 
ELES Slovenia SI 3,12 25,91 32,55 32,95 28,51 814% 
REE Spain ES 25,79 61, 78 77,95 41,58 33,28 29% 
Svenska Krafnät Sweden SE 35,40 67,83 85,30 28,17 54,98 55% 
Swissgrid Switzerland CH 35,29 40,05 78,10 59,37 62,02 76% 
Total 1.411,93 1.668, 47 2.079,31 1.319,71 1.303,49 -8% 
Note: Countries with no congestion rents are not represented. 
 
Source: data from national TSOs collated by ENTS O-E, Commission analysis (last column), 2011  
2. The exemption regime 
In cases where "the level of risk attached to the invest ment [is] such that the investment would not take 
place unless an exemption was granted", EU internal  market legislation foresees the possibility for 
new cross-border infrastructure projects to be ex empted by NRAs from third party access (the owner 
of a grid is obliged to allow any suppliers non-di scriminatory access to its grid to supply customers), 
regulated tariffs, unbundling rules and (for electricity) rules on the use of congestion rents119. In cases 
where the NRAs concerned cannot agree on a decision within a given period of time ACER is obliged 
to take their place and issue a decision. The pro cedures also foresee that the Commission can ask the 
NRAs or ACER to amend or w ithdraw the exemption granted. 
Such exemptions have e.g. been granted to large pan-European gas import pipelines or LNG 
infrastructures and have comforted investors whose projects are either very capital intensive and/or 
carry exceptional risks, which could not be accommoda ted within the standard  regulatory framework.  
However, exemptions should only be granted in cases where the risks related to the investment are 
such that it is not viable without an exemp tion and when the new infrastructure will enhance 
competition. As demonstrated in Pelkmans and Kapff (2010), while contributing to cross-border 
                                                 
119 Article 36 Directive 2009/73/EC (gas) and Article 17 Re gulation (EC) No 714/2009: The exemption regime applies 
to all direct current electricity lines and certain alternating current lines and to major new gas infrastructure, i.e. 
interconnectors, LNG and storage facilities. 
 
 94network development, exempted (merchant) interc onnector investments financed through congestion 
rents alone yield suboptimal results in terms of soci ally desirable levels of interconnection capacity. In 
addition, broad exemptions from the regulated re gime without additional conditions may weaken 
competition, hinder reinvestment of profits in grid  reinforcements and undermine the application of a 
harmonized regulatory framework across the EU. To th is end, the Commission has regularly asked for 
substantial amendments of national exemption d ecisions with the view to alleviate potential 
competition concerns and support network investment. 
Under the baseline scenario, the Commission would ther efore continue to push national regulators to 
establish appropriate incentives through regulated tari ffs and to grant exemptions only where justified 
and with regulatory conditions that ensure th ird party access and support the development of 
infrastructures. Such an approach is likely to de liver the types of project s targeted under the third 
package, i.e. gas and electricity projects enhanci ng competition and security of supply. The exemption 
regime does not specifically address electricity projects aiming at the integration of renewables or 
greater system reliability. Nor does it solve the pr oblem faced by projects with asymmetric cost and 
benefit allocation, as any exemption is subject to  a national regulatory aut hority assessing the request 
made by an operator. It can hence be concluded th at the exemption regime would allow certain riskier 
investments to be delivered, without addressing the underlying problems related to cost allocation and 
broader investment incentives.  
3. The target model 
The Commission has worked over the last few years with regulators, TSOs and all other stakeholders 
to develop an electricity target model based on mark et coupling for linking elect ricity markets. For gas 
a target model is currently being developed. The process of implementing the 3rd IEMP by developing 
guidelines, framework guidelines and network codes to  reach the necessary level of harmonisation has 
already been started. Currently  these guidelines, framework guidelines and network codes are being 
prepared for electricity and gas to achieve common and coordinated congestion management120 and 
capacity allocation procedures on all interconnector s. For the years 2012 and onwards, the priorities 
for gas will notably include framework guidelines or  guidelines on tariffs. The Commission could also 
propose additional guidelines on investment incentives to  TSOs in electricity. All these new rules shall 
be in place by 2014. 
Aligning procedures for trading on interconnectors w ill help to align national markets and provide 
more harmonised signals across the EU for i nvestment in new interconnection capacity. These 
regulatory efforts will considerably improve i nvestment signals, including for cross-border 
infrastructure, once they are fully operational.  
4. The regulation on security of gas supply 
The regulation on security of gas supply for the first time proposes two clear and binding 
infrastructure standards: 
− Member States121 shall ensure that gas demand can be met even at the loss of their largest 
infrastructure (N-1 criterium). They have until 2014 to comply with this rule. Preliminary 
calculations of compliance with the n-1 standard  with and without projects to be financed 
under the EEPR can be found in the figure and the table below; 
− TSOs have to install physical reverse flows at all cross-border interconnections between 
Member States by end 2013, where they are beneficial for security of supply122. 
                                                 
120  It should be noted that the meas ures proposed by the Commission on conge stion management fo r gas only address 
contractual congestion at interconnecti on points and not physical congestion; nor do they address problems faced in 
the absence of interconnections (s ee draft impact assessment accompanying the Commission guidelines on 
congestion management procedures and replacing existing guidelines a nnexed to Regulation (EC) 715/2009). 
121 Except Luxemburg, Slovenia, and Sweden. 
122 Exemptions are possible and Member States can opt for a regional approach to fulfill these standards. 
 
 95Figure 18: Compliance with the N-1 standard (2009) 
0%50%100%150%200%250%300%
DK GR DE BE SK AT PL NL LV CZ EE ES IT HU FR UK RO SE LU PT BG SI LT IE FI EUN-1
Normal EERP 
 
Table 7: Compliance with the N-1 standard (2009)  
Mcm/day Production 
withdrawal 
capacity  Maximal 
Consumption*  Storage 
Withdrawal 
capacity  LNG 
send-out 
capacity  Incoming 
Pipeline 
Capacity  Single Largest 
Infrastructure  N-1 
AT 12,16 49,41 48,00 0,00 137,52 125,94 145% 
BE 0,00 139,20 22,80 24,70 321,61 94,43 197% 
BG 0,30 15,60 4,20 0,00 72,00 72,00 29% 
CY 0,00 0,00 0,00 0,00 0,00 0,00 - 
CZ 0,30 67,60 55,01 0,00 185,98 141,94 147% 
DE 45,00 400,00 463,32 0,00 579,44 105,96 245% 
DK 29,90 25,70 18,80 0,00 0,00 29,90 73% 
EE 0,00 4,30 0,00 0,00 22,99 16,80 144% 
ES 0,00 160,20 10,54 160,90 67,01 39,70 124% 
FI 0,00 1,00 0,00 0,00 20,68 20,68 0% 
FR 2,40 370,00 231,00 42,44 156,28 50,00 103% 
GR 0,00 14,00 0,00 13,69 38,36 19,20 235% 
HU 9,00 92,50 47,50 0,00 58,04 39,80 81% 
IE 1,00 20,30 2,60 0,00 30,00 30,00 18% 
IT 24,00 425,00 295,85 35,00 284,80 114,60 124% 
LT 0,00 16,00 0,00 0,00 39,11 30,00 57% 
LU 0,00 5,98 0,00 0,00 11,30 4,93 107% 
LV 0,00 9,00 14,69 0,00 24,64 24,64 163% 
MT 0,00 0,00 0,00 0,00 0,00 0,00 - 
NL 440,00 235,00 153,02 0,00 95,62 300,00 165% 
PL 6,48 59,71 34,20 0,00 147,56 108,00 134% 
PT 0,00 19,30 7,00 14,20 13,21 14,20 105% 
RO 34,30 75,00 25,80 0,00 113,00 102,00 95% 
SE 0,00 6,00 0,60 0,00 8,49 8,49 10% 
SI 0,00 5,80 0,00 0,00 14,53 10,13 76% 
SK 0,30 29,90 34,87 0,00 301,00 301,00 118% 
UK 231,00 536,00 126,57 84,56 241,34 73,70 114% 
*(1-in-20 winter case) 
Source: SEC(2009)979; IHS and Gas Coordination Group  
 
 96 
According to Regulation 994/2010 and the Commissi on preliminary analysis (Annex X), Bulgaria, 
Lithuania, Ireland, Finland, Hungary, Denmark, Roma nia, Sweden and Slovenia did not fulfill the N-1 
rule in 2009. Over the last years, the EEPR pr ogramme accelerated a numbe r of gas infrastructure 
projects that will help those countries to meet th e N-1 standard by the deadline. However, it is 
expected that further measures will be needed fo r Bulgaria, Lithuania, Finland, and Ireland. The 
Regulation allows Sweden, Slovenia and Luxembourg to have a longer timeframe to meet N-1. The 
Regulation allows the Member States flexibility in meeting the N-1 rule - through demand-side 
measures or regional N-1 rule. While the N-1 standa rd ensures the security of gas supply mainly at 
national and partially at regional level, it does not automatically ensure the infrastructure needed to 
enhance market integration or competition in a wider European gas market.123 
5. Other regulatory measures 
Furthermore, tariff setting would remain the excl usive competence of NRAs. Investments in cross-
border infrastructure would continue to be subject  to the same rules, which also govern domestic 
infrastructure investments. This framework will ensu re that cross-border investments go ahead, with 
TSOs sharing costs according to individual agreements  (usually covering all investment cost in their 
own service area) with congestion revenues often split on a 50:50 basis, alth ough other ratios have 
been seen as well124. 
Projects with asymmetric benefits and costs acro ss border however will continue to suffer from the 
absence of a transparen t cost-benefit analysis125 and an effective cost allocation mechanism covering 
all investments beyond those covered under the secur ity of gas supply regulation with regard to 
benefits oriented cost allocation126. Even if multilateral cost sharing agreements could be developed, 
which would be burdensome and on a case-by-case basis only, this would significantly hamper the development of infrastructures of common interest. 
In gas, the open season procedure to assess market de mand would continue to be  used, although, when 
designed along national rules, it will tend to shield incumbents against competition and fail to deliver 
in regions which lack a competitive gas market structure. Today, open seasons are governed by 
voluntary CEER guidelines on best practices, which are currently under revision. The CEER public consultation carried out in 2010 co ncluded that the open season procedures lack transparency and do 
not provide for sufficient efficiency in getting binding commitments
127. 
In electricity, the inter-transmission system operator compensation (ITC) mechanism, which 
compensates TSOs for the cost of hosting transit flows caused by other Member States, would continue to be the only existing pan- European cost allocation mechanism
128. Several limitations to this 
mechanism have however been identified by operators  and regulators. First, the ITC is not designed 
for incentivising new large scale i nvestments in the transmission network, which are needed to meet 
the infrastructure needs identified. Second, th e corresponding fund is capped at 100 million euros, 
constraining its ability for significant redistribution129. Third, the ITC only serves to transfer funds 
from import or export countries to transit c ountries, not for more complex constellations. 
                                                 
123  It will become fully clear how many Member States re quire additional investment to fulfill N-1 in December 2011 
when the risk assessments under Article 9 of the Re gulation are presented by the Competent Authorities. 
124  The Ireland-UK electricity interconnector  will be fully paid by the Irish TS O Eirgrid. France and Luxemburg have 
also agreed on an asymmetric allocation of costs fo r new gas interconnection cap acities at their border. 
125 See Proost et al., 2010, on the merits of cost-benefit analysis for projects of European relevance in the transport 
sector. 
126 Article 6(8) of the security of gas supply regulation alre ady allows for cost-benefit a llocations in case of reverse 
flow investments. 
127  CEER position paper on cost allocation: CEER consu lted in 2009 on the revision of the ERGEG GGP on Open 
Season procedures (GGPOS). The ERGE G Guidelines for Good Practice on Open  Season Procedures (GGPOS), 21 
May 2007. 
128 Regulation 714/2009, article 13 and Commission Regulation 838/2010 
129 Based on load data for 2009 and costs of losses for 2011, th e main contributors to this fund are Italy, Norway, 
Great Britain, France and the Czech Re public, while the main beneficiaries ar e Germany, Switzerland, Sweden and 
Austria (Source: ENTSO-E). 
 
 97 
6. Permit granting framework 
Permit granting for energy infrastructure projects is a Member State competence, with varying rules 
and practices across the EU. Only a few countries ha ve so far passed legislation to address problems 
related to administrative permit granting procedur es and resulting delays. Reforms to introduce "one-
stop shops" and time limits were recently passed in  Ireland, the Netherlands and the United Kingdom, 
resulting in significant reductions in the duration of the process130. In July 2011, the German 
government passed a law for the acceleration of netw ork expansion, which also foresees the creation 
of a "one-stop shop" for planning and permit granting of important electricity infrastructures, to be 
managed by the national regulatory authority. The latte r would also be in charge of fixing time limits 
for each project submitted to the one-stop shop. As of today, time limits for the entire statutory process 
of granting permits exist in 5 Member States (Aus tria, Czech Republic, Greece, Ireland, Italy), while 
10 Member States (Austria, Germany, Greece, Ireland,  Italy, the Netherlands, Poland, Romania, Spain 
and the United Kingdom) have fast-track schemes fo r certain types of infrastructure (see details in 
Annex 7). 
It is expected that such legislation will deliv er improvements in the Member States where it is 
implemented, though leaving untouched probl ems faced in the remaining Member States.  
                                                 
130  Results from a consultation carried out amongst members of ENTSO-E in March 2011. 
 
 98ANNEX 15 
PAST AND FUTURE INFRASTRUCTURE DEVELOPMENT IN THE EU 
 
 
 
Table 13: New EU cross-border electric ity projects realised between 2000 and 2011 
Project Sub-section / routing / 
specification Estimated 
total cost 
(M€) Indicative 
start of 
operations EU grants 1995-
2010 (M€, TEN-E, if 
not otherwise 
stated) 
Vigy (FR) - Uchtelfangen 
(DE) line   N/A 2002 0,23 
Western Pyrenean 
interconnection FR - ES Cantegrit - Mougerre (220kV) 
- (Arkale, ES) N/A 2002   
Kardia (GR) – Elbasan 
(AL) line   N/A 2002   
New connections for the 
Mediterranean Electricity 
Ring Ipiros (GR) - Puglia (IT) N/A 2002   
North-East PT - North-
West ES line Lindoso II (PT) - Cartelle (ES) N/A 2004   
Sines (PT) - Alqueva (PT) 
- Balboa (ES) line   39 2004 0,68 
IT - CH line San Fiorano (IT) - Robbia 
(CH) 77 2005 0,25 
Avelin (FR) - Avelgem 
(BE) line   21,5 2005 1,01 
Reinforcement of the 
connections DK - SE   35 2006   
Submarine cable to link FI 
and EE Estlink cable 110 2006 0,67 
Meliti (GR) - Bitola 
(Former Yugoslav 
Republic Of Macedonia) 
line   5 (for the 
GR side) 2007 0,13 
Eemshaven (NL) - Feda 
(NO) link  NorNed cable 565 2008 8,72 
Békéscsaba (HU) - 
Oradea (RO) Békéscsaba (HU) - Nadab 
(RO) - Arad (HU) 18,5 2008 2,02 
Philippi (GR) - Hamidabad 
(TR) line   70 2008 0,55 
Dürnrohr (AT) - Slavetice 
(CZ) line   9 2008   
New connections between 
GR, AL, BG and FYROM Stip (FYROM) – C. Mogila 
(BG) 50 2009   
New connections for the 
Mediterranean Electricity 
Ring   55 2009   
Pécs (HU) - Ernestinovo 
(HR)   43,6 2010 2,24 
New connection mid SE - 
mid NO   66 2010 0,06 
Moulaine (FR) - Aubange 
(BE) line   11  (FR) 2010 0,50 
 
 99South PT - South-West 
ES Portimão (PT) - Tavira (PT) - 
P. Gusman (ES) - Guillena 
(ES) line and Tavira facilities 
 90,9 2011 50 (EEPR) 
Connection between IE 
and Northern Ireland (UK) 400 kV North South 
Interconnector 
(Tyrone – Cavan) N/A 2011 0,60 
Valdigem (PT) - Douro 
Internacional (PT) - 
Aldeadavila (ES) line and 
facilities 400 kV Douro interconnection 
Aldeadávila (ES) - Lagoaça 
(PT) 88 2011 51,808 (of which 
50 EEPR) 
Submarine cable South-
Eastern UK - central NL BritNed cable (Isle of Grain in 
Kent (UK) - Maasvlakte (NL)) 600 2011 12,75 
Connection north of the 
Gulf of Bothnia (FI) - SE Fennoscan cable 300 2011 0,75 
 
Source: ENTSO-E, European Commission DG Energy, 2011 
 
  
Table 14: Planned transboundary electricity projects (new lines and upgrades) in the 2010 
TYNDP for the period 2011-2025 
Important disclaimer:
 This list is a compilation of project s as provided by ENTSO-E members and 
provided for information purposes only. It does no t prejudge any future selection of projects of 
common interest. 
Border Project characteristics Connection 
type Length of 
Infrastructure 
line [km] 
AL-ME New 400kV line Tirana (AL)-Podgorica (ME) with length 157km (128.5km 
on Albanian side, 76km of which w ith double circuit and 28.5km on the 
Montenegrin side). new lines 157 
AL-RS New 238km 400kV OHL; on 78km the circuit will be installed on the same 
towers as the Tirana-Podgorica OHL cu rrently in construction (see project 
233); the rest will be built as single circuit line. new lines 238 
AT-HU Installation of the 2nd circuit on the existing interconnection from Wien SO 
(AT, APG) to the border (both circuits  have already been installed on the 
Hungarian side, one is connected to Györ and the 2nd circuit to 
Szombathely). Line length: 63km. new lines 63 
AT-IT New double circuit 400kV interconnection through the pilot tunnel of the 
planned Brenner Base Tunne l. Total line length: 65km. new lines 65 
AT-IT The project foresees the rec onstruction of the existing 220kV-
interconnection line as 380kV-line on an optimized route to minimize the 
environmental impact.Total length should be in the range of 100-150km. upgrade of 
existing 
lines 125 
AT-IT New 380/220kV substation in AT directly  located near the border ; erection 
of a 24km single circuit 220kV-conn ection via OHL and underground cable 
till Graun (IT) and upgrade of the existing line Graun (IT) – Glorenza (IT).  upgrade of 
existing 
lines 24 
AT-IT  Upgrade of  the existing 44km Prati di  Vizze (IT) – Steinach (AT) single 
circuit 110/132kV OHL, currently operated at medium voltage and installing 
a 110kV/132kV PST in Steinach (AT). upgrade of 
existing 
lines 44 
BA-HR New 400kV interconnection line betw een existing stations. new lines 50* 
BA-HR Connection of new generator on existing line 220kV Mraclin (HR) - Prijedor 
(BA) via a new double circuit OHL. Line length: 12km. new lines 12 
BA-HR Re-establishment of previously existing 220kV double circuit 
interconnection Trebinje(BA)-P lat(HR); Total length 10km. upgrade of 
existing 
lines 10 
BA-ME New 400kV transmission line between existing stations. Li ne length: 70km. new lines 70 
BG-GR  New interconnection line BG-GR by a 130km single circuit 400kV OHL. new lines 130 
BG-RO New 400kV double circuit OHL to accomm odate RES generation. Line new lines 10 
 
 100Border Project characteristics Connection 
type Length of 
Infrastructure 
line [km] 
length: 2x10km. 
CH-IT New 400kV tie line between It aly and Switzerland. new lines 70* 
CZ-AT Possible increase of interconnection capacity between CEPS and 50Hertz 
Transmission is under consideration: either a new 400kV tie-line (OHL on 
new route) or a reinforcement of the existing 400kV tie-line Hradec (CEPS) 
– Röhrsdorf (50Hertz Transmission).  upgrade of 
existing 
lines 120* 
CZ-DE New 400kV single circuit tie-line betwee n new (CZ) substation and existing 
(DE) substation. Length: 70km. new lines 70 
DE-AT New 400kV double circuit OHL Isar - St. Peter including new 400kV 
switchgears Altheim, Simbach and St. Peter and one new 400/230kV 
transformer in substation A ltheim. Line length: 90km. new lines 90 
DE-AT-
CH Construction of new lines, extension of existing ones and erection of 
400/220/110kV-substation.  upgrade of 
existing 
lines 100* 
DE-BE Connection between Germany and Belgium including new 100km 
underground cable and extension of existing 380kV-substations.  new lines 100 
DE-FR Change of conductors on the German pa rt of this single circuit 225kV line 
(9km) and installation of a phase-shif ter in Ensdorf (DE) 225kV substation. upgrade of 
existing 
lines 9 
DE-NL New 400kV line double circuit DE-NL inte rconnection linew. Length: 60km. new lines 60 
DE-PL This project is the 3rd 400kV double circuit OHL interconnection between 
Poland (Plewiska) and Germany (Eisenhüt tenstadt) with reinforcement of the 
Polish internal grid. Tota l length is 252km, 242km of which being in Poland. new lines 252 
DE-PL This project is the conversion of ex isting 220kV double circuit line Krajnik 
(PSE Operator) - Vierraden (50Hertz Transmission) into a 400kV line 
together with installation of phase shifting transformers in Krajnik (PSE 
Operator) and Miku łowa (PSE Operator). upgrade of 
existing 
lines 600* 
DK-DE The Kriegers Flak project is the ne w subsea cable multiterminal connection 
between Denmark, Sweden and German y used for both grid connection of 
offshore wind farms Kriegers Flak and interconnection. T echnical features 
still have to be determined. new lines 160* 
DK-DE Installation of two PSTs. This project is in the framework of step 2 in the 
Danish-German agreement to upgrade th e Jutland-DE transfer capacity; This 
step includes also planed strengthening of existing 380kV lines in the grid of 
TPS and Energinet.dk . upgrade of 
existing 
lines 40* 
DK-DE Step 3 in the Danish-German agreemen t to upgrade the Jutland-DE transfer 
capacity. It consists of  partially an upgrade of  existing 400kV line and 
partially a new 400kV route in Denmark. In Germany new 400kV line 
mainly in the trace of a existing 220kV line. The total length of this OHL is 
114km. upgrade of 
existing 
lines 114 
DK-NL COBRA: New single circuit HVDC connection between Jutland and the 
Netherlands via 350km subsea cable; th e DC voltage will be up to 450kVand 
the capacity 600-700MW. new lines 350 
DK-NO Skagerak 4: 4th HVDC connection between Southern Norway and Western 
Danmark, built in para llel with the existing 3 HVDC cables; new 700MW 
including 230km 500kV DC subsea cable. new lines 230 
EE-FI A new HVDC (450kV) connection will be built between Estonia and 
Finland. On the Finnish side, a 14km DC overhead line will be built to a new 
substation Anttila where the converter station will be placed. On the Estonian 
side, a 11km DC cable line will be built to a existi ng substation Püssi where 
the converter station will be placed . Length of marine cable is 140km. 
Expected capacity: 650MW. new lines 165 
EE-LT Latvian-Estonian third interconnecti on will consist of OHL Harku-Sindi-
Lihula in Estonian part, OHL Imanta -Tume-Dundaga-Vents pils in Latvian 
part, and sea cable between cross-border DC ar AC cable. Final 
interconnection type and final interc onnection and transmission line route 
will be selected in middle of 2010. At present three alternative route variants 
researched. Final interconnection le ngth, DC voltage and transmission 
capacity will be selected in feasibility and technical study in the middle of 
2010. The connection would be as a new single circuit line mixed 
(OHL+subsea cable) up to 500kV. new lines 380* 
 
 101Border Project characteristics Connection 
type Length of 
Infrastructure 
line [km] 
ES-FR New HVDC (VSC) bipolar interconnection in  the Eastern part of the border, 
via +/- 320kV DC underground cable usi ng existing infrastructures corridors 
and converters in both ending points. Th e thermal capacity is expected in the 
range 2x825-2x1000MW. Total line length: 60km. new lines 60 
ES-FR New cross-border line - not in the French department "Pyrenees Orientales" 
nor in the Spanish region of Cataluña. new lines 60* 
ES-PT New Duero Interconnection 400kVNe w 400kV OHL interconnection line 
Aldeadávila (ES) - Lagoaça (PT) , including new Lagoaça substation (PT). 
Also associated, the lines Lagoaça- Armamar-Recarei 400kV in PT and the 
Armamar (PT) 400/220kV substation. On a first phase (2009) a new 
400/220kV substation (Lagoaça - PT) will  be created with  only 220kV level 
installed, and there will be some rearrangements and reinforcements on the 
local 220kV network structure. On river crossing a new 220kV double line 
with separated circuits, firstly Aldead avila (ES) - Lagoaça (PT) 1 & 2 and 
changing later to Aldeadavila (ES) - Pocinho (PT) 1 & 2, will substitute the 
existing two 220kV lines Aldeadav ila (ES) – Bemposta (PT) and 
Aldeadavila (ES)-Pocinho (PT). To tal length: 1km (ES)+105km (PT). new lines 106 
ES-PT New Southern Interconnection  
New 400kV OHL double-circuit line between Guillena (ES)-Puebla de 
Guzman (ES) - Tavira (PT) - Portimão  (PT), including new Tavira (PT) and 
P.Guzman (ES) 400kV substations. On the interconnection section 
P.Guzmán (ES) –Tavira(PT), initially only one circuit will be placed. Total 
length: 153km (ES)+110km(PT). new lines 263 
ES-PT New double circuit 400kV OHL between O Boboras (ES) -O Covelo (ES) - 
Vila Fria (PT) - Vila do Conde (P T) - Recarei (PT), including new 400kV 
subestations O Covelo (ES), Boboras (E S), Vila Fria (PT) and Vila do Conde 
(PT). 
On the section O Covelo (ES) – Vila do  Conde (PT), only one  circuit will be 
placed.           Total length: 43km (ES)+112km (PT).  new lines 155 
FI-SE A new 500kV HVDC connection will be bui lt in parallel with the existing 
one between Finland and Sweden. On  the Swedish side, a 70km direct 
current overhead line will be built to a new substation Finnböle where the 
converter station will be  placed. Total length of line: 300km and capacity: 
800MW. new lines 300 
FI-SE Third single circuit 400kV AC OHL between Sweden and Finland. Expected 
capacity: 1850 MVA. new lines 100* 
FR-BE to be determined. new lines 50 
FR-BE Installation of a second circuit on the existing 225kV cross-border OHL. upgrade of 
existing 
lines 30* 
FR-CH Reinforcement of the interconnection in the area of Geneva's lake. upgrade of 
existing 
lines 60* 
FR-IT "Savoie - Piémont" Project : 
New 190km HVDC (VSC) interconnecti on FR-IT via underground cable and 
converter stations at both ends (t wo poles, each of them with 500MW 
capacity). The cables will be laid in the security gallery of the Frejus 
motorway tunnel and possibly also al ong the existing motorways' right-of-
way. new lines 190 
FR-IT Replacement of conductors (by ACCS) on Albertville (FR) - Montagny (FR) 
- Cornier (FR) and Albertville (FR) - La Coche (FR) - La Praz (FR) single 
circuit 400kV OHLs. Overcoming of cons traints of Villarodin (FR) - Venaus 
(IT) - Piossasco (IT) single circuit 400kV  OHLs. In addition, change of 
conductors and operation at 400kV of  an existing single circuit OHL 
between Grande Ile and Albertville (FR)  currently operated at lower voltage, 
and associated works in Albertville (F R) 400kV substation. (Total length of 
lines: 257km : French side 66+95+41 Italian side 55). upgrade of 
existing 
lines 459 
FR-LU Connection of SOTEL (industrial grid in LU) to RTE network by mixed 
(underground cable & OHL) single circuit 225kV line. 
Parts of the new line use existing ones. new lines 30* 
FR-UK New subsea DC link, between GB a nd FR, possibly with a capacity of 
1000MW (still to be determined). new lines 90* 
GR-IT Second 500MW HVDC link between Greece  and Italy via 316km 400kVDC new lines 316 
 
 102Border Project characteristics Connection 
type Length of 
Infrastructure 
line [km] 
subsea cable and converters st ations at both ends.  
IE-UK A new 260km HVDC (380kV DC) underground and subsea connection 
between Ireland and Britain with 500MW capacity. On the Irish side, a 45km 
direct current underground cable will be built to the Woodland substation 
where the VSC converter station will be placed. The link will consist of two 
identical circuits. new lines 260 
IE-UK A new 80km single circuit 400kV 1500MVA OHL from a new Moyhill 
400/220kV substation in Ireland to a new Turleenan 400/275kV substation in 
Northern Ireland. This project is an integral part of the new interconnection 
project Moyhill- Wooodland between Ireland and Northern Ireland.  new lines 80 
IE-UK Strengthening of EHV networks (partial uprate and new) into Donegal and 
West of Northern Ireland and enhanced  links between the two systems.  upgrade of 
existing 
lines 50* 
IT-AL  500MW single pole HVDC Merchant Line between Italy and Albania via 
290km 400kV DC subsea cable and converter staitons at both ends. On the 
Italian side, the new line will be conne cted to the existing substation of 
Brindisi South. new lines 290 
IT-HR New 1000MW HVDC interconnection line  between Italy and Croatia via 
280km 500kVDC subsea cable a nd converters stations at both ending points. new lines 280 
IT-ME New 1000MW HVDC interconnection line  between Italy and Montenegro 
via 375km 500kV DC subsea cable and c onverter stations at both ending 
points. new lines 375 
LT-LV Upgrade single circuit OHL (943 MVA, 50km). upgrade of 
existing 
lines 50 
LT-SE (NordBalt) A new 300kV HVDC VSC partly subsea and partly undergroud 
cable between Lithuania and Sweden. (440km). new lines 440 
LU-BE New interconnection between Creos grid in LU and ELIA grid in BE via a 
16km double circuit 225kV underground cable with a capacity of 1000 
MVA. new lines 16 
MK-AL New 200km cross-border single circ uit 400kV OHL between existing 
substations. new lines 200 
n.a. Installation of an additional transfor mer + replacement of an existing one 
(400/110kV and 220/110kV) and shunt reactors in substations, upgrading 
and decommissioning of substations. substation 
ugrade  1 
NO-DE Nord.Link: A new HVDC connection between Southern Norway and 
Northern Germany. Estimated subs ea cable length: 520 - 600km. Capacity: 
700 - 1400MW. new lines 560 
NO-FI New single circuit 400kV OHL (500km, 1850 MVA). new lines 500 
NO-NL NorNed 2: a 2nd HVDC connection be tween Norway and The Netherlands 
via 570km 450kV DC subsea cable with 700 - 1400MW capacity. new lines 570 
NO-SE "South West link" 
consisting of three main parts: 
1) New 400kV line between Hallsberg and Barkeryd 
2) New double HVDC VSC underground cable line between Barkeryd and 
Hurva 
3) New HVDC VSC line between Ba rkeryd and Tveiten/Norway.  
The project also include new substati ons and converter stations in the 
connection points line  
double circuit new OHL Hallsberg - Barkeryd 170km, underground VSC 
Barkeryd - Hurva 250km and VSC Barkeryd - Tveiten with 103km on the 
Norwegian side. Expected capacity: 1200MW. new lines 523 
NO-SE  A joint Stattnett & Svenska Kraftnat study north - south reinforcement (AC 
or VSC), expected length: 400 - 500km under study. upgrade of 
existing 
lines 450 
NO-UK A new 1400MW HVDC bipolar installatio n connecting Western Norway and 
the UK via 800km subsea cable; DC vo ltage is to be determined. new lines 800 
PL-LT Construction of a new 400kV OHL E łk to PL-LT border. (2x1870 MVA, 
108km). new lines 108 
PL-LT Construction of Back-to-Back conve rtor station near Alytus 330kV 
substation. Construction of double ci rcuit 400kV OHL between Alytus and 
PL-LT border. Construction of 330kV AC line Alytus-Kruonis. Length of new lines 46 
 
 103Border Project characteristics Connection 
type Length of 
Infrastructure 
line [km] 
line: 46km. 
PL-UA Establish existing 750kV interconn ection between Poland and Ukraine. 
Mode of operation on border lines (synchronous/asynchronous) depends on 
results of future study concerning possibility of synchronous connection of 
Ukraine and Moldova to continental pa rt of ENTSO-E and bilateral Polish - 
Ukrainian agreement. upgrade of 
existing 
lines 430* 
RO-MO New 400kV transmission line between ex isting station in Romania and new 
substation in Moldavia. Line length: 145km.  new lines 145 
RO-TR New DC link (subsea cable) between exis ting stations in RO and TR. Line 
length: 400km. new lines 400 
RS-MK New 220km 400kV single circuit overhea d interconnection between Serbia 
and FYROM. A new 400/110 substation w ill be built in Serbia between 
connection nodes. new lines 220 
RS-MK A new 400kV OHL releavant to planning  investment of 2000MW of TPP in 
the area of Kosovo and Metohija. Line length: 85km. new lines 85 
RS-RO New 150km double circuit (single wi red at the beginning) 400kV OHL 
between existing substations.  new lines 150 
SI-HU-
HR The existing substation of Cirkovce (SI) will be conn ected to one circuit of 
the existing Heviz (HU) -Zerjavinec (HR) double circuit 400kV OHL by 
erecting a new 80km double circuit 400kV  OHL in Slovenia. The project 
will result in two new cross-border circuits: Heviz (HU) - Cirkovce (SI) and 
Cirkovce (SI) - Žerjavenec (HR).  new lines 80 
SI-IT New 120km double-circuit 400kV OHL with installation of a PST in 
Okroglo. The thermal rating will be 1500 MVA per circuit. new lines 120 
SK-AT-
HU SEPS and MAVIR consider a new in terconnection between SK and HU 
(starting from Gab číkovo substation - SK) and a connection to the existing 
400kV tie-line Györ/Szombathely (HU) - Vienna/Sarasdorf (AT) on 
Hungarian side.  new lines 30* 
TU-IT New 350km 500MW HVDC line between Tuni sia and Italy via Sicily with 
400kV DC subsea cable and conver ters stations at both ends. new lines 350 
UK-BE Nemo project: new DC sea link incl uding 135km of 250kV DC subsea cable 
with 1000MW capacity. new lines 135 
UK-NL  New 1290MW HVDC bipolar installation including 260km of 450kV DC 
subsea cable.  new lines 260 
* Commission estimation of length 
 
 104Table 15: New gas infrastructure realised between 2000 and 2011 
Inauguration / 
start of 
operations New interconnectors TEN-E / EEPR support (in 
Million Euro) 
2006 BBL (UK-BE)*  - 
2011  OPAL DE-CZ* - 
2011 PL-CZ 14 
2010 HU-HR 20 
2010 RO-HU 16.6 
 New LNG Terminals  
2009 Dragon LNG Terminal* - 
2010 South Hook LNG Terminal* - 
2009 North Adriatic LNG Terminal (Rovigo)* - 
2011 Gate LNG Terminal Rotterdam* - 
2005 Grain LNG Terminal NCG* - 
2010 Fos-Cavau - 
2003 Sines 0.9 
2003 Bilbao - 
2006 Sagunto - 
2007 Mugardos - 
 New import pipelines  
March 2011 Medgaz (Algeria-Spain) 2  
2011  Nord Stream (Russia-Germany) - 
2006 Langeled (Norway-UK) - 
2005 Greenstream (Libya-Italy) - 
   
 Storages developed since 2008 TEN-E support not specified 
as country approach 
January 2007 AT  
June 2008  AT, DK, FR, DE, IT, ES  
February 2009 AT, DK, FR, DE, IT, ES, UK  
January 2010 AT, BE, CZ, DK, FR, DE, HU, IT, ES, UK  
* Exemption obtained  
 
Source: GLE Investment database 2010; GSE Investment database 2008-2010; ENTSOG TYNDP 
2011; European Commission DG Energy, 2011. 
 
 105Figure 19: Gas storage investments in selected Member States between 2007 and 2010 
 
Source: GSE 
 
 
Figure 20: Gas storages developed in selected Member States since 2008 
 
Source: GSE 020040060080010001200140016001800
AUSTRIA
BELGIUMBULGARIA
CZECH REPUBLIC
DENMARK
FRANCE
GERMANY
HUNGARYITALYLATVIA
LITHUANIA
NETHERLANDS
POLAND
PORTUGAL
ROMANIA
SERBIA
SPAINUKMcmJan-08
Jun-08
Feb-09
Jan-1005000100001500020000
AUSTRIA
BELGIUM
BULGARIA
CZECH REPUBLIC
DENMARK
FRANCE
GERMANY
HUNGARY
ITALYLATVIA
LITHUANIA
NETHERLANDSPOLAND
PORTUGAL
ROMANIA
SERBIA
SPAIN UKMcmJul-07
Jan-08
Jun-08
Feb-09
Jan-10
 
 106Table 16: Aggregates of cost estimates for gas TYNDP 2011-2020 
Infrastructure type Number of 
projects Aggregate Cost 
Estimate for 
infrastructure 
investment (in €10^6) 
 Remarks 
Transmission projects – 
FID 62 13,711  
Storage projects – FID 26 4,260  Some projects missing 
from the estimate, see below for more detailed 
information 
LNG projects – FID 11 3,570  
Transmission projects – 
Non-FID 97 58,556  
Storage projects – Non-
FID 22 2,593 Some projects missing 
from the estimate, see 
below for more detailed 
information 
LNG projects – Non-FID 20 6,614 Some projects missing 
from the estimate, see below for more detailed information 
Subtotal FID projects 99 21,514   
Subtotal Non-FID 
projects 139 67,763  
TOTAL 238 89,304  
    
 
Source: ENTSOG TYNDP 2011 
 
 107Figure 21: Past (2005-2009) and planned future (2010-2020) TSO investments: operators' 
perspective 
 
Source: Roland Berger, 2011 
 
 
Figure 22: Past (1995-2009) and planned future ( 2010-2020) investments for selected electricity 
TSOs in Europe (EUR bn per year) 
 
Source: Roland Berger, 2011 
 
 108Figure 23: Past (2005-2009) and planned future ( 2010-2020) investments for natural gas 
TSOs in Europe by region (EUR bn per year) 
 
Source: Roland Berger 
 
 109Figure 24: ENTSO-E analysis of main electricity transmission bottlenecks up to 2020 
 
 
 
Source: ENTSO-E 2011 (preliminary analysis) 
 
NB.: Arrows do not represent any projects, but only show the direction of main power flows. 
 
 110Figure 25: Main gas transmission capacity reinf orcement needs for 2015 and 2020 as identified 
by ENTSOG (scenario analysis "security of supply")  
 
 
Source: ENTSO-G, TYNDP 2011 
 
 111ANNEX 16 
EVALUATION OF SUBOPTIONS WITH REGARD TO PERMIT GRANTING AND PUBLIC 
CONSULTATION  
 
 
 
Element A.2.1 Organisation of the permit granting process 
 
Suboption A.2.1.a : Leading Authority without decision-making power at national level (“light 
one-stop shop”)  
Assessment of effectiveness 
Since the Leading Authority is not entitled to take the final administrative decision it is expected that 
the lack of managerial authority and final responsib ility will not allow the Leading Authority to drive 
the entire process significantly forwar d. Effectiveness is expected to be limited as multiple procedures 
and permits implying double work and friction losses w ould continue to exist. In some countries with 
federal structures, such as Germany and Austria, th e Leading Authority would constitute an additional 
layer, as coordination (and decision-making) compet ence would remain with multiple institutions at 
federal state level.  
Assessment of feasibility – le gal implications in MS 
A slight adaptation of national legislation may be  necessary in MS where a “one-stop shop”-approach 
is not in place, as coordination tasks may have to  be (re)assigned.  However, the overall permitting 
framework would not need to be modified and th e competences of other authorities concerned would 
not be affected by these measures.  
Assessment of proportionality 
This suboption is considered to be in line with  the principle of proportionality as planning and 
decision-making competence would be entirely left to the MS concerned, and MS would not be 
obliged to adapt their existing permitting framework. 
 
Suboption A.2.1.b: Leading Authority with decision-making power at national level (“full one-stop shop”) 
Assessment of effectiveness 
Effectiveness is expected to be significant if a full one-stop shop with decision-making power is 
established at national level in each MS. The Leadi ng Authority would throu gh its responsibility to 
take the final decision have the managerial power to effectively streamline and reduce the complexity 
of the process. The number of interfaces would be reduced for the project promoter and concentrated 
within one authority, such that information lo sses and double work can be prevented. Since the 
Leading Authority has been involved in the operatio nal handling of the procedure it would be able to 
take an informed decision if required, if needed with  support of external expertise. This is expected to 
have positive effects on the duration of the overall pe rmitting process. In the Netherlands for instance, 
the one-stop shop as main feature of the new permit ting regime has resulted in the reduction of the 
entire process from an average of 10-15 years to 6 years (including realisation of about 2 years), 
whereas in some other countries where loose coordination mechanisms such as under suboption 
A.2.1.b exist, procedures take on average more than 8 years. Table 17 shows that in countries where a 
full one-stop shop exists, the duration of the pe rmitting process tends to be shorter. In terms of 
compliance and administrative costs, this subopti on is expected to be more cost-effective than 
suboption A.2.1.a, if a coordinated approach is chosen. The administrative structures and thus the need 
for adaptation of national legislation, i.e. complianc e costs, would be similar under both suboptions, in 
that responsibility would have to be allocated to  the Leading Authority. However, under this 
suboption, the Leading Authority could take a fi nal decision, avoid delays, and thereby reduce 
administrative costs spent on handling the procedures. It would not only have an impact on administrative costs, but also reduce the foregone lo sses due to the missing infrastructure. In general, it 
 
 112should be noted that the costs related to the intr oduction of these measures are minor compared to the 
costs imposed on society as a whole if the infrastructure is not built on time. 
 
Assessment of feasibility – le gal implications in MS 
Adaptation of national legislation may be extens ive for this suboption if full responsibility for 
decision-making is chosen to be (re)assigned, and a wide range of laws can,  depending on the MS and 
the legislation in place, be concerned. The more fragmented the process is, the more adaptation of 
national legislation is expected to be necessary. Howe ver, the need for adaption is expected to be less 
significant if authorities involved in the process re tain their competences and the Leading Authority 
only steps in case of duly justified reasons. Feasibilit y of this suboption has been proved in those MS 
where full-one-stops with integrated procedures have  been established, such as in the Netherlands, the 
UK, Italy etc. as legal requirements in terms of environmental and other procedures are fully respected in these MS. Respect of requirements in place is inherent to the permit granting process as authorities 
have to ensure that permits can withstand judicial reviews. 
 
Assessment of proportionality 
This suboption is considered to be in line with the principle of proportionality, as MS would be free to 
choose and establish their competent authority by a target date, and as decision-making and planning 
competence would be entirely left to the MS concer ned. Further, since this suboption leaves flexibility 
to the MS to decide whether competent authoriti es retain their competences, the requirements to 
modify the permitting process are limited. These  measures are broad in nature, establishing a 
framework within which MS can carry out the pr ocedures according to the national specificities. 
  Suboption A.2.1.c: Cross-border Leading Authority ("light one-stop shop") with European Authority of Last Resort and European permitting procedure  
Assessment of effectiveness 
This suboption is not considered viable. A cross-border Coordinating Authority will have difficulties 
in reaching the “critical mass” and develop the expe rtise needed, as for most individual cross-border 
projects a new authority would have to be established (each cross-border project may involve different 
countries), and new staff of each of the MS invol ved would have to be assigned each time as staff 
from one MS may not be familiar with language and procedures of another MS. For a European 
Authority of Last Resort, an entirely new procedur e would need to be established, and EU staff does 
currently not have the necessary expertise. Although this expertise may be developed and/or possibly 
subcontracted, in accordance with a new Europ ean permitting procedure, suboption A.2.1.b is 
expected to deliver at least the same or better results in a more timely fashion. 
 
Assessment of feasibility – le gal implications in MS 
Adaptation of national legislation is expected to  be necessary. Coordination competences for PCI 
would have to be assigned to a new authority. Ho wever, adaptation is expected to be limited as 
national authorities would keep their decision-maki ng competences if the time limit is respected. In 
order to establish the Authority of Last Resort at European level and a European permitting procedure, 
adaptation of national legislation is not expected to be necessary.  
Assessment of proportionality 
Both elements of this suboption – the cross-borde r Leading Authority and the European Authority of 
Last Resort – do not leave competences at most appr opriate level. It is exp ected this suboption would 
exceed what is necessary to achieve the objectives, such that this provision is not in line with the 
principle of proportionality.  
Resulting from this analysis, A.2.1.b is the most preferred suboption. 
 
  
 
 113Element A.2.2 Limitation in time of the permit granting process  
 
Suboption A.2.2.a: Requirement for Member States to establish time limits for each individual 
PCI 
Assessment of effectiveness 
Effectiveness of this suboption is expected to be  limited in most Member States. Although individual 
time limits would make it possible to take into acc ount the national specificities of the varying permit 
granting processes, and the different degrees of complex ity of projects, experience has shown that time 
limits without legal consequences in case of their expiry  are relatively ineffective. In the context of the 
public consultations carried out, Member States we re generally supporting the idea of individual time 
limits, however respondents across stakeholder groups,  including Member States, raised the issue of 
consequences in case of expiry. Time limits would only be effective in Member States where certain sanction mechanisms exist, such as the deferral of the decision to a higher level. The EU would not 
have any means to apply any sanctions, as th e legal grounds to do so would not exist. 
 
Assessment of feasibility – le gal implications in MS 
This option would have limited im plications on Member States’ procedural law. In some Member 
States, legislation would need to be adapted to a llow the Competent Authority  to set time limits, or 
general time frames could be introduced by law,  based on which the Competent Authority would act. 
 Assessment of subsidiarity and proportionality 
As this option leaves substantial flexibility to Member  States in defining time limits, it is considered to 
be in line with the principle of subsidiarity and proportionality.   
 
Suboption A.2.2.b: Legally-binding time limits es tablished by stakeholders in the framework of 
the regional fora  Assessment of effectiveness 
Effectiveness of this suboption is expected to be limited as implementa tion would be difficult. 
Although the "ownership" of the decision on a legally-b inding time limit is expected to have positive 
effects on its acceptance and could accommodate the complexities of each individual project, 
experience with working groups in regional fora an d consultation of MS i nvolved have shown that 
discussions within these groups are lengthy and consensus difficult to achieve. Although some 
Member States have expressed their support to such idea, those which have been involved in existing 
regional fora opposed this option as too cumbersome. Even if consensus is found, a legally-binding 
time limit can only be established through an intergove rnmental agreement, w hose signature by Heads 
of State would require additional resources and time.  
Assessment of feasibility – le gal implications in MS 
Adaptation of national legislation would not be  necessary under this suboption as intergovernmental 
agreements as the legal basis would be elaborated for a given PCI. 
 
Assessment of subsidiarity and proportionality 
As this suboption leaves the definiti on of legally-binding time limits to the MS affected, this suboption 
is considered to be in line with  the principle of proportionality. 
 Suboption A.2.2.c: Legally-binding time limit established by the EU legislative act  
 
Assessment of effectiveness 
This suboption is considered to have significant effects on the duration of the permit granting process. 
Legally-binding time limits are crucial to incentivise promoters and authorities to complete the permit 
granting process in a timely fashion, and for sanction m echanisms to kick in at EU level if considered 
appropriate and justified. As men tioned above, an issue raised in th e context of the public consultation 
carried out was the consequences if a time limit e xpires. Possibilities identified were the automatic 
 
 114approval or rejection of the project. However, this is  considered as a non-viable option, such that other 
mechanisms to sanction the expiry of a time limit should apply. The de finition of time limits under the 
legislative act would create the legal grounds fo r the EU to apply sanctions, which are, across 
stakeholder groups, considered as crucial to enforc e time limits. This s uboption would be without 
prejudice to the time limits established for the st atutory permit granting process in some MS which 
are, according to the analysis carried out, shorter in duration, thus not creating any adverse incentives. 
Further, Leading Authorities are free to identify indi vidual time limits for the different stages of the 
project by elaborating a permit granting schedule fo r a given PCI. The Leading Authority's decision-
making power at national level constitutes an add itional effective enforcement mechanism if other 
competent authorities involved in the pro cess do not issue the required permits on time. 
 A two-step approach has been id entified as most effective to achieve the timely delivery of 
infrastructure investments, addressing both promoters and authorities. A one year time limit would be 
established for the statutory permitting procedure fo r which the competent authorities are responsible, 
notably from the acceptance of the submitted docum ents until the final administrative decision is 
taken. However, this one year time limit would not take into account the signi ficant efforts needed for 
the preparation of application documents for wh ich the project promoter is responsible nor 
administrative procedures which do not result in a legally-binding permit (such as spatial planning 
procedures and public debates). Further, it woul d not incentivise the authorities to reduce delays 
between the submission of application documents by the promoter and the acceptance of these by the 
authorities, which is a challenge in some MS wher e time limits for (part of) the official permitting 
procedure are defined, but where authorities postpon e the acceptance of documents to gain time. A 
three years time limit would therefore be established to accommodate time consuming pre-application efforts. Respecting the fact that delays may be  caused by promoters and/or authorities and that 
unforeseen external factors may influence the process,  discretionary margin is left to the Commission 
at what point and in which form sanction mechan isms (reporting, withdrawal of financial support, 
infringement procedures) are applied.  
Assessment of feasibility – le gal implications in MS 
Under this suboption, no major adaptation of nati onal legislation is expected to be necessary. 
According to the analysis carried out, a one year ti me limit for the statutory administrative procedure 
exceeds the time limit established by legislation (in MS where these are defined). Legally-binding time limits for pre-application efforts are usua lly only established for individual steps of the 
procedure, such that these can be well-accommodated by the overall time limit.  Assessment of subsidiarity and proportionality 
During public and stakeholder consultations (mainl y) Member States were raising the issue of 
subsidiarity and advocated that time  limits should be set at national level. Some Memb er States stated 
that EU measures should not prevent th em to take more ambitious action. 
This suboptions would take account of the concerns raised by the Me mber States, as they may define 
their individual time limits for the overall proce dure, whose ambitions may exceed those set by the 
legislative act, and establish individual target durations  for the different steps of the procedure, thereby 
respecting the principle of setting broad measures, l eaving the individual steps in the procedure to the 
MS. The time limit set by the legislative act woul d well accommodate the time needed to carry out 
public consultations, which usually have a duration of 4-8 weeks. The time needed for environmental 
assessments can also be well integrated. As concluded by a study, an EIA decision takes less than one 
year from the moment of notification of the project until the final decision is taken. No major changes 
of procedural law are, as explained above, considered  necessary, such that this  option is considered in 
line with the principle of proportionality and subsidiarity.  
Resulting from this analysis, A.2.2.b is the most preferred suboption. 
 
 115Table 17: Summary of impacts 
 
Suboption Effectiveness Legal imp lications Proportionality Overall 
evaluation
A.2.1.a – light 
one-stop shop 0 limited 
effectiveness as no decision-making competence + light adaptation of 
national legislation if assigned to existing institution Y coordination and 
decision-making competence at MS level 0 
A.2.1.b – full 
one-stop shop ++ strong 
effectiveness as decision-making competence can drive procedure forward, 
reduced complexity 0 moderate adaptation 
of national legislation if authorities continue to issue draft permits and if responsibilities 
are assigned to an 
existing institution Y coordination and 
decision-making at MS level ++ 
A.2.1.c – 
Cross-border coordination with 
European 
ALR - low effectiveness 
due to insufficient expertise cross-border and at EU level 0 moderate adaptation 
of national legislation 
for cross-border 
component, for ALR 
EU legislation N coordination and 
decision making at regional/EU level - -  
 
Suboption Effectiveness Legal imp lications Proportionality Overall 
evaluation 
A.2.2.a: 
Legally-binding time limits established by 
stakeholders in 
the framework of the regional initiatives - limited effectiveness  
as joint agreements on legally-binding target durations are difficult to achieve and entail 
additional procedures 0 intergovernmental 
agreements to be signed Y MS are free to 
agree on individual time limits - 
Suboption 
A.2.2.b: 
Legally-
binding time limit of 4 years established by the EU 
legislative act ++ strong 
effectiveness with full 
one-stop shop. 
Precondition to apply adequate sanction mechanisms at EU level. ++ no adaptations 
expected to be 
necessary Y MS are free to 
set more ambitious 
time limits for the 
overall procedure as well as to define time limits for individual 
steps in the 
process ++ 
 
 116ANNEX 17 
CHALLENGES AND CORRESPONDING MEASURES PROPOSED  
FOR PERMIT GRANTING AND PUBLIC INVOLVEMENT  
 
 
 Problems related to different phases of the process 
 Phase B Phase C Phase D Proposed solutions 
 for improvement 
 
Complex and fragmented process  One-stop shop , including 
obligation to coordinate and control the process 
Lack of upfront planning and 
coordination  One-stop shop , particularly the 
obligation to elaborate a  permit 
granting schedule , to handle 
consultation procedures , and to 
carry out scoping activities  
Lack of time limits/ long duration Legally-binding overall time 
limit , together with sanction 
mechanisms  to enforce time 
limits (infringements, reporting), 
and the obligation of the one-stop shop to control the process, based on a permit granting 
schedule  
Unclear 
documentation 
standards and lack of quality   One-stop shop  to carry out 
scoping activities  and 
coordinate with other authorities concerned Inefficient administrative process Flexibility of environmental legislation  Granting of the status of 
imperative public overriding 
interest  to ensure that the 
decision about the necessity to 
build a project, decided by Member States during the selection process, cannot be reversed by an authority later in the process 
Objections of citizens One-stop shop  responsible to 
handle consultation procedures 
according to principles set by the legislative act, including early 
consultation  before submission 
of application files, and to issue 
transparency guidelines.  Time 
frame established as 3+1 approach to leave substantial time for promoters and authorities to consult the public 
before decisions are taken. To be 
accompanied by best-practice 
sharing  and communication 
campaigns.   Opposition of affected population 
  Appeals to courts Early consultation  before 
 
 117submission of application for 
better consensus with citizens. 
No legal measure with regard to 
judicial procedures proposed, as not considered in line with subsidiarity. Best-practice 
sharing  and communication 
campaigns . 
 Lengthy negotiations with landowners Early consultation  before 
submission of application for 
consensus with landowners. No legal measure proposed, as not considered in line with subsidiarity. Best-practice 
sharing  and communication 
campaigns.  
 
 
 
 118ANNEX 18 
ADMINISTRATIVE COST ASSESSMENT  
 
 
Introduction  
This administrative cost assessment  analyses the most important changes under each policy option. In 
line with the principle of proportionate analysis , a quantitative analysis was carried out for the 
measures entailing relatively significant impacts on ad ministrative costs, notably the establishment of 
a regime of common European Interest, as well as the introduction of a one-stop shop approach. It 
should however be noted that the policy proposal  does not aim at the reduction of administrative 
burden as such, but at making the realisation of energy infrastructure happen by increasing certainty for investors, with all consequences this entails on security of supply, market integration and the 
deployment of renewable energy.  
 
Methodology
 
In a first step, a number of Member States was identified in which a reorganisation of the permit 
granting regime similar to the proposal subject to th is impact assessment has been carried out, notably 
the Netherlands, Germany (at federa l state level), the UK, and Ireland. 
In a second step, a detailed questionnaire was elaborated, aiming at 
a) Identifying the different activities related to  the main stages of the permitting process, 
b) Capturing the resources spent on these activities based on a reference project, 
c) Comparing the results of a) and b) before and after the reorganisation of the permitting 
process. 
The questionnaires and/or a request for any other in formation available, such as impact assessments 
carried out at national level, were sent to the "one-s top shop" authority as well as to the TSO(s) in the 
respective MS. 
 However, most of the respondents answered that the due to the complexity of such processes, the fact 
that projects vary widely with regard to their comp lexity, and that several projects are handled at the 
same time by a large number of people, it was not po ssible to give such detailed information. Partial 
data was made available by a German TSO as well as a German authority at federal state level on the 
existing regimes, and individual in terviews were subsequently held with some TSOs to give some 
rough estimations on potential savings through the establishment of a national one-stop shop. These 
were used as assumptions in the below calculati ons, which give a relatively good estimate on the 
administrative costs incurred in a permit granti ng process for a large-scale energy infrastructure 
project. It should be noted that due to the lack of complete and detailed data, on ly some features of the 
EU Standard Cost Model
131 could be applied. 
 
Assumptions  
- Measures proposed are implemented by none of the MS. 
- Two responsible authorities132 are involved in the permit granting process (conservative 
assumption). Coordinating and decision-making competence would be allocated to one of these. 
- No impacts on the other authorities involved at local or technical level, as it is assumed that 
they will continue to issue permits/opinions such that these impacts are not taken into 
account
133. 
- Policy option A.1: acceleration of procedures by three months. Staff subsequently working for 
1,5 months on the procedures at promoters' and on authorities' side, with equal distribution of 
                                                 
 
132  Authority responsible to issue a legally-binding permit, concentrating pa rts of the procedure regionally or 
technically 
133  Exception Austria where one-stop shops  at federal state level exist – not  specifically taken into account. 
 
 119work load over the project, and 50% impact on authorities' side (calculations based on data 
sent by respondents: on promoters' side savings  of 820 person-hours; on authorities' side 
savings of 725 person-hours). Possible impact s on litigation processes are not taken into 
account in these calculations, as these will not be subject to the legislative act. 
- Policy option A.2: 25% reduction of resources for the TSO if a one-stop shop at national level 
was established (interviews with TSOs and Impact Assessment UK134), and 34% reduction of 
resources on the authorities' side (Commi ssion's calculations based on activities 
communicated). 
- Labour costs: simple average of labour co sts for the category "professionals" based on 
standardised ESTAT data (four-yearly Labour cost  survey and the annual updates of labour 
costs statistics, covering both wages and non- wage labour costs, reflecting 2006 prices and 
25% overhead costs)135. 
 
                                                 
134  UK Department for Communities and Local Government, "Localism Bill: major infrastructure projects, Impact 
assessment", 2011. 
135  Source: http://adminburden.sg.cec.eu. int/Manuals%20and%20documentati on/080115_FINAL%20tariffs_gross% 
20earnings%20per%20hour%20in%2027%20MS.xls   
 
 120Table 18: Results of the administrative cost assessment 
 
Business as usual 
 Policy options A.1 - A.3 
 
Target 
group Type of 
obligation Description 
of activity Time 
spent 
(hours) Labour 
costs (€ 
per 
hour)* Number 
of 
projects 
(2014-
2010)** Total 
adminis-
trative costs 
in € (BAU) Total 
adminis-
trative costs 
(PO A.1) Change 
in 
percent 
(compa
red to 
BAU)  Total 
adminis-
trative costs 
(PO A.2)  Reduction in 
percent 
(compared to 
BAU)  Total 
adminis-
trative costs 
(PO A.3) Reduction 
in percent 
(compared 
to BAU) 
Preparation 
of 
application  19.508 25,63 150 74.998.506 
Other 
related 
activities 10.280 25,63 150 39.521.460 Promoter Securing 
necessary 
permits 
Total 29.788   114.519.966 111.367.476 -0,03 85.889.975 -0,25 82.737.485 -0,28 
Pre-planning 
activities 64 25,63 150 246.048 
Scoping 96 25,63 150 369.072 
Checking of 
submitted 
documents 240 25,63 150 922.680 
Coordinatio
n with other 
authorities involved 112 25,63 150 430.584 
Public 
consultation 2.480 25,63 150 9.534.360 
Elaboration 
of the permit 2.880 25,63 150 11.072.160 Authority Issuing 
necessary 
permits 
Total  5.872   22.574.904 19.787.642 -0,12 15.012.311 -0,34 12.225.049 -0,46 
Total 
(2014-20) 137.094.870 131.155.118 -0,05 100.902.286 -0,26 94.962.533 -0,31 
*Figures are not discounted
 
 121Remarks on results 
 
It should be noted that these results are based on the relatively conservative assumption that two 
authorities are responsible for the permit granting process under BAU, which are coordinating other technical, regional and/or local authorities and stakeh olders involved. However, this is only one type 
of permitting regime existing in the different MS. Im pacts would be greater if there were, as it is in 
many MS the case, more responsible authorities, or  if the responsible authority was not or only 
partially coordinating other authorities and stakehol ders involved. In the latter case, a shift of 
administrative costs from promoter towards authority  is expected. However, according to the data 
available, in terms of pure coordinative activ ities such as telephone conversations, e-mails and 
meetings, this shift would not account for more th an 2%, as more inefficiences are related to the 
duplication of efforts in the preparation and assessment of application files, and as half of these 
coordinative activities would still have to be pursued by  the promoter, given that technical details need 
to be discussed directly. Shifts of administrative co sts are also expected towards the Leading Authority 
from other responsible authorities. These are expected  to be limited if the MS chooses to implement 
the coordinated approach.   In order to compare the numbers with the figures available in MS
, where such an approach has already 
been implemented, the below table shows the re duction in full time equivalents (FTE) per year. 
 
 Old regime (BAU) New regime (PO A.3)  
Running costs promoter (per 
project) 14.9 10.7 
Running costs authority (per 
project) 2.9 1.6 
 
On the promoters' side, figures are in line with es timations made by one promoter where a one-stop 
shop approach has been introduced: 11 employees ar e working on one project (external contracts not 
taken into account). On the authorities' side, the UK with an integrated permit granting regime, where 
all necessary expertise and decision-making power is with the Leading Authority, has a ratio of 1.9 
employees per project (94 employees for 50 projects), in line with the Commission's estimations. In 
the Netherlands however, a ratio of 0.5 employees pe r project has been estimated. Here, a coordinated 
approach has been implemented, where expertise and decision-making power is mainly left to the 
other authorities involved, such that less resources at the level of the Leading Authority (20 people, 44 
projects) is needed. 
 
 122ANNEX 19 
IMPACT OF A 2%  EQUITY ADDER ON TRANSMISSION TARIFFS  
 
 
 
Denmark
Lithuania
PolandSelected Countries
France
Sweden
Greece
now TimeAfter 10
years
14,6%15,1%
11,5%12,4%
10,0%10,2%
7,4%7,6%
3,6%3,7%
2,1%2,4%+ 0,9 % / 0,07 c/kWh
+ 0,2 % / 0,02 c/kWh
+ 0,2 % / 0,02 c/kWh
+ 0,1 % / 0,01 c/kWh
+ 0,3 % / 0,03 c/kWh+ 0,5% / 0,07 c/kWh15%
10%
5%transmission cost as
% of electricity tariff
 
Source:  Roland Berger, European Commission 
 
Main assumptions: 
− equity share of 30 % for future investments  
− 2 % additional annual revenue on equity  
− other costs constant  
− transmission tariff averaged for house holds and industry (excluding VAT) .