EN  
 EN EN 
EN  
 EN  EUROPEAN COMMISSION 
Brussels, 17.11.2010 
SEC(2010) 1395 final 
  
COMMISSION STAFF WORKING DOCUMENT 
  
IMPACT ASSESSMENT  
 
Accompanying document to the 
  
COMMUNICATION FROM THE CO MMISSION TO THE EUROPEAN 
PARLIAMENT, THE COUNCIL, THE EUROPEAN ECONOMIC AND SOCIAL 
COMMITTEE AND THE COMMI TTEE OF THE REGIONS 
  
Energy infrastructure priori ties for 2020 and beyond -  
A Blueprint for an integrated European energy network 
   
{COM(2010) 677 final} 
{SEC(2010) 1396 final} 
 
 2TABLE OF CONTENTS  
 
Table of contents.............................................................................................................. ........0  
Glossary ....................................................................................................................... ............3  
1. Procedural issues and consultation of interested parties .................................................5  
1.1. Green paper and public consultation........................................................................6  
1.2. Stakeholder consultations.........................................................................................7  
2. Problem definition............................................................................................................. 8 
2.1. A dramatically changed policy context......................................................................8  
2.2. Current TEN-E framework and European Energy Plan for Recovery.......................9  
2.3. Main problems ........................................................................................................10  
2.4. Baseline scenario ...................................................................................................14  
2.4.1.  Energy trends and infrastructure needs..........................................................17  
2.4.2.  Infrastructure delivery under current market, regulatory and financing 
conditions........................................................................................................22  
2.5. Main geographical bottlenecks ...............................................................................24  
2.6. Key players and affected population.......................................................................26  
2.7. EU right to act.........................................................................................................26  
3. Objectives..................................................................................................................... ..27 
4. Policy options ................................................................................................................. 28 
4.1. Policy area A: Scope of policy instrument ..............................................................29  
4.2. Policy area B: Design of policy instrument .............................................................29  
4.3. Policy area C: Coordination....................................................................................30  
4.4. Policy area D: Permitting ........................................................................................31  
5. Analysis of impacts.........................................................................................................32  
5.1. Baseline ("business as usual") ...............................................................................32  
5.2. Policy area A: Scope of policy instrument ..............................................................38  
5.3. Policy area B: Design of policy instrument .............................................................38  
5.4. Policy area C: Coordination....................................................................................39  
5.5. Policy area D: Permitting ........................................................................................39  
6. Comparison of policy options and conclusion ................................................................41  
7. Monitoring and evaluation ..............................................................................................44  
Annex 1: Electricity transmission capacity increases for the period 2010-2015 and 2015-2025
............................................................................................................................... ................46  
Annex 2: Current financing of TEN-E projects .......................................................................47  
Annex 3: E3ME modelling scenarios and results...................................................................48  
Annex 4: Design options for an integrated offshore grid ........................................................53  
 
 
 3GLOSSARY  
 
  AC   Alternating Current 
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 CRE Commission de Régulation de l'En ergie (National Regulatory Authority 
in France) 
DC   Direct Current 
EBRD   European Bank for Reconstruction and Development 
EIA   Environmental Impact Assessment EEPR   European Energy Plan for Recovery EESII   European Energy Security and Infrastructure Instrument 
EIB   European Investment Bank EIP   Energy Infrastructure Package ENPI   European Neighbourhood and Partnership Instrument 
ENTSO-E  European Network of Transmi ssion 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 EU   European Union GDP   Gross Domestic Product GW   Giga Watt ICT    Information and Communication Technology INOGATE European Union programme s upporting internati onal cooperation 
between the EU, the littoral states of the Black and Caspian Seas and 
their neighbouring countries 
IPA   Instrument for Pre-Accession Assistance LNG   Liquefied Natural Gas Mtoe   Million tons of oil equivalent NGO   Non-Governmental Organisation 
 
 4NIF   Neighbourhood Investment Facility 
NSCOGI  North Sea Countries  Offshore Grid Initiative 
OFGEM Office of Gas and Electricity Ma rkets (National Regulatory Authority 
in the UK) 
PEI   Project of European Interest RES   Renewable Energy Sources SME   Small and Medium Enterprises TEN-E   Trans-European Networks for Energy TFEU   Treaty on the Functioning of the European Union TSO   Transmission System Operators TWh   Tera Watt hour TYNDP  Ten-Year Network Development Plan 
UPS Unified Power System (synchronise d power system currently covering 
Russia and the three Baltic States) 
VSC Voltage Source Converter (tec hnology to improve overall system 
performance for both high voltage alte rnating current and direct current 
transmission) 
 
 5 
1. PROCEDURAL ISSUES AND CONSULTATION OF INTERESTED PARTIES  
 
Lead DG: ENER 
Services involved in the Interservice Group: AGRI, AIDCO, BEPA, BUDG, CLIMA, COMP, 
DEV, ECFIN, ELARG, ENTR, ENV, ESTAT, INFSO, JLS, JRC, MARE, MARKT, MOVE REGIO, RELEX, RTD, SANCO, SJ, SG, TRADE, TAXUD 
Reference to Roadmap: 
http://ec.europa.eu/governance/impac t/planned_ia/docs/19_en er_energy_infrastru cture_package_en.pdf  
 
Background: 
 
Europe's future economic growth and stability depend on the availability of appropriate 
energy infrastructure ensuring the achievement  of the EU energy and climate goals, cost-
efficient functioning of the internal energy market and security of supply. In 1996, as part of 
EU moves to complete the single market, the Trans-European Energy Networks (TEN-E) 
policy was developed. Its purpose was to provide a more political impulse to energy 
infrastructure development from the European perspective, by focussing on the feasibility 
stage for gas and electricity network projects, notably those crossing borders, which 
contribute to the working of the internal market. At that time, the EU had no common energy 
policy and no functioning internal energy market. In most Member States, state-run 
companies managed network investments, which we re mainly driven by national security of 
supply considerations. Later revisions to TEN-E incorporated sustainability and supply 
security criteria. It was assumed throughout t hat EU intervention in the implementation 
phases of such projects would not be necessary, as commercial interests would drive 
projects forward. The TEN-E budget consequently remained very low – some € 22 million 
annually in the period 2007-2013. The currently valid TEN-E Guidelines were adopted in 
September 2006 replacing those of 19961 and 20032. 
 
This impact assessment was prepared to support the forthcoming communication on energy 
infrastructure priorities (phase 1 of the so called "Energy Infrastructure Package") for a new 
policy to promote the development of TEN-E to enable adequate and timely development of 
energy infrastructures. This impact assess ment covers the development of energy 
infrastructure for the period 2010-2020, with a view beyond to 2030 - having in mind the 
energy challenges for the century - and assesses investment needs for new transmission 
infrastructure, evaluates the current TEN-E framework and financing possibilities, compares 
various policy options for implementing sufficient infrastructure to support the achievement of 
the EU's energy and climate policy goals in the most cost efficient way and thereby examines 
the possibility of integrating CCS and oil transport networks in the future policy. 
 
Building on the present document, a separate assessment will be carried out to prepare the 
legislative proposal for a new European energy se curity and infrastructure instrument, which 
is to be presented in 2011 (phase 2 of the Energy Infrastructure Package). Therefore, the 
present impact assessment does neither include a detailed analysis of the way, in which 
infrastructure investments are currently financed, nor possible solutions in terms of tariff 
regulation or financing to address the identified investment gap or other financing 
shortcomings. 
 
The detailed list of documents and studies that have been used for the preparation of this impact assessment can be found in Annex 5. 
                                                 
1 Decision No 96/391/EC 
2 Decision No 1229/2003/EC 
 
 61.1. Green paper and public consultation 
 
The main consultation for this impact assessment took place in the framework of the green 
paper "Towards a secure, sustainable and co mpetitive European Energy Network", which 
was endorsed by the European Council and Parliament and published with the Second 
Strategic Energy review3. The green paper pointed out that the current EU network policy 
was not able to deal with global security of suppl y challenges, to effectively diversify the EU's 
energy sources, to ensure solidarity in the case of an energy crisis or to draw on the benefit of new technologies. It also stressed the direct link between energy import infrastructure and the EU's external relations. The Green Paper recommended that energy infrastructure 
development should be driven by the energy policy goals: the "20-20-20" objectives
4, security 
of supply and solidarity, sustainability and innovation, as well as competitiveness. The implications of climate change for Europe's en ergy networks, concerning for example the 
location of power plants, electricity lines and pipelines, were identified as an important element to be taken into account for infrastructure projects. It moreover recommended: 
• to extend the scope beyond electricity and gas transport infrastructures (including 
liquefied natural gas terminals and storage) to oil and CO
2 transport infrastructure; 
• to let the market drive planning with a clear remit for the European Network of 
Transmission System Operators and the Agency for the Cooperation of Energy 
Regulators, as well as the EU as active facilitator and mediator; 
• to narrow down the number of priorities to a limited number of European strategic 
projects, to be incorporated in national infrastructure plans; 
• to build up accompanying measures to disseminate information and exchange best 
practices; 
• to consider, in exceptional cases, the appointment of a European Coordinator, 
building on the experience of the past/current coordinators; 
• to improve the effectiveness of the TEN- E instrument within existing means through 
better coordination with other EU financial instruments, while also considering ways of 
increasing the TEN-E budget, notably to support investments with a public good character. 
Questions at the end of the Green Paper addressed the main barriers to the development of a European electricity and gas network and the role the EU should play in overcoming these 
barriers. Concerning TEN-E, the questions asked advice on the main recommendations 
listed above and additional measures the EU could take to secure sustainable infrastructures.  During the four month consultation exercise, ending on 31 March 2009, The Commission 
received 91 written replies to the questions raised in the Green Paper. 13 came from 
Member States (2 from a regional and a local government), 1 from regulators, 60 from the 
industry, 2 from academia and 13 from individual citizens, NGOs and other organisations. The energy sector dominated the industrial responses. Contributions were received from system operators, the upstream sector, t he energy equipment sector, and cogeneration and 
district heating companies as well as shippers,  traders and firms involved in infrastructure 
construction. The renewable industry was mainly represented by wind and solar industry 
players.  A clear message from the public consultations was that there is a strong need to better align the energy network policies of the EU and the EU energy and climate targets. There was 
also general support for a fundamental review of the TEN-E framework. The Commission's 
concern to give more attention to energy infrastructure as a factor of energy security was 
                                                 
3 COM (2008) 781 "An EU energy security and solidarit y action plan" endorsed by the Council in its March 2009 
summit conclusions 
4 20% reduction in greenhouse gas emissions, 20% share of renewable energy in EU final energy consumption 
and 20% improvement in energy efficiency by 2020 
 
 7also vindicated. The possibility to also cover transport infrastructure for carbon dioxide 
capture and storage (CCS) was generally supported, while the replies were more hesitant on 
oil transport networks. A specific area where a broad consensus emerged was in the 
relevance of energy networks to EU external  energy relations. The role of the EU in 
facilitating infrastructure projects in third countries was welcomed, and the importance of external energy relations to infrastructure policies was reaffirmed.  
1.2. Stakeholder consultations 
Stakeholder consultation included discussions in the Gas Coordination Group5 (March and 
June 2010) comprising representatives of 27 Member States and gas industry and gas 
consumers' associations, in the different working group meetings (Sustainable Fossil Fuel and Security of Supply working groups) of the Berlin Fossil Fuels Forum (May 2010). Regular exchange of information took place with the two European Networks of Transmission System Operators (ENTSO) for gas and for electricity and the European Regulators' Group for 
Electricity and Gas (ERGEG). The 10 year network development plans developed by the 
ENTSOs served as an important input for the infrastructure needs assessment. A high level conference was organised under the Spanish Presidency on 28 May 2010. Regarding the development of offshore grids, inputs from the so-called "Adamowitsch working group
6" and 
the workshop organised by the North Seas Countries' Offshore Grid Initiative (March 2010) 
have been incorporated.  
 Several bilateral meetings with industry representatives and stakeholder organisations took place providing similar results to the public consultation. The electricity industry expressed particular concern about lengthy and uncertain permitting procedures and supported the Commission's intention to tackle those. A further concern was the need for better regulation 
of grid investment financing and cost sharing. The industry also pleaded for the definition of 
priority infrastructure corridors rather than pre-defined project lists. The gas industry generally emphasised the environmental advantages of  gas in terms of lower CO2 emissions 
in comparison to other fossil fuels. The CCS sector was strongly in favour of the inclusion of CO2 transportation infrastructure in the trans-European networks policy, while there was no 
common position concerning the inclusion of oil pipelines within the oil industry (generally, 
Eastern EU oil companies supported the idea, while Western European companies did not have a position).  Regarding smart grids, this impact assessment  has benefited from the input given by the 
European Technology Platform smart grids for the preparation of the Strategic Energy 
Technologies plan (June 2007) and by the three experts groups of the European Task Force 
for smart grids, which presented their intermediate reports in June 2010.  Following the recommendations for improvement included in the opinion of the Impact Assessment Board on the 27
th September 2010, a better explanation is provided on the 
issues, which will be tackled in the forthcoming Communication and are thus included in this 
impact analysis, and on the issues, which would need to be further explored for the legislative proposal and its accompanying Im pact Assessment, to be prepared next year. 
Chapters 2.3 and 3 have been amended accordingly. To provide more transparency on the underlying modelling, its assumptions and invest ment estimates, specific boxes have been 
inserted in Chapters 2.4 and 5.1. Chapter 2.4 has generally been amended to better highlight 
what the expected impact of the implementation of the 3
rd Package on the internal energy 
market will be in the baseline scenario. In these chapters, the current tariff setting rules and their shortcomings as well as the definition of "commercial viability" are better explained; however, an in-depth analysis of these issues is foreseen for the IA report accompanying the 
                                                 
5 Commission Decision 2006/791/EC 
6 Consultative group set-up by the EU Coordinator for off-shore wind, Mr. Georg-Wilhelm Adamowitsch 
 
 8legislative proposal. Concerning the issue of permitting Chapters 4.4 and 5.5 have been 
amended, including clearer explanations and indications on the further analysis to be 
undertaken to provide a more thorough assessment of the options aiming at accelerating 
permitting – i.a. the assessment of the compatibili ty of the options with national legal systems 
and their costs – and included in the Impact Assessment for the legislative instrument.  Finally, the options and impacts for the policy areas of coordination and design of new policy instrument have been clarified in Chapter 4.2, 4.3, 5.3 and 5.4. Following the second opinion of the Board (18
th October 2010), further improvements have been included with reference to 
the estimates on the investment needs and in the conclusions.  
 
2. PROBLEM DEFINITION  
 
2.1. A dramatically changed policy context 
This chapter summarises the current energy policy context which has changed dramatically 
since the TEN-E policy was last revised in 2006. More details on existing legislation and its impact on future infrastructure development will be given in chapter 2.4 (Baseline scenario). 
 
The EU Energy Policy
7 and its implementing legislation, pursuing the objectives of 
sustainability, competitiveness and security of energy supply, set ambitious goals and 
binding targets for 2020 on greenhouse gas emissions8 (-20%%; -30% if a satisfactory 
international agreement is reached) , energy from renewable sources9 (20% of final energy 
consumption) and energy efficiency (20% reduction in energy consumption compared to 
business as usual). This legislation includes the energy and climate package (Renewable 
energy directive10 and CCS directive11), the third internal energy market package12 and the 
recently agreed regulation on security of gas supply13. 
 Adequate, reliable energy networks are a prerequisite to meet all these objectives. Europe's networks will have to undergo important evolutions to meet this challenge – evolving from a 
patchwork of national networks to a truly integrated EU-wide network. At the same time, 
these networks are aging and urgently need refurbishment and modernisation. Therefore, massive investments in network infrastructure will be needed in the coming decades, challenging the TEN-E policy framework as a whole and the existing regulatory model for electricity and gas infrastructure development in Europe. 
 
The regulatory framework itself has evolved with the adoption of the third internal energy market package in July 2009. It introduces several new rules for infrastructure planning, coordination and investment, which address many of the weaknesses (detailed in chapter 2.4.2). Transmission System Operators (TSOs)  are required to establish national 10-year 
network development plans and to co-operate and elaborate regional and European 10-year 
network development plans (TYNDP) for electricity and gas with a focus on cross-border interconnections, in the framework of the European Network of TSOs (ENTSO). The package also establishes an Agency for the Co-operation of Energy Regulators (ACER) that – among other tasks – will have to monitor t he implementation of European TYNDPs. The 
                                                 
7 COM (2007) 1 endorsed by the Council on 15 February 2007 (C/07/24) 
8 Directive 2009/29/EC amending Directive 2003/87/EC  so as to improve and extend the greenhouse gas 
emission allowance trading scheme of the Community, Decisi on No 406/2009/EC on the effort of Member States 
to reduce their greenhouse gas emissions to meet  the Community’s greenhouse gas emission reduction 
commitments up to 2020 
9 Directive 2009/28/EC on the promotion of th e use of energy from renewable sources 
10 Directive 2009/28/EC OJ  L140 of 5.06.2009 p. 16 
11 Directive 2009/31/EC establishes a legal framework for safe geological storage of carbon dioxide (CO 2). 
12 http://ec.europa.eu/energy/gas_electric ity/third_legislat ive_package_en.htm : see notably Directives 2009/72/EC 
and 2009/73/EC and Regulations (EC)  713/2009, 714/2009 and 715/2009 
13 http://www.europarl.europa.eu/oeil/FindByP rocnum.do?lang=2&procnum=COD/2009/0108  
 
 9third package finally sets the target, where possible, to equip at least 80% of consumers with 
smart meters by 202014 as a first step towards the implementation of smart grids. 
 
Furthermore, the European Council15 has set as an EU objective an 80-95% reduction in 
greenhouse gas emissions by 2050 compared to 1990 levels, in the context of necessary reductions by developed countries as a group. The Europe 2020 strategy therefore includes the establishment of a vision of changes required to move to a low carbon, resource efficient and climate resilient economy by 2050. In this context, there is work on-going within the 
Commission to outline a vision concerning climate action and possible roadmaps for a 
transition to a low-carbon energy system by 2050. Infrastructure development and planning of today has to ensure that investments made in the next two decades are compatible with the long term vision. 
2.2. Current TEN-E framework and Europe an Energy Plan for Recovery 
The TEN-E framework  has been developed and shaped in the 1990’s through the 
successive TEN-E Guidelines and the corresponding financing Regulation16. The current 
objectives of the TEN-E policy are to (1) support the completion of the EU internal energy market while encouraging the rational production, transportation, distribution and use of energy resources, (2) reduce the isolation of less-favoured and island regions, (3) secure and diversify the EU's energy supplies also through co-operation with third countries, (4) contribute to sustainable development and protection of the environment (including inter alia  
a greater use of renewable energy source s and the reduction of environmental risks 
associated with the transportation of energy). The current TEN-E policy framework includes electricity, gas and olefin transmission networks, but not CO2 transportation, neither oil pipeline infrastructure. The guidelines establis h a framework for closer cooperation, for 
example through better exchange of informati on and coordination between Member States. 
The guidelines foresee that, when projects encounter significant delays or problems, a 
European coordinator may be appointed to the project in order to facilitate coordination and monitor progress. Four coordinators have been appointed in September 2007
17, on the basis 
of the Priority Interconnection Plan18. 
 
The 2006 guidelines for Trans-European Energy Networks listed about 550 projects eligible 
for Community support according to the above-mentioned objectives, ranking them in the 
following three categories: projects of European interest (42 in total); priority projects and 
projects of common interest. These projects co ver only electricity and gas infrastructure, no 
oil, olefin or CO2 transportation infrastructure.  The report on the implementation of the TEN-E framework in the period 2007-9
19, published 
in April 2010, concluded that the policy made a positive contribution to selected projects by giving them political visibility and the TEN-E label facilitates communication to and 
collaboration with third parties. However, there is a lack of focus within the current guidelines 
and not enough clarity between the categorisation of projects (common interest, priority project, European interest). The list of targeted projects is rigid: new projects and technologies (e.g. electricity storage, CNG etc.) cannot be included. The guidelines are based on a bottom-up selection of existing projects but do not leave space for a top-down 
approach to fill identified infrastructure gaps. There is no mechanism to ensure that Member 
States grant projects of EU importance the same priority as their national projects. The 
                                                 
14 Annex 1 of Directive 2009/72/EC 
15 European Council conclusions, 30 October 2009  
16 Decision No 1364/2006/EC laying down a series of guidelines for trans-European energy networks and 
repealing Decision 96/391/EC and Decision No 1229/2 003/EC; Regulation (EC) No 680/2007 laying down  
general rules for the granting of Community financial aid in the field of the trans-European transport and energy 
networks 
17 http://ec.europa.eu/energy /infrastructure/tent _e/coordinators_en.htm   
18 COM(2006)846 
19 COM(2010)203 and SEC(2010)505 
 
 10current TEN-E framework is not binding and places no obligations on Member States or 
project promoters to really invest and construct infrastructure. TEN-E support may be given 
to competing and – within a given timeframe – mutually exclusive infrastructure projects. 
While there is a strong link between the EU's external energy policy and infrastructure development, coordination between TEN-E and external aid programmes has been insufficient.   The TEN financing Regulation
20 adopted on 20 June 2007 sets out the conditions for TEN-E 
funding and, in particular, states that co-financing can be granted for up to 50% of studies' 
cost and 10% of eligible works' cost, in particular to projects of European interest. The budget for the period 2007-2013 is 155 million eur o (about 22 mln € per year). Currently, 
TEN-E plays a particularly important role for imma ture or risky projects and feasibility studies. 
However, no precise methodology was established to assess the "additionality" of EU 
support, i.e. the specific contribution of TEN-E funds to making projects actually bankable. 
The TEN-E Programme's limited financial resources may have been adequate when focused on studies for remaining problematic interconnections, but the paradigm shift to a low carbon energy system and hence the major evolution and investment needed in energy infrastructures in the coming years call for a reassessment of the TEN-E instrument to ensure its future effectiveness. The TEN financi ng Regulation allows only grants and interest 
rate rebates, while the market rather needs innovative financial instruments such as 
guarantees or equity participations for risk mitigation. The current financing Regulation does not allow the funding capital expenditures outside the EU, while large gas import infrastructure and related connection to upstream sources or even electricity interconnections with third countries go well beyond EU borders. 
 
This demonstrates that the current TEN-E policy and financing framework is not effective enough given the above described dramatic c hanges in the wider policy context.  
 Set up in the context of the economic and financial crisis, the European Energy Plan for 
Recovery
21 has responded to some of the weaknesses identified above by allocating, for the 
first time, significant amounts (around 4 bn€) to a rather limited number of eligible projects in the domain of electricity and gas interconnectors, gas reverse flows and storages, off-shore wind and CCS demonstration projects. The objective was to help overcoming possible financial difficulties caused by the economic and financial crisis and thus to contribute to the expenditure for the implementation of the most mature projects, in order to speed up and 
secure investments and accelerate their construction. 
 
2.3. Main problems 
The challenges and drivers as well as the obs tacles hampering energy infrastructure 
development and the resulting main consequences of insufficient infrastructure are summarised below:  
 
                                                 
20 Regulation (EC) No 680/2007 
21 Regulation (EC) No 663/2009 of the European Parliame nt and of the Council of 13 July 2009 establishing a 
programme to aid economic recovery by granting Union fin ancial assistance to projects in the field of energy (OJ 
L200, 31.7.2009) 
 
 11 
 
Figure 1  
 
As pointed out in the introduction, the new policy context triggers substantial needs for new energy infrastructure investment in the EU, which is estimated at about 200 billion euros up to 2020 (see chapter 0 for details). However, due to the obstacles described in this chapter, not all the necessary investment will materialise under current conditions. The obstacles to 
adequate development of infrastructure can be described in detail as follows:  
 
1) Huge uncertainties concerning future technologies in terms of their availability, 
possible risks and cost competitiveness, standards for the interoperability and scalability of systems (notably for certain renewable energy technologies, offshore grids and smart 
grid infrastructure, but also for electricity storage and CCS, currently not included in the 
TEN-E framework),  energy mix and geographical distribution of future plants 
(electricity), and new sources  (unconventional gas, green gas, LNG/CNG, new import 
infrastructure and upstream development in third countries) add to the overall uncertainty of future energy market developments and lead to sub-optimal market solutions (from an EU point of view). 
The market players and/or regulators do not anticipate future demand / capacity needs if 
it is not commercially viable or would result in  higher tariffs in the short term. This will 
result in increased cost over time (in the long term) and higher environmental impact (for 
example a number of smaller pipelines instead of one large).  
2) Tariff regulation and financing: Transmission is a regulated business at national level 
and cost allocation to final beneficiaries is difficult or impossible for large trans-European infrastructure. In order to keep transmission tariffs as low as possible, tariff regulation in most Member States has been based on the principle of cost-efficiency, allowing recovery of costs only for projects based on real market needs or cheapest available solutions. There are in particular three types of projects, whose realisation is typically 
hindered through this approach: 
a. Projects with higher regional than national benefit
: 
The higher the regional or EU benefit of a project, i.e. the more Member States are involved, the more complex it often is (cross-border issues including e.g. different regulatory regimes concerning rates of return or investment amortisation • Insufficient energy (especially cross-
border) infrastructure is delivered 
• Infrastructure design is not optimal 
from an EU point of view
Economic : 
Higher energy prices due to lack, 
unavailability or suboptimal design 
of transmission capacity Social : 
Supply 
disruptions / 
black-outs Environmental : 
EU climate goals not 
achieved; local impact of 
new infrastructure Challenges / drivers  for demand growth for 
infrastructure investment: 
- Climate objectives (CO2, RES, efficiency) 
- Security of supply 
- Market integration 
- Evolution of energy generation mix/type and location Obstacles  for delivering infrastructure:  
- Uncertainties concerning technologies 
- Tariff regulation and financing 
- Permitting and social acceptance 
- Imperfect internal market 
- Extra-EU infrastructures 
- Inadequacy of TEN-E policy 
 
 12periods, different permitting procedures etc.) and the more difficult cross-border 
coordination gets, especially if the costs and benefits of the project are shared 
asymmetrically between Member States. This complexity increases the project 
risks and hence the financial needs, which will not be covered by the market and new third package rules alone. It will result in sub-optimal solutions in terms of overall European or regional benefit. 
b. Projects using innovative technologies
22 typically involve higher risks, as their 
industrial-scale applicability and business case are not fully proven yet. 
Nevertheless, market players do often not ask for and/or regulators do not 
approve a higher rate of return to make them bankable. Thus, first-of-their-kind projects that use new technologies for generation (e.g. carbon capture and storage) or transmission (e.g. DC VSC offshore grid technology, storage, smart grid applications), and which are necessary for the achievement of the EU energy 
and climate goals, will not be implemented within the set timeframe
23. 
Uncertainty on the appropriate market model and regulatory approach for the above mentioned technologies also lead to suboptimal solutions. 
c. Infrastructure with the objective to enhance security of supply
 – in pursuit of the 
infrastructure standards included in the new regulation on security of gas supply (N-1 and reverse flow) – is needed all over the EU, but is only rarely if ever 
justified by market demand and transported volumes as it is used only in case of 
supply disruptions (low probability / high impact events), but not under normal market conditions. In many Member States, most of them with relatively low per capita GDP levels, there has so far been no regulatory solution on how to recover the costs of these investments, and financing through tariff increases will be 
difficult to achieve
24. 
In addition, there are externalities concerning the financing of infrastructure: TSO's must justify their investment to the national regulator by looking at future revenues only from transmission; they cannot factor in revenues  from business opportunities such as price 
arbitrage between markets or market contestability (lower prices in a given market due to 
the threat of competition). For the same reason, supply shortage or increased market 
prices (due to lack of infrastructure) have no or little impact on TSO revenues, while they have a huge economic impact on commodity markets.  Finally, as a result of the financial crisis, and the current rapid evolution of rules in the financial sector, access to capital has become more difficult since 2008. Credit ratings of many TSOs have deteriorated and still continue to do so. There is also a lack of 
adequate financing instruments, risk capital and loans at sufficiently long maturity. 
Furthermore, there seems to be a lack of knowledge within the financial sector, notably among potentially interested investors (such as private wealth funds), on how to evaluate energy infrastructure investments.  
3) Permitting and social acceptance: Long and uncertain permitting procedures were 
indicated by industry as one of the main reasons for delays in the implementation of infrastructure projects, notably in electricity. This puts a major additional risk on investments in power generation and transmission and has slowed down or even stopped new projects. In several Member States, publ ic opinion is turning progressively against 
new projects and in particular overhead electricity lines, adding to the obstacles faced by 
projects due to inappropriate authorisation procedures and administrative practice. 
                                                 
22 Cf. Impact Assessment of the SET Plan (SEC (2009) 1297) 
23 The European Electricity Grid Initiative (EEGI), l aunched in the framework of the SET Plan, has identified 
research and development priorities for both electricity transmission and distribution covering the period up to 
2018. The functional areas covered include improved gr id planning, renewables integration, both on- and 
offshore, and smart grid applications, with a budget es timated at 2 bn€, out of  which about 560 m€ for 
transmission activities alone. However, the projects focus on studies only and do not cover industrial-scale works. 
24 Cf. "Commission Declaration on long term security of supply measures" related to Regulation XXX/2010 
concerning measure to safeguard security of  gas supply and repealing Directive 2004/67/EC 
 
 13Therefore, the time between start of planning and final commissioning of a power line is 
frequently more than 10 years, be it a domestic or  a cross-border project. With significant 
permitting obstacles and public opposition, projects can take up to 20 years to be 
completed25. Cross-border projects often face additional opposition, as they are 
frequently perceived as mere "transit lines" without local benefits. Limited public understanding for the benefits of a given project or technology might also limit in particular the roll-out of smart-grid applications.  
4) Imperfect internal market : there is weak competition in some Member States where 
national markets are still dominated by incumbents (such as Belgium, France, Greece, Latvia, Luxembourg or Slovakia in electricity and Finland, Greece, Latvia, Lithuania, Luxembourg, Poland, Slovakia and Slovenia in gas)
26. Lack of infrastructure constitutes a 
high entry barrier for new entrants, especially in markets, which are dominated by historic 
operators and will most likely remain so over the coming years, despite third package 
provisions on unbundling. Lack of market development does not allow TSOs to have sufficient firm capacity contracts to invest in an interconnector between two markets; at the same time, the market is unlikely to be able to develop as long as there is no interconnector. 
 
5) Infrastructures external to the EU.  For energy infrastructures outside the EU that will 
be required to meet the EU’s growing need for imported gas and oil and to improve security of supply through diversified supply sources and routes, or to import "green electricity", there are additional political risks. Beside the need to engage politically with third countries to identify and ensure a mutual benefit from new energy infrastructures, 
risks may range from an unattractive or non-transparent investment framework in the 
third countries through to the risk of changes  in the fiscal/tax or legal environment once 
the investment has been made.  
6) Inadequacy of the current TEN-E policy  as described in chapter 2.2. 
 
 It clearly derives from the above that the new energy policy context has created huge challenges for EU infrastructure development at  a continental scale. Current policies aiming 
at connecting national grids will not be sufficient, as there is a need to build a fully interconnected European network for electricity and gas, including through new electricity 
super-grids. 
To meet the EU’s energy and climate goals for 2020 and beyond up to 2050, massive investments are required in energy networks and par ticularly in Europe’s electricity grids over 
the next two decades up to 2030 as a necessary condition for change to happen in energy generation, supply and demand. Given the problems encountered, these investments will not 
happen quickly enough without strong action both at national and Community level. 
 
This Impact Assessment aims at supporting the forthcoming Communication with the 
objective to establish a broad policy direction for future infrastructure development. This 
initiative hence broadly addresses the above identified problems, in particular the uncertainties, the issues surrounding permitting, external policy aspects of infrastructure and the inadequacy of the current TEN-E, including inter alia the lack of focus and the rigidity of the identified project list. 
 
The proposals included in the Communication and the remaining problems will be addressed and followed up next year through the legislative proposal for an EU Energy Security and 
                                                 
25 ENTSO-E 10-year network development plan, June 2010 
26 Benchmarking Report (COM (2010) 84) and technical annexes (SEC (2010) 251) 
 
 14Infrastructure Instrument, for which a specific impact assessment will be prepared with 
particular focus on financing, tariff regulation and an in-depth analysis on permitting. 
 
 
 
2.4. Baseline scenario 
This chapter presents the likely evolution of networks and bottlenecks in terms of 
infrastructure development under the current policy framework.  
Box 1: Methodology used for infrastructure investment needs assessment
 
 
The analytical tools used are the following:  
 
a) for determining energy balances in 2020 and 2030, t he PRIMES model (using the results of GEM-
E3, PROMETHEUS and GAINS modelling as inputs); 
b) for evaluating resulting infrastructure needs in the electricity and gas sector, a specialized grid 
modelling framework developed by KEMA and Imperial College London; 
c) for assessing infrastructure needs for CO 2 transport, two specialized analysis and modelling tools 
developed by ARUP and JRC. Experience from  on-going investments was also analysed. 
 
a) PRIMES modelling of energy balances 
The PRIMES model is a modelling system that simu lates a market equilibrium solution for energy 
supply and demand. The model is organized in sub-models (modules), each one representing the 
behaviour of a specific (or representative) agent, a demander and/or a supplier of energy. Several EU 
baselines and scenarios have been established at diffe rent points in time using a framework contract 
with National Technical University of Athens ( author and owner of the PRIMES model). Energy 
modelling is a tool for informed policy making. For instance, the PRIMES 2007 baseline was used to 
analyse impacts of the energy and climate package in  2008. This analysis relies on the 2009 update of 
PRIMES. Two recent scenarios have been developed:  
• the Baseline 2009  that takes into account the policies implemented in the Member States up to 
April 2009; 
• the Reference scenario , which includes policies up to the end of 2009 and assumes the 
achievement of the legally binding targets on renewables and greenhouse gas reduction. 
 
The latest update is based on an average GDP grow th of 1.7% per year for the period 2005-2030 as 
opposed to 2.2% in the 2007 baseline. The energy proj ections are based on a relatively high oil price 
environment compared with previous projections a nd similar to reference projections from other 
sources, with oil prices of 59 $/barrel in 2005 ri sing to 106 $/barrel in 2030 (in year 2008-dollars). 
Significant changes in these assumptions alter the energy outlook for the next 20 years.  Primary 
energy consumption stabilizes at today's level as compared to rising consumption in 2007 baseline. 
Less electricity is projected but with more RES in t he system (impacts on electricity grid) as well as 
lower demand for gas (lower gas imports). More information can be downloaded from the Europa 
website: 
http://ec.europa.eu/en ergy/observatory/tr ends_2030/in dex_en.htm 
 
b) Modelling of electricity and gas infrastructure requirements 
Investment needs were assessed for electricity and gas infrastructure, taking into account the 
available information in the 10-year network development plans prepared by the two European 
Networks of Transmission System  Operators (ENTSO, introduced by the 3rd package),taking into 
account also the interdependencies between the two sectors. It should be no ted that a forecasting 
exercise with a time horizon of up to two dec ades can only give indicative results, given the 
uncertainties surrounding future s upply, demand and price developments. 
 
Electricity  
 
 15The requirements for investment in electricity infrastructure were estimated using a modelling 
framework developed by KEMA and Imperial Colle ge London (ICL), which divides the investment 
requirements into two parts: 
- an investment estimate for the interconnection requirements between Member States to evaluate 
cost-optimal regional interconnection and generat ion capacity requirements for system security 
purposes, and the annual operat ing costs of the system; 
- an investment estimation for the cost of integr ation of offshore wind capacity based on a separate 
estimation tool. 
The investment model divides the EU27 countries plus Norway and Switzerland into 29 regions. The 
model trades off the various investment elements and optimises based upon input cost assumptions. 
The scope of the transmission system analysis is  focused on incremental capacity requirements 
between the regions for each future scenario relati ve to the current 2010 baseline, but respecting the 
anticipated 2020 transmission capacities contained with in the ENTSO-E TYNDP, i.e. all investments in 
the ENTSO-E TYNDP are assumed to happen in all scenarios. 
 
Three scenarios were modelled, two based on PRIMES 2010 Reference scenario in 2020 and 2030 
and a further High Renewable Energy Source scena rio (High RES) in 2030. The modelling results 
provide snapshots of electricity transmission netw ork investment requirements, additional generation 
investments and associated operational costs aligned with the respective time horizon. 
 
For each scenario, the European electricity system  is modelled as a 29-node system with 54 defined 
interconnection possibilities between these nodes . The system consumption and peak demand 
characteristics are common in the two 2030 scenarios and greater than the overall electrical energy 
requirement assumed in the 2020 scenario. The cons umption data for all scenarios is aligned with 
PRIMES consumption forecasts including the net electricity import/export position. 
 
The modelling approach relies on a cost estimation methodology. It seeks to provide an indication of 
the capital costs associated with expanding the in terconnection capacity between Member States to 
maintain a power system with security characteristics similar to those experienced today. The 
modelling framework does not provide specific costs for any particular circuits to form the indicated 
transmission capacity. Nor does it assess the invest ment requirements for connections due to growing 
demand or investment in the distribution network. 
 
Both technical and cost assumptions were devel oped in the framework of a previous extensive 
analysis of industry standards and learning rates and vetted by key industry stakeholders. 
Assumptions and results were also discussed in deta il with ENTSO-E experts in charge of the TYNDP 
preparation, which have confirmed the validity of  the general modelling approach and the indicative 
nature of the investment need results. 
 
It must be underlined that this modelling exercise covers only transmission needs for interconnection 
and offshore connection. Changes in the generation capacity mix (e.g. due to structural variations in 
fossil fuel prices), in energy demand (e.g. due to sl ower or faster than expected economic growth) or 
in the costs for certain specific transmission te chnologies could have a significant impact on the 
outputs of the model. While it is assumed that as sumption errors for the individual transmission 
investments will offset each other to  some extent, it has been estima ted that the aggre gate error on 
investment costs could be in the range of +/–15%. 
 
The evaluation of investment needs in Smart Gr ids has been based on the most recent available 
literature, in particular the findi ngs of the High-Level Advisory Group on ICT for Smart Electricity 
Distribution Networks. The figures used are only very  first indications and could vary significantly, 
depending on future technology cost evolutions. 
 
Gas 
The requirements for investment in gas infrastructure were based on gas demand projections from the 
PRIMES baseline 2009 and Reference scenario 2010 for 2020. These projections were matched for 
consistency against data coming from stakeholder s (preliminary ENTSOG estimates, Eurogas) and 
analysing the most recent studies27 and available documentation regarding gas infrastructure 
                                                 
27 "Model-based Analysis of Infrastructure Projects and Market Integration in Europe with Special Focus on 
Security of Supply Scenarios", study by EWI Institute of  Energy Economics at the University of Cologne. May 
 
 16development projects, including investment in LNG terminals, natural gas storage and reverse flow 
projects. The estimation of gas in frastructure investment need is to  some extent dependent on the  
assumptions concerning future gas demand, which again depend to a limited extent on assumptions 
concerning GDP growth, but to a far higher extent on  a series of other factors such as gas prices 
(partly based on mainly oil-indexed long-term cont racts, partly decoupled from oil price and based on 
global supply and demand balance), the role of gas in electricity generation and in particular as back-
up for variable electricity energy from renewable sources, the level of ma rket integration and the 
infrastructure and supply standards for security of gas supply and finally the cost of infrastructure 
(which can vary highly based on the routing for pipe lines, cost of steel, the geological conditions for 
storage etc.). This would add an ov erall +-25-30% range to the identified figures (about +-20% for 
storage and interconnectors and up to  50% for import infrastructure). 
 
c) Modelling of CO2 infrastructure requirements 
The requirements for investment in CO 2 transport infrastructure were determined, based on the 
amount of CO 2 indicated as captured under both the PRIMES baseline 2009 and Reference scenario 
2010. Modelling was prepared by JRC, using a dedicat ed analytical tool (InfraCCS) and the following 
four methodological steps: 
- Identification and clustering of CO 2 sources and sinks;  
- Assumptions about the evolution of captured CO 2 emissions and storage capacities; 
- Routing of potential pipelines between nodes; 
- Selection of the optimal netw ork and evolution over time. 
Given the fact that the EEPR CCS projects are already under devel opment, the model runs under both 
PRIMES scenarios resulted in the same required network length, with the Reference scenario 
delivering slightly lower investment needs due to t he fact the pipelines to be deployed would not have 
to be oversized. Uncertainties rema in concerning the evolution of CO 2 demand beyond 2020, which 
will have to be analysed in more detail to  confirm the need for pipeline oversizing. 
 
ARUP prepared a separate analysis to determine the optimal CO 2 transport network in Europe and its 
evolution over time, based on predefined volumes of CO 2, identification of suit able storage sites and a 
cost-minimisation approach. The study analysed snapshots for 2030 and 2050. The results can 
therefore not be directly compared with the results of JRC analysis. However important similarities 
have been recorded in the shape of the future netw ork proposed by both studies, confirming that a 
regional approach to developing the future network will be esse ntial.. Assumptions of the study were 
discussed in detail with the EC Fossil Fuels Fo rum (Berlin Forum) stakeholders. Zero Emission 
Technology Platform (ZEP TP) was also consulted. Moreover, ZEP's Chairman in his letter of 30 June 
2010 addressed to the Energy Commissioner stress ed that the policy objective of ensuring the 
development of networks to permit the achievement of the EU’s ener gy and climate objectives should 
explicitly be extended to include the development of new CO 2 pipeline infrastructure. EURELECTRIC 
was also consulted. It xtended its support to a coordinated approach to the development of a CO 2 
pipeline network across Europe and recommends that CO2 infrastructure should be included in the 
upcoming infrastructure instrument. Furthermore, EURELECTRIC supported as sumptions of ARUP's 
study, in particular as regards developing scenari os outlining different transportation roadmaps. A 
number of other stakeholders supported Commission's approach. 
 
It is important to point out that deployment of CCS could have an impor tant contribution to meeting the 
GHG reduction targets as described in the Ener gy and Climate package. The impact assessment 
prepared for the Directive on the ge ological storage of carbon diox ide proves that without enabling 
policy for CCS at EU level (that is, achievement of climate objectives without CCS), the costs of 
meeting a reduction in the region of 30% GHG in 2030 could be up to 40% higher than with CCS. 
Thus not enabling CCS would have substantial negati ve impacts on Europe’s capacity to meet the 2 
degrees Celsius target and on competitiveness, and also for employment, and would have a slight 
negative impact on security of supply. 
 
                                                                                                                                                         
2010 and "The revision of the trans-European energy net work policy (TEN-E)", impact assessment study by 
COWI, Cambridge Econometrics and KEMA 
 
 17 
2.4.1.  Energy trends and infrastructure needs 
The PRIMES reference scenario has been used to estimate future demand for energy up to 
2030, the impact assessment itself being limited to 2020. The results have been compared to 
the PRIMES baseline scenario28 and other scenario results. It is assumed that the two 
binding targets (20% renewables share and -2 0% greenhouse gas emissions) are achieved 
in the Reference scenario, implying that all ot her necessary implementing provisions (such 
as the energy infrastructure policy) will be completed. In the baseline scenario, based only on continuation of already implemented policies, these targets are not achieved. While primary 
energy consumption is projected to remain largely stable at 1,800 Mtoe and final energy 
demand at 1,200 Mtoe between 2010 and 2030 in both the PRIMES baseline and the 
PRIMES reference case scenario, the use of electricity and in particular renewable energies tends to increase significantly over the period, while the use of coal, but also oil and gas decline under both scenarios, however at a substantially different pace. In the following, we give a more detailed overview of the likely evolutions by sector.
 
 The electricity  sector is expected to face increasing demand
, partly because of a major fuel 
shift in the overall energy mix as a result of the greenhouse gas reduction goals, but also because of its convenient use and the multiplication of applications relying on it as an energy vector (heat pumps, electric vehicles, information and communication technology devices 
etc.). EU-27 gross electricity generation is projected to grow from about 3,362 TWh in 2007 
to 4,073 TWh in 2030. At the same time, the electricity generation mix is changing, with less fossil fuels and more renewable and variable energy sources
. According to the Reference 
scenario, their share in gross electricity generation is expected to be around 33% by 2020 and 36% in 2030, out of which variable sources (wind and solar) could represent around 16% in 2020 and almost 20% in 2030. Significant new renewable capacities will be concentrated 
in locations further away from the major centres of consumption (offshore wind parks, 
ground-mounted solar parks), while decentralised generation will also gain field. This change in the nature of both generation and consumption patterns will require both electricity transmission and distribution grids to play an ever more important role
 in flexibly balancing 
supply and demand over increasing distances, while maintaining the same levels of security 
of supply. At the same time, the correct functioning of the internal electricity market will 
require additional cross-border interconnections and reinforcements of domestic grids. Annex 
1 shows the major additional cross-border transmission capacity needs until 2015 and beyond, as estimated by ENTSO-E.   All these factors trigger large-scale investment needs at a level not seen over the past 
decades , both within Member States and cross-border, including in areas almost not covered 
today by electricity grids such as the Norther n and the Baltic Seas. ENTSO-E's first TYNDP 
compiles a list of about 500 projects selected by national TSO's and identified as being of European significance because of their contribution to market integration, integration of renewables or security or supply
29. This list amounts to a total of about 42,100 km (35,300 
km new connections, 6,900 km upgraded connections). For new lines alone, this 
corresponds to doubling the annual extension of the currently operational European transmission grid, with a growth rate of about 1.5% between 2010 and 2020, compared to an annual average of 0.8% for the EU-15 during the period 1989-2003
30. This corresponds to an 
                                                 
28 EU Energy Trends to 2030: Update 2009 (Baseline 2009 and Reference scenario 2009). A detailed description 
of these scenarios and their assumptions is available at http://ec.europa.eu/energy /studies/index_en.htm . 
29 It must be stressed that this list does not include local, regional or national  projects, which are not considered to 
be of European significance. As many transmission grids were built in the 1950’s and 1960’s and near the end of 
their lifetime, important  additional investment needs will arise from the renewal or refurbishment of existing local, 
regional and national lines. 
30 "Lessons from Liberalised Electricity Markets", OECD/IEA 2005, p.145 
 
 18annual investment of about 3.3-4.7 bn € per year for projects of European significance. 
According to ENTSO-E's own calculations, these projects correspond to an overall 
investment need of 50-70 bn€31 for the period 2010-202532. According to KEMA calculations, 
these projects would need to be operational in 2020 to reach the 20-20-20 targets33. 
 As underlined by ENTSO-E, the first TYNDP does not take full account of needed infrastructure investment triggered by important new offshore wind
 generation capacities in 
the Northern Seas34. According to the national renewable energy action plans submitted by 
19 Member States in application of directive 2009/28/EC35, 2020 installed capacity is 
estimated at over 40GW, while 56 GW are needed according to the PRIMES reference scenario. According to calculations done by KEMA, this adds investment needs of about 32 bn€ for offshore connection infrastructure by 2020. In the medium term up to 2030, more offshore wind and development of solar energy
 generation capacities in Southern Europe 
and beyond will trigger further transmission grid development needs. According to KEMA 
estimates, overall offshore connection and cross-border interconnection needs could amount to an additional 18 bn€ in the period 2021-2030 under a PRIMES reference scenario with about 36% of renewables in gross electricity generation in 2030, or as much as 100 bn€ under a more ambitious High-RES scenario developed by KEMA with about 50% of renewables by 2030
36. 
 
Moreover, reaching the EU's energy efficiency and renewable targets might not be possible without more intelligent networks, based in particular on more demand side management 
and smart grid technologies . Digitised electricity grids enable two-way communication 
between suppliers and consumers and feature an intelligent monitoring system to track 
electricity flows in all directions. This will contribute to reducing network losses, increasing 
the reliability of the grid and allowing large amounts of variable renewable power to be connected to the grid. Moreover, smart grids will enable consumers to control appliances at their homes to save energy, facilitate domestic generation, reduce cost and increase 
transparency. The investment needs in smart grid technology to make networks "intelligent" 
as a whole and get the expected benefits out of 200 million smart meters has been estimated 
at 40 billion € by 2020
37. By 2030, total additional investment in smart grids deployment in the 
EU could reach 176 bn€, out of which 50 bn€ for smart metering, according to the final High-
                                                 
31 Note that transmission investment costs are highly s ensitive to technology choices. The investment cost for 
undergrounding cables, e.g. to reduce their environmental  impact, is typically 3 to 10 times higher than the 
investment cost for an overhead line or even more if specific structures are needed (Source: ENTSO-E and 
Europacable). 
32 By comparison, the average investment on all transmission infrastructure in the EU from 1996 to 2004 has 
been around 3.1 bn € per year. The largest part was devoted to substations (40%), internal lines (33%) and other 
assets (23%), such as telecommunication, protection an d control, and special equipment, while only 4% of the 
total has been devoted to cross-border lines, mostly for HVDC interconnections through submarine cables 
(source: TEN-Energy-Invest study). While the resulting incr ease in annual investment would be significant (up to 
over 50%), it is not expected to ov erstretch the absorption capacity of th e industry. On the one hand, TSOs are 
preparing themselves for this "wave" of investments over  the coming years. On the other hand, the supply chain 
is fully ready to answer such increased demand, as it  supplies already today significant volumes to strongly 
growing electricity transmission ma rkets in e.g. China or India. 
33 "The revision of the trans-European energy network policy (TEN-E)", chapter 3 
34 It is expected that the next  edition of the TYNDP planned for 2012 will take a more top-down approach, with a 
view beyond 2020, and address these shortcomings.  
35 Plans received and analysed as of 1st of September 2010 
36 It should be noted that these scenarios also have si gnificant impacts on both back-up capacity needs and 
operating costs. KEMA has calculated that additional generat ion investment of about 42 bn € would be needed by 
2030 under PRIMES reference to ensure current levels of  system reliability. Under High-RES, this investment 
would reach 93 bn €. This would however be compensat ed by lower total annual generation operating costs 
under High-RES 2030 (130 bn €) compared to PRIMES reference 2030 (160 bn €). Note that this calculation does 
not take into account costs for developing the correspond ing renewables generation capacity, which should be far 
higher than the related grid or back-up capacity investment. 
37  DG ENER calculations based on DG INFSO report "Impacts of Information and Communication Technologies 
on Energy Efficiency". The 80% target of Directive 2009/72/EC corresponds to equipping 200 million European 
households with smart meters. The cost for this  equipment amounts to another 40 billion €. 
 
 19Level Advisory Group on ICT for Smart 
Electricity Distribution Networks. The 
evolution towards smart grids faces 
multiple challenges, given the technology changes involved, the absence of harmonised standards and markets rules. Because of the uncertainties and high costs, no single one party is able to afford 
smart grid investment at transmission 
level on its own. Moreover, even if cost-benefit analyses in Member States show overall smart metering benefits, absence of appropriate regulation leads to unequal 
allocation of cost and benefits to the 
different parties in the value chain. In the medium term, new high-voltage long 
distance grid  technologies and new 
electricity storage  technologies will also 
be necessary. Uncertainties remain today as regards the potentials and risks of these 
different technologies. 
 The overall investment need for electricity networks (including offshore and smart grids) is estimated at 142 bn€ until 2020
38. However, the attainment of this target is currently highly 
unlikely because of the delays observed for the planning and authorisation of overhead 
electricity lines, because of uncertainties concerning technologies needed, planning 
coordination and cost-benefit allocation for offshore grids deployment, and because of uncertainties related to technologies, common standards and appropriate market models and incentive regulation for smart grids. It is estimated that only about 30% of the total investment needed would be delivered under a business-as-usual scenario. 
 
 Gas demand is highly dependent on energy policy choices. High uncertainty is surrounding 
the future of gas demand, as is demonstrated by the difference between various demand scenarios presented in Figure 2. While binding RES targets may crowd out gas fired generation (37% of gas demand in 2006) as base-load, they will also increase its role as 
back-up. At the same time, the development of new technologies, such as CCS, which is 
highly dependent on the price of emission allowances in the EU ETS, may increase the importance of gas in power generation. On the other hand, efficiency gains in buildings may reduce gas demand.  
The main challenge that gas infrastructure faces is the high and growing dependence on gas 
imports  (to reach about 73-79% by 2020 and 81-89% of consumption by 2030) mainly due to 
the depletion of indigenous resources. Based on the different scenarios, the additional import need ranges from 44 Mtoe to 148 Mtoe by 2020 and from 61 to 221 Mtoe by 2030
39 
(compared to 2005). Import dependency calls for sufficient and diversified import infrastructure from various sources. This development should be closely linked with the EU's 
strategy towards third countries.  
 
                                                 
38 The level of in-country, cross-border and offshore grid  infrastructure also determines additional back-up 
capacity requirements in the different  Member States. According to KEMA calculations based on PRIMES 
reference, additional generation investment based on the cheapest available flexible generation technology would 
amount to 18 bn € by 2020. 
39 For the whole section on gas, the lower figures refer to the PRIMES 2010 reference scenario, while the higher 
figures are derived from the Eurogas Environmental Sc enario published in May 2010, based on a bottom-up 
collection of the members' estimates. Gas demand
380430480530
2015 2020 2025 2030
Eurogas env Eur ogas  bas e
Ents og Primes baseline
P rimes reference95140 
Figure 2 , in Mtoe
 
 20In addition, the increase of electricity production from variable renewable energy sources 
requires additional flexible back-up generation . A large part of it is expected to be provided 
by gas-fired power plants. Given current interconnection and forecast error levels, Eurelectric 
estimates that 200 GW of installed wind capacity correspond to about 20-30 GW of back-up capacity needs. This increases the need for flexibility, such as LNG/CNG, more flexible use of pipelines and in particular gas storage  (both working volume as well as injection and 
withdrawal capacity), moving away from the tradi tional "injection in the summer, withdrawal in 
the winter" patterns.  According to some estimates, about 30-39 million cubic meters of 
annual working volume are needed to balance 1 GW of installed wind capacity in the 
absence of other measures (such as demand side management).  Thus the investment need for gas infrastructure in the coming decade has been estimated (according to internal calculations based on conservative gas consumption assumptions) to 
reach 71 bn€
40, including EU internal interconnectors (including reverse flows), new import 
infrastructure (pipelines and LNG) and storage requirements41. However, given the problems 
faced by these projects as outlined above, notably in terms of authorisation delays, 
insufficient market development, lack of cross-border coordination and economic viability, it is estimated that only about 80% of the corresponding projects would be delivered under a business-as-usual scenario. More details to the figures are given in Box 2 under chapter 5.1. 
 
 80% of imported crude oil is currently delivered to the EU by tankers. An important feature of 
the internal EU oil transport network is that the Western part is connected via pipeline to major European ports while most of the refineries in Central and Eastern Europea (EU12) 
are supplied through the Druzhba oil pipeline system from Russia (about 60 million 
tons/year). There are limited connections between the Western European pipeline network and the eastern infrastructures. This is a consequence of the fact that the Eastern European pipeline network (an extension of the final part of the Druzhba pipeline) was conceived and built during the Cold War period and had, at that time, no pipeline link with the western 
network. Moreover, in these countries, unlike in the EU15, the oil demand is expected to 
grow by 7.8% between 2010 and 2020 (see Error! Reference source not found. ). In case 
of supply disruptions in the Druzhba system, the limited alternative supply options would lead to a big increase in tanker traffic in the environmentally sensitive Baltic area
42, in the Black 
Sea and in the extremely busy Turkish Straits43, creating big concerns about the potential 
danger of accidents and oil spills. This puts pressure to develop oil pipeline infrastructure to 
ensure security of supply in this region. 
 CCS  is a novel technology, which comprises the capturing of CO2 at emission points, its 
transportation and underground storage in suitable geological formations. To date, the implementation of CCS has been limited to pilot plants and the first large-scale 
demonstration projects are under development to be deployed around 2015 supported by 
Community funds, the New Entrants' Reserve of the EU Emissions Trading Scheme (the so 
called "NER300 initiative"
44), state aid and contributions from developers. The Commission's 
                                                 
40 The investment need may range from about 50 to 89 bn € based on various factors described in Box 1.  
41 ENTSOG is currently elaborating on th e investment need for the coming ten years to be included in their next 
TYNDP to be published in December 2010. To date, thei r non exhaustive analysis (work in progress) has 
estimated about 41 bn € of identifi ed investment need. The above menti oned figures have been checked also 
against available (partial) studies. 
42 The Baltic Sea today is one of the busiest seas in the world, accounting for more than 15% of the world’s cargo 
transportation. Each month 3,500-5,000 sh ips cross the waters of the Baltic Sea. Approximately 17-25% of these 
ships are tankers transporting approximately 170 million tonnes of oil a year. 
43 The Turkish Straits comprise the Bosporus and Dardanelles. Less than a kilometre wide at their narrowest 
point, the Turkish Straits are one of the world's most difficult waterways to navigate, due to their sinuous 
geography. With 50,000 vessels, including 5,500 oil tanker s, passing through the straits annually, they are one of 
the world’s busiest and most dangerous chokepoints. 
44 Cf. article 10(a) 8 of the revised Emissions Trading Directive 2009/29/EC 
 
 21ambition, supported also by the Council, is to have up to 12 such plants. The demonstration 
projects will include integrated value chains consisting of CO2 capture installations, transport 
and storage infrastructure. The use of pipelines is widely considered to be the most reliable 
for long-term bulk movement of CO2. Whilst storage capacity in Europe is plentiful, it is not evenly distributed geographically and in some cases distant from significant emission sources. Moreover, some EU Member States, considering their significant levels of CO2 
emissions, have limited potential storage within their state boundaries which calls for cross-border transport infrastructure. The development and marketability of CCS technologies – 
and hence the need for a CO2 transportation network - are highly dependent on the CO2 
prices. This is shown in the PRIMES reference scenario (lower CO2 prices due to lower demand for emission permits due to higher share of RES and more energy efficiency in the 
system) where the share of CCS use in power generation is only 1.4 % in 2030 corresponding to 37.6 Mt of captured CO2. The PRIMES baseline with higher carbon prices 
allows for more CCS development reaching 8.7% of power generation in 2030
45.  
 
Without intervention, CO2 pipelines installed during 2014-2020 will be relatively short in length, associated with specific projects and therefore tailored to their needs. They will also rather remain geographically remote (i.e. unconnected) from one another. For the period beyond 2020, technology experts expect a commercial rollout of CCS in lead countries 
followed by a global rollout of CCS after 2025. Beyond 2030, the need for CO2 transport 
infrastructure could be even more important due to the expected share of CCS in the energy supply mix. This implies a need for early in frastructure development and advanced capacity 
investment, despite current low price of emission allowances due to the economic crisis. As the results of recent private sector analysis show, it is still more economical to oversize the 
pipelines initially and wait around 10 years until the spare capacity is fully utilised than to 
build pipelines fit for one emission point and one CO2 sink
46. 
 The CO2 infrastructure investment need has been estimated by the JRC at about 2.5 bn€ until 2020. Under a business-as-usual scenario, i.e. without creating the necessary 
conditions for the early deployment of a European CO2 infrastructure network adapted to 
future needs, it is estimated that no significant investment will take place.  Moreover, the increased interconnection of energy networks and the use of advanced information technologies represent additional c hallenges in the event of external events, 
such as those resulting from natural hazards and human-made malicious threats. The 
aspects of physical protection of infrastructures, their interoperability under disrupted 
conditions, and coordinated planning of cont ingencies will need to be addressed with a 
European dimension in every future development of energy infrastructures as they are key 
factors in the overall resilience of the energy supply system.  
As a result, the overall investment need
 amounts to 215.5 bn€ (142 bn€ electricity, including 
interconnections, offshore connections and smart grids; 71 bn€ gas, out of which 14 bn€ of investment outside the EU; 2.5 bn€ CCS). Taking into account assumptions on business-as-usual market and regulatory conditions determining the commercial viability of projects (see chapter 2.4.2) and delays for project implementation in each sector (electricity, gas and CO2) (see chapter 5.1 and Annex 3 for more details), one can estimate the business-as-usual 
investment: it would reach in electricity and gas 102 bn€ over the period 2010-2020 (45 bn€ 
electricity, 57 bn€ gas). No significant investment would take place for the CO2 transport infrastructure as identified in the JRC and ARUP studies.. 
                                                 
45 It must be noted that projections up to 2050 can feature significant chan ges to these prices, depending on the 
scenario chosen. 
46 Pre-FEED (front end engineering and feasibility) studies on industrial-sca le carbon capture and storage (CCS) 
demonstration projects in the United Kingdom (2009) 
 
 222.4.2.  Infrastructure delivery under current market, regulatory and financing conditions 
Electricity and gas infrastructure in Europe are regulated sectors, whose business model is 
based on regulated tariffs collected from the users, which allow recovering the investments 
made (“user pays principle”). The regulatory framework for infrastructure (including planning 
and investment) has evolved through the 3rd internal market package for electricity and gas 
that was adopted mid 2009, to be implemented by mid 2011. It enhances the separation ("unbundling") between transmission and supply activities. On the one hand, this may translate into more difficulties for TSOs to forecast future demand and no more possibilities of cross-subsidies. Thus regulated tariffs and congestion rents are the only way to recover 
costs. On the other hand, effective unbundling will give them more independence and 
increase their incentives to better plan infrastructure investment. The new transparency guidelines will lead to better information within the market, thus to possibly more available capacity for shippers in the case of gas, more optimal use of infrastructure and better signals on congestions where TSOs should invest in additional infrastructure. Generally, a more 
efficient market should provide better price si gnals: price differentials will indicate where 
additional or new interconnection capacities are needed within the European network.  The third package provides for new rules in terms of infrastructure development across borders, which will facilitate the implementation of grid investments in electricity and gas: 
 
• The third package establishes new rules for national regulatory authorities to cooperate 
on cross-border issues, including operational arrangements, networks codes and 
congestion management
47. For electricity only, provisions are made as regards an inter-
transmission system operator compensation mechanism for costs incurred as a result of hosting cross-border flows, which should clarify the sharing of costs and benefits for a given cross-border infrastructure
48. ACER will intervene in particular to establish and 
monitor implementation of network codes, to coordinate regulatory differences affecting 
cross-border infrastructure and to monitor the implementation of interconnection 
projects49. Notably the new rules on inter-TSO compensation, which are in the final stage 
of the comitology procedure, are expected to facilitate the implementation of needed grid investments. 
 
• The new ENTSOs for electricity and gas will facilitate co-operation and co-ordination 
between TSOs, notably for investment planning. The first European TYNDPs are based 
on a bottom-up approach and were successful in consolidating existing projects in one 
single document, thus giving more transparency to network planning. However, they do not provide a top-down vision suited to identify all future infrastructure gaps as a consequence of the new energy and climate policy challenges. More top-down oriented second versions of the European TYNDPs will be published in December 2010 for gas and in 2012 for electricity, giving the start for bi-annual revisions. These plans are 
ultimately expected to deliver a longer-term vision and setting strategic priorities for future 
development. 
 
• While the third package gives the necessary powers to national regulators to ensure 
implementation of investments foreseen in the binding national plans
50, no provision is 
made to ensure implementation of the Eu ropean TYNDPs, which are non-binding plans51. 
However, the third package does require that national plans are consistent with the 
European TYNDP and gives the Agency a monitoring role in this respect. Enforcing 
                                                 
47 Cf. article 38 of Directive 2009/72/EC and article 42 of Directive 2009/73/EC 
48 Cf. article 13 of Regulation (EC) No 714/2009 
49 Cf. articles 6 and 8 of Regulation (EC) No 713/2009  
50 Cf. articles 22 of Directive 20 09/72/EC and Directive 2009/73/EC 
51 Cf. articles 8 of Regulation (EC) No 714/2009 and Regulation (EC) No 715/2009 
 
 23realisation according to the planning and timing foreseen will be impossible for certain 
projects listed as being of European interest. 
 
The third package also asks national regulators to provide appropriate tariff incentives, both short and long term, for network operators to increase efficiencies, foster market integration and security of supply and support the related research activities
52. Although regulators 
furthermore will have an obligation to take into account the impact of their decisions on the internal EU internal market as a whole,  still, tariff setting remains national competence and 
hence not always conducive to advance European priorities.  
Furthermore, this regulatory approach is not designed to address the major technological changes, notably in the electricity sector, concerning offshore or Smart Grids. 
 
 As demonstrated above, the measures adopted and,  for many, still to  be implemented will 
not be sufficient to ensure full delivery, given the lack of regulatory solutions to allocate costs 
and cross-border benefits and especially the obstacles identified in chapter 2.3. They will resolve some coordination issues for simple cross-border projects. However, they may not provide sufficient incentives for investments in public goods – e.g. gas reverse flow or storage for security of supply – or projects with information asymmetry – e.g. new technologies or innovative solutions (interconnected offshore grids, smart grid applications) 
or cross-border projects with complex cost and benefit allocations involving several 
countries, notably in gas, where no inter-TSO compensation or any other mechanism to allocate costs for domestic investment to final beneficiaries outside the domestic territory has been established. Moreover, while the energy and climate policy goals adopted at EU level and the corresponding support schemes for renewable energies do speed up their 
development, they have also a distorting effect, notably on the internal electricity market. 
Finally, they are currently not matched by corresponding measures for infrastructure development to ensure adequate grid integration.  Finally, both the internal markets for electricity and gas are still incomplete, partly due to 
missing infrastructure
53. Eastern Europe has inherited East-West gas infrastructures with little 
or no interconnections between neighbours. As t he gas crisis in January 2009 showed, lack 
of infrastructure and insufficient transmission capacity were the main barriers to the handling of the crisis
54. The new regulation on security of gas supply has just introduced a compulsory 
"N-1" rule for infrastructure, meaning that all Member States should be able to compensate the disruption of the single largest infrastructure by the remaining other infrastructures to 
ensure that total gas demand is met. An obligation to implement reverse flows was also set. 
In order to meet these standards, additional infrastructure needs to be constructed. However, such projects will not always be bankable under a business-as-usual scenario.  In addition to traditional private financing on the basis of regulated tariffs, EU-funded support 
has been granted to current TEN-E projects through a number of instruments, such as the 
TEN-E budget, EEPR, IPA, ENPI (such as NIF or INOGATE) and loans from EIB and EBRD (see Annex 2 for more details). Under current rules – valid until 2013 –, EU TEN funding will continue to give small grants to finance feasibility studies or riskier projects, which may have an important EU-wide benefit. Interest rate rebates figure in the Regulation, but have never been used as they may have a market distorting effect. Projects that are not commercially 
viable but that may be important for other reasons (security of supply, market integration, 
                                                 
52 Cf. article 37 of Directive 2009/72/EC and article 41 of Directive 2009/73/EC 
53 In electricity, interconnections have historically been good between Eastern European Member States, which 
used to be connected synchronously among each ot her and with the Russian power system. Following 
disconnection from the Russian system and connection to t he synchronous grid of continental Europe (i.e. the 
grid of the Union for the Co-ordination of Trans mission of Electricity / UCTE) in 1995, interconnections between 
East and West have developed (e.g. between the Czech Republic or Poland and Germany), but certain 
bottlenecks remain as of today. 
54 SEC(2009)979 
 
 24new technology or innovative solution), would not be constructed. In addition, the current 
policy does not address permitting issues, market or regulatory failures, the mismatch 
between national and European priorities and the need for strong political support. This 
would lead to insufficient infrastructure devel opment. Finally, oil and CCS infrastructure as 
well electricity storage and smart grid technologi es would remain excluded from the policy. 
No new electricity/gas projects would be added to the current list, non feasible or outdated ones could not be removed.  
Concerning CCS, integrated backbone pipeline networks would probably be the most 
efficient long-term option, but the incremental cost of building optimized networks ahead of point-to-point pipelines may not satisfy project-specific commercial evaluation criteria. Concerning oil, the current supply situation, in particular with regard to Central and Eastern Europe, is satisfactory. If the uninterrupted and smooth flows from Russia through transit 
countries could not be ensured in the future, alternative supply routes would have to be 
explored, either through existing infrastructure  (Odessa-Brody pipeline in Ukraine or Adria 
pipeline in Croatia) or through new West-East interconnections. However, the corresponding investments, which would then become necessary, are limited
55. They are not regulated by 
EU legislation concerning e.g. rates of return or third-party access to infrastructure.  
2.5. Main geographical bottlenecks 
In the business as usual scenario, the main bottlenecks would occur in the below listed 
regions or domains, as a result of the observed future energy trends, infrastructure needs and combination of several of the identified obstacles:  
BEMIP (Baltic Energy Market Interconnection Plan) 
The three Baltic States – and in terms of gas also Finland – are practically isolated from the 
EU energy markets. In electricity, the Baltic  energy grids are synchronously connected to the 
Russian UPS (Unified Power System). As of today, there is only one asynchronous interconnection to the West between Estonia and Finland. New connections are planned with Finland, Sweden and Poland, but not yet all realised. In gas, all four countries depend on a single supplier, and in most cases through one import route, which raises security of supply 
concerns. This same supplier also has a stake in the TSOs of the countries. With no real 
functioning market, cross-border and additional import infrastructure needs (such as LNG) to improve market integration and security of supply cannot be met by market demand. Coordination between Member States, TSOs and regulators is necessary in order to align regulatory approaches – a barrier for further investments and market opening – that would allow a fair distribution of regional infrastructure development costs as well as benefits. 
Offshore grid in the Northern Seas 
Offshore wind is expected to be an important  means to reach the EU’s 20% renewable 
target. Potential for this energy source is mainly in the North Sea and neighbouring waters. At the same time, there is also an increased need for interconnection capacities between countries in the North (e.g. Norway, Sweden) and Central Europe (e.g. Germany, the Netherlands), both for more electricity trade and enhanced security of supply. This creates 
the need for an integrated offshore grid solution both to connect large amounts of offshore 
wind and ocean energy capacities and to function as an international interconnector. The creation of such a new grid is subject to several important challenges: coordination among Member States and entities in charge of planning and execution (ministries, 
                                                 
55 Concerning existing infrastructure, the cost for upgradi ng the Odessa-Brody pipeline capacity from 14.5 to 33 
million tons per year (mta) was estima ted at about 450-500 million euros, wh ile upgrading the Adria pipeline from 
9.8 to 14 mta would add another 70 million euros. Concer ning new West-East interconnections, the Schwechat-
Bratislava pipeline for example would require about 50 mi llion euros investment for up to a capacity of 5 mta. 
(calculations done by ILF and Purvin&Gertz). 
 
 25regulators, TSOs, developers etc.); designing a new regulatory scheme; defining appropriate 
market rules for multilateral investments; developing appropriate technical standards and 
operational solutions. 
So far, Member States have adopted different approaches to develop their national offshore wind potential and the corresponding grid. National regulation encourages radial connections of wind farms with an onshore connection point, to maximise benefits while minimising 
project risks and costs (see  Annex
 4 for more details). Under these conditions, projects 
using innovative but riskier technologies (e.g . offshore voltage source conversion) and new 
grid designs involving more than two countries are difficult to realise, preventing further 
cross-border optimisation. Moreover, individual planning and building of wind farm 
connections makes the anticipation of future development needs difficult, which might lead to increased overall cost and environmental impact in the long term. Integrated solutions such 
as a meshed offshore grid, associated with appropriate cost-benefit allocation mechanisms, are lacking, preventing the full benefits of both renewables connection and electricity trade to 
realise
56. 
Such a grid will only be possible with strong regional or even European level coordination and planning and the necessary technological developments (notably concerning direct current (DC) breakers and multi terminal control systems). The need for this coordinated approach has been identified by the countries that are participating in the North Sea 
Countries Offshore Grid Initiative (NSCOGI)
57. It is finally important to note that this offshore 
grid development, together with the onshore wind development near to the coasts, will trigger major interconnection requirements with existing and new generation and hydro pumping capacities both in the North (Norway, Sweden) and the Alpine region (Austria, Switzerland). 
Renewables in Southern Eu rope and the Mediterranean 
In the Southern countries of the EU, solar energy will offer important new generation 
capacities, notably in France, Italy, Portugal and Spain. The role of solar electricity could still 
increase, if additional generation in Mediterranean third countries is imported into the EU 
through interconnections between Morocco and Spain or Tunisia and Italy. As for wind energy in the North, these new capacities will trigger major grid reinforcement and new interconnection investment needs in this region, especially concerning the Spain-France and the Italy-France, Italy-Switzerland and Italy-Austr ia links. As recent experience has shown, 
development of additional cross-border infras tructure in the regions has faced major 
difficulties in reaching public acceptance, leading to lengthy authorisation procedures and costly solutions. Concerning interconnectors  between the EU and third countries, problems 
arise from the often complex political situation. In addition, questions remain concerning the applicable regulatory framework. 
New supply sources – Southern Corridor 
The objective of the development of the Southern Corridor is to further diversify sources and 
to bring gas and oil from the Caspian Basin and the Middle East to the EU. The projects in 
the Southern Corridor face on one hand the necessity of coordination between several Member States and with non-EU members, the es tablishment of a legal regime to transport 
gas through these territories and on the other hand the challenge to co-ordinate the timings to develop the up-stream resources and necessary infrastructure with the timings of the 
import infrastructure projects. At the same ti me, this is also the opportunity for the European 
Union to enter closer energy partnership with Central-Asian and Middle-East countries. 
                                                 
56 Currently the analysis is not done at regional or European  level, where these synergies could be identified. An 
integrated interconnector / offshore wind connection solution might cause different proportion of costs and 
benefits for the different actors.  
57 In December 2009, the Po litical Declaration of the NSCOGI was si gned by 9 Member St ates (Belgium, the 
Netherlands, Luxembourg, Germany, France, Denmark, Swed en, the UK and Ireland). Norway joined the initiative 
in early 2010. The 10 countries are aiming at signing a Memorandum of Understanding by the end of 2010. The 
mission of the NSCOGI is to facilitate coordinated offshore  electricity infrastructure  development with a joint 
commitment in view of large offshore wind power development in the region. 
 
 26Central and South-East European interconnections 
Concerning gas, Central and Eastern EU countries, as well as South-East Europe (Energy 
Community countries) often depend on one sing le import source and hence limited, weak 
competition. Furthermore, they often depend on one single pipeline infrastructure both for oil 
and gas. Practically all of the problems identified in chapter 2.3 converge in this area: no complete implementation of internal energy market rules, missing infrastructure development due to lack of market development and vice versa, the lower creditworthiness of local companies due to their lower capitalisation, the effects of the economic crisis (thus deteriorating country risk ratings) and the higher exposure to external transit or supply risks. 
Furthermore, the investment need to meet the infrastructure standards set out in the security 
of gas supply regulation is very high in this region compared to the investment capacity of the concerned countries/companies, given current tariff levels and households’ ability-to-pay. 
Concerning electricity, challenges arise from the evolution of power flows and the need for further market integration in the countries of  the region. North-South flows will rise in 
importance as new generation in Bulgaria, Hungary or Croatia will get connected to the 
network. East-West interconnections could need reinforcement, as new systems (Turkey, but also Moldova and Ukraine) join the continental synchronous system. Moreover, these systems will have to be connected to the domi nant storage capacities in the Alpine region. 
 
2.6. Key players and affected population 
Various actors in the energy sector and beyond are affected by the proposal: 
• Transmission and distribution system operators will be first and foremost affected, as any 
new initiative will touch upon planning and realisation of new transmission infrastructure; 
• Operators and developers of existing and new power plants (including CCS) and 
electricity and gas suppliers, as a new policy will have an impact on the evolution of grid 
capacity; 
• Member State governments, administrations and regulators who will be in charge of 
implementing any new rules related to tariff regulation, financing, planning and permitting; 
• Energy consumers, as optimised and smarter grids will contribute to better balancing of 
supply and demand and hence to reduced and less volatile energy prices; 
• Citizens in the neighbourhood of new infrastructure, that might be affected temporarily 
(construction) or permanently (local env ironmental or visual impacts etc.); 
• EU citizens at large, as a new policy will contribute to making the energy system more 
reliable, competitive and sustainable in terms of environmenta l and climate impacts. 
 
2.7. EU right to act 
Under Article 194 TFEU, Union policy on energy shall aim at: (a) ensure the functioning of 
the energy market; (b) ensure security of energy supply in the Union; (c) promote energy efficiency and energy saving and the development of new and renewable forms of energy; 
and (d) promote the interconnection of energy networks. Energy transmission infrastructure 
(including an interconnected off-shore grid and smart grid infrastructure) has Trans-European, regional or at least cross-border nature or impacts. Member State level regulation is not suited and individual national administrations have no competence to deal with these infrastructures as a whole. They are therefore covered under Article 170 and 171 TFEU. 
Article 170 specifies that “the Union shall cont ribute to the establishment and development of 
trans-European networks in the areas of transport, telecommunications and energy infrastructures”. Article 171 sets the obligation that “the Union shall establish a series of guidelines covering the objectives, priorities and broad lines of measures envisaged in the sphere of trans-European networks; these guidelines shall identify projects of common interest”. 
 
 
 27The Second Strategic Energy Review proposed that a new EU Energy Security and 
Infrastructure Instrument should be tabled to replace the existing TEN-E framework (policy 
and financing). At its extraordinary session in January 2009, the Transport, 
Telecommunications and Energy Council invited the Commission to "to carry out a thorough assessment of network interconnection, identify gaps, suggest action and to speed up the revision of the TEN-E framework with a view to considering the development of a comprehensive EU Energy Security and Infrastructure Instrument as suggested in the 2nd Strategic Energy Review." At its March 2009 summit, the European Council concluded that 
“Energy infrastructures and interconnections must be developed. To that end, the 
Commission, in cooperation with Member States, is invited to rapidly present the detailed actions required to realise the priority areas identified in the SER. […] The Commission is invited to present […] its proposal for a new EU Energy Security and Infrastructure Instrument.” This instrument will be dealt with in a legislative proposal following a 
communication on energy infrastructure priorities. 
 Moreover, the Second Strategic Energy Review stated that "a Blueprint for a North Sea offshore grid should be developed to interconnect national electricity grids in North-West Europe together and plug-in the numerous planned offshore wind projects."
58 In the 
conclusions of the Energy Council on 19 February 2009, the plans for the blueprint were 
endorsed with the small change that the scope was changed from North Sea to "the North 
Sea and North West Offshore Grid", thus clearly covering also the Irish Sea. In its conclusions, the Council also agreed to "promote a co-ordinated approach between Commission and Member States, where appropriate, in order to support in a cost effective way large scale deployment of offshore wind power in the European seas while preserving 
the reliability of the grid". 
 More recently, the Europe 2020 strategy
59 put again energy infrastructures in the forefront as 
part of the flagship initiative "Resource efficient Europe". It underlined the need to urgently upgrade Europe's networks towards a European "smart" supergrid, interconnecting them at 
the continental level, in particular to integrate renewable energy sources. It also highlighted 
the need to promote infrastructure projects of major strategic importance to the EU in the Baltic, Balkan, Mediterranean and Eurasian regions.   
3. OBJECTIVES  
 
The general objective of the initiative is to ensure sufficient and timely infrastructure 
development across the EU  and beyond  in order to: 
• further develop the internal energy market so  as to ensure reliable energy provision at 
affordable prices to European customers,  
• ensure security of supply, 
• meet the EU’s energy and climate targets. 
 
In order to sustain infrastructure development, its main hindrances are to be tackled. The planned Communication on infrastructure priorities hence has the objectives to propose clear priorities and improve focus of EU action for all relevant energy infrastructure, reinforce 
regional co-operation and coordination, highlight the difficulties linked to permitting 
procedures and build public acceptance to help reducing planning and permitting 
uncertainties. Clear infrastructure priorities will also provide a political message towards third countries.   
                                                 
58 COM(2008) 781 p. 5 
59 COM(2010) 2020, 3.3.2010  
 
 28The abovementioned objectives are fully in line with the Europe 2020 strategy and in 
particular the "Resource efficient Europe" flagship initiative and support directly the 
achievement of the two binding targets of 20% share of renewables and 20% of greenhouse 
gas emission reductions by 2020. In addition, the uptake of smart grid technologies directly promotes energy efficiency. The objectives are fu rthermore consistent with the EU policies 
on competitiveness and innovation.  The objectives explained above are consistent with the Commission’s on-going work to 
outline possible roadmaps for a transition to a low-carbon energy system by 2050. While the 
development of electricity and CO2 transport infrastructure is recognised as a key factor for success under almost any future scenario, uncertainties concerning future gas and oil demand do not reduce the need for infrastructure development in the near term future
60. 
 
 
 
4. POLICY OPTIONS  
 
In order to better analyse solutions to the main problems identified above, it is suggested to split the analysis in policy areas and propose separate options for each area (see Table 1). 
The policy options are evaluated against the criteria of effectiveness, subsidiarity and 
proportionality. The main criterion for effectiveness is how much adequate infrastructure investment the single options are likely to deliver. All the options are coherent with the overarching EU objectives, strategies and priorities. Based on this evaluation, the most effective and efficient options will be combined into a preferred policy set.  
 
Policy area A: Scope of the policy instrument 
Option 1: Business as usual (electricity and gas)  
Option 2: Enlarged electricity and gas 
Option 3: Enlarged electricity and gas, inclusion of CO2 networks and oil pipelines  
Policy area B: Design of policy instrument  
Option 1: Business as usual (project lists as today) Option 2: Updated project list 
Option 3: Limited number of priority projects/regional corridors and smart selection criteria Policy area C: Coordination  
Option 1: Business as usual (national approach, EU coordinators), voluntary regional 
structures 
Option 2: EU coordinators and mandatory regional or thematic priority structures Option 3: EU TSO 
Policy area D: Permitting 
Option 1: Business as usual (national competence), exchange of best practices  
Option 2: Inclusion of projects of European interest in national priorities and application of 
fastest national procedure (where existing) 
Option 3: National one-stop-shop approvals with streamlined time limits (5 years) 
Option 4: New harmonised permitting scheme at the EU level 
Table 1: Policy options  
                                                 
60 Indeed, while the evolution of gas demand is uncertain until 2030 and ev en more so until 2050, gas is expected 
to have an increasing share until 2020, which is unlikely to drop dramatically after 2030  from a projected share of 
22.4%-24.3% of total energy demand under the PRIMES reference scenario, especially if carbon capture and 
storage technologies develop. Similarl y, the projected oil share of aro und 32% by 2030 is unlikely to drop 
drastically, especially considering its slow substitution in the transport sector.  
 
 29 
 
4.1. Policy area A: Scope of policy instrument 
All proposed options in this policy area are considered to meet the subsidiarity and 
proportionality principles.  Option 1: Business as usual: electricity and gas
 
This option would cover electricity, gas and olefin transmission infrastructure, gas storage 
and liquefied natural gas (LNG) infrastructure, as is the case with the current TEN-E policy. 
 
Option 2:  Enlarged electricity and gas  
Under this option, the electricity infrastructure targeted would be enlarged to cover also smart 
grids and storage projects, in addition to the traditional transmission projects. Compressed natural gas (CNG) infrastructure would be added under the targeted gas infrastructure. This 
option can in principle be combined with all options of policy areas B, C and D. 
 Option 3: Enlarged electricity and gas, inclusion of CO2 networks and oil pipelines
 
This option would include electricity transmission, storage as well as smart grid technologies; 
gas pipelines, storage, LNG and CNG, as is the case in option 2. But it would also cover both 
CO2 transportation and oil pipeline infrastructure, thus overall energy transport infrastructure. 
This option can in principle be combined with all options of policy areas B, C and D. However, oil pipelines could a priori not be treated under option C3 (EU TSO, see below), as they are privately operated without central management through an independent TSOs. 
 
4.2. Policy area B: Design of policy instrument 
All proposed options in this policy area are considered to meet the subsidiarity and 
proportionality principles. 
 
Option 1: Business as usual  
The “business as usual” option would mean to continue with the TEN-E policy as it is, 
including the current project list divided into three categories and re-confirmation of the existing priority axes.  
 
Option 2:  Updated project list
 
Option 2 would mean to continue with the general TEN-E policy, but to revise and update the 
priority projects defined in the annexes of the decision and to possibly enlarge the scope 
under options 2 or 3 of policy area A (through ordinary legislative procedure). New projects 
would benefit from political support and an EU label, as is the case in the current TEN-E policy.  
Option 3:  Limited number of priority projects/r egional corridors and smart selection criteria
 
This option would propose new broad priority areas and regional corridors of European 
interest, focusing on the main bottlenecks identified (see chapters 2.4 and 2.5), thus not 
fixing a list of projects beforehand. These broad priority corridors would be complemented 
with smart and transparent criteria for identifying projects in need of more focused attention at the regional or EU level. The approach is based on a European top-down (thematic or regional) perspective rather than on individual projects. This differs from the current approach laid down in the TEN-E guidelines, where the list of projects is fixed in the Annexes and has been identified bottom-up, reflecting Member States' national priorities. The criteria 
for the identification of projects should be based on the following principles and further 
 
 30discussed and refined with relevant stakeholders, so that the more detailed criteria can be  
included in the future legislative proposal61. 
Principles to be applied in the electricity sector would cover the major objectives of EU 
energy and climate policy: (1) contribution to secu rity of electricity supply; (2) capacity to 
connect renewable generation and transmit it to major consumption centres; (3) increase of market integration and competition; (4) contribution to energy efficiency and smart electricity use. The principles suggested for gas infrastructure are derived from the objectives of the EU 
energy and climate policy to improve secu rity of supply and market development: (1) 
diversification, giving priority to diversification of sources, counterparts and in last place routes; (2) ratio of increase in interconnection level; (3) reduction of market concentration. 
 
4.3. Policy area C: Coordination 
Option 1:  Business as usual  
This option would continue the current approach based on largely national initiatives, with 
support from EU coordinators and voluntary regional structures for certain projects. 
 
Option 2:  EU coordinators and mandatory regional or thematic priority structures  
While maintaining the involvement of EU coor dinators, existing regional structures would be 
given the task of identification of concrete priority projects and implementation and monitoring of infrastructure priorities in a given region or sector, with the involvement of all relevant stakeholders (national administrations, National Regulatory Authorities, NGOs and TSOs). A compulsory framework would ensur e that there is a regional view and that 
approaches do not remain fragmented at national level. The identification of the priorities 
would be linked to the criteria referred to under option B3. 
There is already mandatory regional co-operation in the framework of the internal energy market rules (second and third package) in various areas: regional 10-year network development plans shall be prepared by the TS Os and national regulatory authorities co-
operate within the “regional initiatives”. The Regional Initiatives are currently under revision 
and a new proposal is expected in 2011. The ov erall EU optimum would be ensured through 
the already existing EU-level institutions such  as ACER, the ENTSOs and regulatory for a. 
Building on the positive example of the BEMIP  or the NSCOGI, the Commission may support 
ad-hoc regional co-operation on request, such as the Visegrad+ initiative to implement North-South interconnections in Central-Eastern and South East Europe. This solution would simplify the cooperation, build on synergies with other discussion areas (defined in the third 
package) and reduce the number of fora and meetings for all stakeholders. The constitution 
of regional initiatives under this option will be closely linked to the identification of priorities under policy area B.  
Option 3:  EU Transmission System Operator
 
The idea of a single European TSO for gas was raised by a group of EU gas companies and 
outlined also in the Green Paper. The European Parliament concluded that " forward-looking 
initiatives, such as the European transmission system operator and the establishment of a 
single European gas network, should be encouraged "62. The aim could be to build 
progressively independent companies to manage unified transport networks throughout the EU in gas, but also in electricity or CO2. The progressive merging of national networks, provided that it is organised in a manner co mpatible with competition law, would allow 
looking at network development from a truly EU  perspective and enhance incentives to invest 
in infrastructure where it is needed regardless of national boundaries.  
                                                 
61 As long as these detailed criteria have not been elab orated, an estimation of the precise number of projects 
qualifying or not qualifying under the new regime is not possible. 
62 European Parliament resolution of 3 February 2009 on the Second Strategic Energy Review (2008/2239(INI)) 
 
 31An EU TSO would facilitate more regulatory and technical standardisation and thus allow 
energy to cross borders more easily. This could lead to a situation where national regulators 
would not any more be capable to regulate transmission. A European regulator would be 
needed – a future role that could be played by ACER. Such a solution would also allow introducing “European transmission tariffs” to cover the TSO’s costs (and wider EU benefit). In the case of electricity, such a TSO could also be charged with the design and implementation of integrated offshore grids or new European high-voltage long distance grid. For CO2, this would also allow the up-front planning of an optimal CO2 network. 
These single EU TSOs would have to take into account all objectives of the EU energy policy 
(market integration, security of supply and the climate goals). An EU TSO would become a monopoly and have a huge asset base. This would increase its creditworthiness and capacity to invest. To be a truly EU TSO, it should be given exclusivity over infrastructure development in the EU, wh ich would eliminate the possibility for other 
market players to construct "merchant lines" dedicated to trade, where the owners reserve all 
or part of the capacity for their own use. Past experiences for strong monopolies demonstrate, however, that such a TSO would need to be closely regulated and monitored with full transparency in order to make sure that transmission costs are correctly allocated to the users and to prevent abuse of its dominant market position. No individual supplier should be allowed to acquire a controlling stake in the EU TSO in order to maintain its neutral 
position and non-discriminatory approach on the market. 
It is also considered that the process towards an EU TSO may rather take place on a progressive and voluntary basis and that the Treaty does not provide the powers to impose this solution. This solution furthermore is unlikely to respect the principles of subsidiarity and proportionality, as strengthened or mandatory regional co-operation and infrastructure 
planning may lead to similarly effective results. Therefore this option is discarded from further 
analysis.  
 
4.4. Policy area D: Permitting 
Option 1:  Business as usual: national competences, exchange of best practice  
In this option (current TEN-E approach), national competences would be maintained, their 
obligation being to make best efforts to facilitate implementation of identified TEN-E infrastructure. They would be enhanced through the publication of national best-practice measures. Member States would apply these measures on a voluntary basis.  
Option 2:  Inclusion of projects of European interest in national priorities and application of 
fastest possible procedure (where existing)  
This option  would oblige Member States to include projects declared to be of European 
interest (PEI)63 in their national priorities and to apply the fastest existing authorisation 
procedure (where these exist). The principles of subsidiarity and proportionality would be 
respected as this option does not provide for concrete procedures, which would be left to the Member States. This policy option would be applic able only in Member States where national 
priorities have been defined and where “fast-track” procedures exist. In the other Member States, “business as usual” would be maintained.  
 
Option 3:  National one-stop-shop approvals with streamlined time limits
 
The Presidency of the European Council invited the Commission in March 2007 " to table 
proposals aiming at streamlining approval procedures "64, and industry expressed the need 
for EU measures to facilitate permitting procedures. This option would introduce a "one-stop-shop" permitting scheme for projects of European interest, under which all Member States 
                                                 
63 NB: The definition of "project of European interest" c ould be revised and does not necessarily correspond to the 
currently used definition in the TEN-E guidelines. 
64 See European Council Presidency Conclusi ons of 8/9 March 2007, 7224/1/07 REV 1 
 
 32would have to nominate a national contact authority. It would be left up to Member States, 
whether this authority would have decision making powers or be a coordination body where 
decision-making competence would remain with the competent authorities at national, 
regional, and/or local level. The one-stop shop would serve as a single interface between the project developer and the competent authorities. It could include more detailed objectives and specify the procedures to implement, including guidelines for public consultations, for minimum transparency requirements and for com pensation of affected populations, as well 
as tacit approval or sanction mechanisms in ca se of delays. This option may ideally introduce 
a time limit of 5 years
65 for a final authorisation decision to be taken by the competent 
authority for a given project, feasibility of which still would need further assessment. The introduction of a one-stop-shop would fac ilitate administrative procedures for project 
developers, and a time limit would lead to accelerated authorisation and more certainty in the process. Such an option would also apply to all Member States, not only to those where 
national strategies exist. Effects could further be enhanced by more specific guidelines. Tacit 
approval or sanction mechanisms would incentivise authorities to meet the timeline. With respect to the principle of proportionality, a legislative proposal would introduce general guidelines on the implementation of these meas ures. The concrete formulation of measures 
would still be left to the Member States, givi ng them freedom and flexibility how to meet the 
stipulated objectives. 
 
Option 4:  New harmonised permitting scheme at EU level
 
Option 4 would create a new harmonised permitting scheme, based on some of the 
measures as outlined under option 3 (one-stop-shop approach, time limit for final authorisation decisions), but with an aim at harmonising national approaches and giving final decision making power to the EU level in case problems cannot be resolved at Member State level. This should in certain cases allow overriding other interests on the basis of “European 
interest”, similarly to the “Déclaration d'utilité publique” (DUP) procedure applicable in certain 
Member States. The impact of this approach would be substantial because of the harmonised and hierarchical decision making approach. However, this policy option is unlikely to respect the principles of subsidiarity and proportionality, as the same results could be achieved by implementing option 3. Thus this  option is discarded from further analysis.
 
 
5. ANALYSIS OF IMPACTS  
We first analyse impacts for the business as usual (BAU) scenario, which includes the policy 
option 1 for each of the four policy areas. We then analyse the impacts of the different other options sequentially in each policy area A (scope), B (design), C (coordination) and D (permitting) as compared to BAU. The impact anal ysis for all options is based on qualitative 
and, where available, quantitative evaluation, covering, as relevant, economic (including 
administrative and compliance costs), social and environmental aspects. This methodology 
will allow identifying a limited number of policy sets for further, more detailed assessment and comparison.  
5.1. Baseline ("business as usual") 
Under business as usual (BAU), implementation of third internal market measures would 
help to resolve some of the identified problems in infrastructure planning and implementation 
of cross-border projects. The shortcomings of the current TEN-E instrument would however 
remain as such, with a focus on electricity and gas, rigid project lists, insufficient cross-border coordination and persistent delays in permitting. Nationally focussed and for technologies "conservative" tariff-setting would still render certain projects commercially not viable (see 
                                                 
65 See recommendation of Priority Interconnec tion Plan (2007), COM(2006) 846 final/2, p.12f. 
 
 33more details in Box 2). Moreover, due to the limited amounts of available EU funding and 
their focus on studies rather than works, only market based investments would take place, 
i.e. investments that are commercially viable under current market and regulatory conditions. 
Planning and permitting difficulties would lead to a remarkable mismatch between planned investments and investments actually carried out.  
Box 2: Methodology used for assessing the impa ct of identified problems on investment 
 
Quantifying the impacts of the proble ms identified under BAU is only possible to a limited extent, given 
the complexity of electricity and gas markets and corresponding infrastructure development. It was 
therefore decided to limit the quantitative analysis of impacts for this study to the following two 
dimensions, whose impacts can be estimated, based  on existing theoretical and empirical evidence: 
- uncertainties about technologies, imperfect tariff regulation and internal market, assessed through 
their impact on the commercial viability of projects; 
- permitting, assessed through its impact on the realisation ratio of projects. 
 
Commercial viability  
While it is very difficult to circumscribe precisely the field of commercially viable projects in regulated 
markets such as those for electricity and gas trans mission infrastructure, one can consider in a 
simplified manner that an investment concerning a new corporate financed asset is commercially 
viable if its cost-benefit analysis re sults lead the concerned TSO(s) to submit the investment project for 
approval to the regulator, for a given set of mark et and regulatory conditions (related to future 
utilisation rate forecasts, expected congestion rent s etc. on the one hand, and a given set of rules 
concerning the asset base, regulated rate of  return, amortisation etc. on the other hand). 
Concerning project financed assets , commercial viability can also be tested through the ability of the 
project to secure commercial financing (equity and debt). One can further co nsider that regulated 
investments, which are approved by the regulator but afterwards not implemented by the concerned 
TSO because the regulated rate of return for the proj ect is considered too low, given its expected risk 
and return profile, are not commercially viable. 
Obviously, the field of commercially viable projects  is a function of the applicable regulation, which 
itself should evolve with the implementation of the third internal market package. However, as 
described in chapter 2.4.2, the def inition of commercial viability applied here takes already into 
account these evolutions. 
 
Based on this definition and the investment needs anal ysis carried out in chapter 0, infrastructure 
investment needs and effective investment under BAU for electricity  for the period 2010-2020 were 
calculated as follows: 
• 70 bn€ for transmission infrastructure (source: ENTSO-E), out of which 28 bn€ are assumed to be 
dedicated to cross-border interconnections (source: KEMA). It was assumed that these 
investments will be commercially viable, although, gi ven problems related to cost-benefit allocation 
for complex cross-border projects, some  of them might actually not be so. 
• 32bn€ for offshore grid infrastructure, based on an estimated 40 GW of installed offshore wind 
generation capacity by 2020 (source: ENTSO-E, Offs horeGrid study). Given the technological and 
regulatory uncertainties and the lack of incentives  to develop optimised grid architecture, it was 
assumed that the corresponding investments will not be commercially viable, although some of 
them will happen under BAU. One must also note t hat first results from the OffshoreGrid study 
indicate that overall costs for connecting offsho re wind farms and interconnecting electricity 
markets across the Northern Seas could be reduced with an optimised integrated grid 
infrastructure. 
• 40bn€ for smart grid infrastructure in distributio n and transmission networks (not related to smart 
metering). Given the technological and market design uncertainties as well as the lack of 
incentives for individual market actors to develop  such grid infrastructure on their own, it was 
assumed that 50% of this investment (20bn€) will not be commercially viable. 
 
Infrastructure investment needs and effective investment under BAU for gas for the period 2010-2020 
were calculated as follows (sourc e: PRIMES / DG ENER analysis): 
• 28bn€ for import pipelines, out which an estimated 50% (14 bn€) will be built within the EU. It was 
assumed that intra-EU investments will be co mmercially viable under current market und 
regulatory conditions. 
 
 34• 21bn€ for intra-EU interconnectors. It was assumed that intra-EU investments will be commercially 
viable under current market und regulatory conditions. 
• 21 bn€ for storage. It was assumed that about 1/ 3 of these investments (7bn€) will not be 
commercially viable under current market and regulatory conditions; 
• 1bn€ for reverse flow infrastructure. It was assumed that the corresponding investments will not be 
commercially viable under current market and regulatory conditions. 
 
Given the technological, regulatory and market uncert ainties surrounding CO2 transport infrastructure 
and the lack of incentive to build an optimised ne twork, it was assumed that none of the estimated 
2.5bn€ of investment needed over the peri od 2010-2020 will be commercially viable. 
 
Realisation ratio  
The impact of delays in planning and permitting on t he effective commissioning of projects has been 
analysed based on stakeholder consultations as well as  on empirical evidence from the literature. The 
2005 "TEN-Energy-Invest" study co ncluded that the ratio “performed investments”/”scheduled 
investments” could be as low as 60% for certain electr icity TSOs. It is highly like ly that this ratio has 
further declined since, given the increased leve ls of local opposition and associated media focus on 
certain projects since 2005. This assumption seems to be validated when examining in detail the list of 
projects presented in the first TYNDP: despite cons ervative estimates for commissioning dates, delays 
are expected for about 20% of all projects identifi ed and for about 50% of cross-border interconnectors 
in particular. 
 
For gas infrastructure projects, consulted stakehol ders have confirmed that planning and permitting 
problems exist but are less acute. Under BAU, it wa s therefore assumed that the realisation ratio is 
50% of the total commercially viable inve stment for electricity and 90% for gas. 
 
 
Based on the analysis described in Box 2, the total investment need amounts to 142 bn€ for electricity, out of which about 90 bn€ are assumed to be commercially viable under current market and regulatory conditions. The total investment need is 71 bn€ for gas, with 63 bn€ assumed to be commercially viable. For CO2 transport infrastructure, the number is 2.5 bn€. 
Applying the assumptions made on commercial viability and realisation ratios under BAU, 
electricity infrastructure delivery would reach about 30% (45 bn€ out of 142 bn€), while gas infrastructure delivery would reach about 80% (57 bn€ out of 71 bn€). No significant investment would take place for CO2 transport infrastructure. These figures are average figures taken as reference for simplification. In terms of overall economic impacts
, BAU 
would therefore result in insufficient and sub-optimal development of electricity and gas 
transmission infrastructure, with an estimated investment shortfall of 113.5 bn€ over the period 2010-2020, corresponding to an overall infrastructure delivery rate of only 47%.  Error! Reference source not found.  Table 2 below summarises these numbers: 
 
Sector 
(investment 2010-2020, bn€) Business-as-
usual delivery Commercially 
viable delivery Total need 
Electricity 45 90 142 
Gas 57 63 71 
CO2 transport 0 0 2.5 
TOTAL 102 153 215.5 
Investment gap 113.5 62.5 0 
Total (%) 47% 71% 100% 
Table 2: Business-as-usual, co mmercially viable and needed in vestment by sector 2011-2020 
 
 
 35Concerning  electricity , transmission would continue to be optimised mainly at national rather 
than EU level, thus bearing significantly higher costs. For offshore grids in particular, certain 
projects would not be realised at all up to 2020, given delays and difficulties in the planning 
and permitting process, while for other projects, national, technologically mature and mostly radial connections to shore would be preferr ed over cross-border or technologically more 
advanced and integrated designs. Concerning onshore projects, planning and permitting delays and obstacles due to the imperfect internal market would affect in particular cross-border connections, maintaining certain transmission bottlenecks and hence congestion 
rents. Between 2006 and 2009, total congestion rents of 26 European electricity TSOs (EU-
27 without CY, MT and UK plus Norway and Switzerland) have varied between about 1.2 bn€ and 1.95 bn per year
66. The energy imbalances between Member State price zones 
would generate price differences, leading to significant social welfare impacts. These differences reached in 2008 on average between 15 and 29 €/MWh for 12 different 
interconnectors linking two Member States, with corresponding welfare losses estimated at 
over 3 bn€
67. Increased price volatility and negative prices would be another consequence of 
insufficient transmission capacity in a given price zone. Concerning both economic and social impacts
, risks of system instability would increase due 
to higher balancing constraints, leading to more black-outs. Despite their relatively low probability, research shows that black-outs have unusually costs, notably for industry or 
services (production shortfalls, restarting of machinery, and damage to machinery or raw 
material) or households (loss of food, comfort and potentially free time). For the case of Germany, it has been estimated that overall costs could amount to 8-16 €/kWh, or about 30 to 150 times more than the current electricity price
68. Therefore, even slightly deteriorated 
security of supply could induce macroeconomic losses of several billion euros for this country 
alone69. The social impacts of a black-out on soci ety and daily life were felt clearly in 
November 2006 when a black-out, originated in North-West Germany, struck France, Austria, Belgium, Italy, Spain and even Morocco, leaving a total of about 15 million people without electricity for up to two hours. Among the concrete consequences affecting directly EU citizens were about 100 train delays in  Germany and hundreds of passengers trapped in 
lifts in Paris due to the outage. 
 Concerning smart grids , BAU would lead to insufficient development, given their inherent 
risks, with associated negative impacts in term s of power outages, losses in the electricity 
system (technical, e.g. thermal losses, but also non technical, due to sub-optimal systems 
planning and asset management) and greater difficulty if not impossibility to integrate an 
increasing share of renewables and integrate and operate grids at European-level. But it 
would also prevent the EU from benefiting from directly quantifiable positive economic 
impacts : The French regulator CRE has estimated that with the implementation of smart 
metering the supplier switch capability for households will increase by a factor of 10 (50% instead of 5%). In the longer term, smart grids would contribute to price reductions on the 
electricity market by increasing trans parency of supply and demand, hence reducing 
congestions, optimising system flows and pr oviding the information needed for dynamic 
pricing. Moreover, the Bio Intelligence Report concludes that smart grids could reduce the EU’s annual primary energy consumption in the energy sector by almost 9% by 2020
70, 
which equals to about 148 TWh of electricity. In 2010 prices, this amounts to annual savings of almost 7.5 bn€. 
                                                 
66  European Commission consultation on an Inter-TSO Compensation Mechanism, 2008; ENTSO-E 
67 “Influence of National and Company Interests on Eu ropean Electricity Transmission Investments”, Study by 
Matti Supponen, Helsinki University of Technology, August 2010 
68 German electricity prices were about 11c€/kWh for industry and 23c€/kWh for household customers during the 
second half of 2009 (Eurostat). 
69 “Hohe Versorgungszuverlässigkeit bei Strom wertvo ller Standortfaktor für Deutschland”, David Bothe and 
Christoph Riechmann in Energiew irtschaftliche Tagesfragen, 10/2008 
70 Pilot projects with smart metering in various Europ ean Member States have yielded annual reductions of 
consumption between 5 and 15%. 
 
 36 
Lack of sufficient gas infrastructure would increase the probability of supply shortages or 
supply disruptions, or limit the possibilities to mitigate actual supply disruptions, in a context 
of decreasing domestic production (all ov er Europe) and higher import dependency. The 
example of the winter 2005/2006 in the UK illustrates the possible economic impact  of supply 
shortages: due to higher prices, the extra cost  paid by British consumers amounted to about 
2 billion £71 (about four times the value of the BBL pipeline between NL and UK). This 
shortage was mainly due to an infrastructure failure (storage burn) combined with insufficient 
import capacity to bring additional gas from other sources (through pipelines or LNG). 
The economic damage caused by the January 2009 gas supply disruption in South East Europe has been estimated at 1.65 billion €
72 for Slovakia, Hungary, Croatia, Serbia and 
Bulgaria. This amount is by far higher than the total cost of all reverse flow projects and Central-Eastern European interconnector and stor age projects included in the EEPR (around 
1.2 bn€), which could have mitigated the supply disruption had they been operational at the 
time of the crisis. It was mainly inadequacies in gas transport which constrained flows (capacities, reverse flow capabilities, unusual routes, insufficient integration of gas networks in Central and South Eastern Europe), not lack of gas
73. 
Social impacts  on consumers could also be significant, especially in the winter. During the 
January 2009 gas crisis, many Bulgarian households remained without heating for up to 48 
hours. While transit disputes, such as the one that lead to the above described crisis, have 
occurred on average 2 to 3 times each year in Europe over the past years74, they resulted 
only twice (January 2006 and January 2009) in effective supply shortfall/disruption to the EU.  Lack of infrastructure would also increase dependency from only a few or a single source 
and hence hinder market integration and competition, leading to higher prices. This can be 
demonstrated by looking at the price evolution at existing trading hubs. North-West Europe seems to be rather well integrated, as the prices of TTF (Netherlands), Zeebrugge (Belgium), Gaspool or Net-Connect (Germany), PEG (F rance) and NBP (UK) generally seem to 
converge. However, the prices at the Italian PSV are constantly higher than the prices in the 
North-West. In Eastern Europe, liquid and transparent hubs are still under development (or to 
be developed), making the assessment of price differentials and missing links more difficult. However, as confirmed by stakeholder consultations, there are significant price differences between Central-Eastern European Member States
75. These Member States (who joined the 
EU in 2004 and 2007) and the member countries of the Energy Community Treaty are therefore those exposed to the highest risks in terms of supply shortage or disruptions, lack 
of market and integration and therefore possible negative economic and social impacts. 
 Finally, the impacts of over- or under-investm ent in both electricity and gas infrastructures 
are asymmetric. As the cost of transmission is limited in the final energy price, over-
investment in infrastructure will cause only a limited increase of the final price
76. But a lack of 
infrastructure can cause energy shortages, disr uptions or price increases with far higher 
economic and social impacts. For electricit y in particular, transmission on average only 
amounts to about 10% of overall electricity cost. Investing in more generation and/or back-up capacity to avoid energy shortages and black-outs would result in higher overall costs for the concerned Member States compared to the construction of interconnectors to obtain EU-
                                                 
71 "Crossing Borders in European Gas Networks: The Missing Links", Clingendael Energy Paper, September 
2009 
72 Estimates were provided by the concerned Member States to DG ENER. 
73 SEC(2009) 979 Impact Assessment of t he gas security of supply regulation 
74 Such disputes arise for supplies coming from Russia th rough Ukraine, but also for those coming from Algeria 
through Morocco, the most recent one being the dispute between Belarus and Russia in July 2010.  
75 Note that even in the case of perfect interconnectivity and market integration, price differentials between distant 
regions would remain due to transport costs. However, pric es should converge within a region if the market works 
well and sufficient interconnection capacities are available. 
76 For gas, transmission costs account on average for onl y 2-4% of the final gas price in Western Europe, 
although this share may be significantly higher in indi vidual Member States, in particular in Eastern Europe. 
 
 37wide or regional balancing, thus again increasing prices to final consumers. This effect would 
be even stronger, if missing transmission infrastructure prevents the development of 
renewable generation capacities and hence favours the use of fossil fuel based generation 
with higher fuel-dependent operating costs. This in turn could lead to increased problems of energy poverty for low income households, notably in Eastern Europe.  Concerning CO2 transportation , the BAU scenario would prevent any significant investment 
in networks and give rise to piecemeal development (at project or national level) with a high 
risk of future redundancy or bottlenecks in through-flow capacity (similarly to the electricity 
and gas grids) and limited market integration with a risk of higher energy prices in the long term. 
 
Concerning environmental impacts , less infrastructure development would diminish negative 
local impacts for those directly concerned by  new energy infrastructure projects, both 
temporarily (e.g. during the construction perio d for underground gas pipelines or electricity 
lines) and permanently (notably for overhead electricit y lines or offshore grid infrastructure). It 
would also limit potential losses of biodiversity due to energy infrastructure crossing natural habitats. However, these impacts should be put in perspective with the negative global climate impacts generated by insufficient infr astructure development. Under BAU, lack of 
transmission infrastructure and smart grids would limit the possibilities to inject electricity 
from renewable sources into the grid to reach final customers, hindering the achievement of 
the 20% renewables target and preventing CO2 emission reductions, with the related consequences on the climate and the environm ent. Concerning renewables, given the 
difficulties and shortcomings identified above for offshore grid development, it is estimated that a significant share of the 32 bn€ of investments needed for offshore connection 
infrastructure by 2020 will not be realised. As demonstrated by KEMA and confirmed by 
ENTSO-E, reaching the 20% renewables target in 2020 will therefore be impossible, given 
the important contribution expected from offshore wind (over 12% of total renewable electricity production in 2020 or about 20% of the additional renewables capacity to be installed between today and 2020
77). Concerning emissions, the Smart 2020 study estimates 
that global emissions could be reduced by 15% thanks to smart grids, mainly through their 
contribution to energy efficiency. Similarly, absence of sufficient transportation capacity and lack of interconnection between CO2 producing sites in one Member State and CO2 storage sites in another Member State would slow down the uptake of CCS technologies, again maintaining higher CO2 emissions. Gas supply shortages or disruption due to lack of infrastructure or alternative sources (such 
as LNG or CNG) would on the one hand lower CO2 emissions under BAU, as less gas is 
consumed. On the other hand however, one can realistically assume that gas would be replaced by other more emitting fossil fuels, typically oil or coal. The overall effect of 
insufficient gas infrastructure can be assumed to be higher CO2 emissions. This environmental impact analysis is confirmed at the macro-level: cumulated CO2 
emissions for the EU between 2010 and 2030 under the PRIMES baseline scenario 
(corresponding to BAU) are projected to be about 2,500 millions tons or over 3% higher than under the Reference scenario, where all necessary infrastructure is supposed to be operational. In addition, the absence of additional energy infrastructures might also lead to negative local environmental impacts (e.g. air pollution), due to longer lifetimes or development of new 
capacities for non renewable, higher emission electricity generation capacities. In the case of 
oil transport, the alternatives to bringing additional oil to the EU in case of an oil supply 
disruption would be an increased tanker traffic in the environmentally sensitive Baltic Sea and the Bosporus to compensate a shortfall in  the Druzhba pipeline system (the stop of the 
entire supply of this system would require to redirect approximately 60 million tons of crude 
                                                 
77 DG ENER calculations  
 
 38oil/per year78). Developing alternative supply routes would require investments, which might 
not happen without political support and awareness-raising at EU level. 
 
5.2. Policy area A: Scope of policy instrument 
From the impact assessment of the BAU scenarios, one can clearly conclude that major 
positive impacts are expected at the economic and social level from extending the scope of 
the policy instrument to new sectors in electricity (smart grids including storage) and gas (CNG), but also to CO2 transportation. This would address some of the uncertainties and the shortcomings of the current TEN-E framework, outlined in Chapter 2.3. Moreover, by focussing attention on new technologies such as smart grids, electricity storage or carbon 
capture and storage, extending the scope would also foster innovation in these fields. The 
extension to oil would also provide positive env ironmental impacts, by ensuring diversified oil 
supply routes to the EU to reduce the environmental risk related to increased tanker traffic on the Baltic Sea and in the Bosporus. Nevertheless, these would be limited to countries in Central and Eastern Europe supplied through the Druzhba pipeline system. Including all 
these new sectors in the scope of the policy instrument (option A3) is therefore the preferred 
option.  
5.3. Policy area B: Design of policy instrument 
Compared to BAU with a fixed and rigid projec t list defined in 2006, the update of this list 
(option B2) based on an enlarged scope (option A3) would allow taking into account new or 
changed priorities in terms of infrastructure  development. This improv ed focus would have an 
overall positive impact, but would maintain the rigidity of a project list, which might again 
need adaptation in the future up to 2020 and beyond.  By contrast, a complete reform of the current approach (option B3), with a very limited number of broad priorities of European interest, no ex ante list of priority projects and smart 
and transparent selection criteria instead of the current three-tiered categorisation of 
projects, would yield far bigger positive econom ic, social and environmental impacts. Indeed, 
this option would allow focussing all attention on those priorities, which are of major European interest and for which EU intervention will be most beneficial, or on areas with strong innovation and high positive environmental impacts such as renewables’ integration 
into the grid, smart grids, storage or CO2 transport. More generally, this approach based on 
European priorities would draw attention on economic and environmental trans-boundary 
and regional effects, while option B2 would be in fluenced more by national or even local level 
effects. Establishing smart and transparent selection criteria would minimise possible distorting effects on the internal market, by designing rules that are in line with current legislation and regulation. It would also allow evolution over time of the concrete support given to projects, optimising the use of the po licy instrument even in  the longer term. It is 
therefore considered to be the preferred option. 
Transition from old guidelines projects list to new priorities and projects: 
- Some projects are implemented or well underway (will be implemented by 2014). 
- Some projects have been abandoned (proved unfeasible or uninteresting). 
- Some will be taken up under the new priorities (if identified so by the respective regions). 
- Projects, which lose their status acquired under the former guidelines, will do so because 
they are not of European, but of national or sub-regional interest, and should be promoted at these respective levels.  
                                                 
78 "Technical aspects of variable use of oil pipelines coming  into the EU from third co untries", feasibility study by 
ILF and Purvin & Gertz 
 
 395.4. Policy area C: Coordination 
As seen in chapter 2.2 and 2.3, the current TEN-E design with voluntary regional structures 
and EU coordinators has not provided all the nec essary incentives for effective regional 
coordination and rapid implementation of cross-border infrastructure projects. Option C2 with 
mandatory regional structures and, where necessary, EU coordinators, would have significant positive impacts in terms of infrastructure development and is therefore 
considered as the preferred option compared to BAU. These regional structures would be particularly positive for projects with a clear regional delimitation such as the offshore grid in Northern Europe or the development of a gas corridor in South-Eastern Europe. They would 
also contribute positively to market integration and better functioning of regional markets. 
Their negative impacts in terms of administrativ e burden would be very limited to the meeting 
and coordination requirements created for various actors (national governments, regulators, TSOs, energy companies) through the newly est ablished or extended regional structures. As 
existing regional structures, for example the so-called Regional Initiatives, would be used for 
this task, no additional administrative costs are expected. 
 
5.5. Policy area D: Permitting 
Both measures would introduce more efficiency  in the decision making process by clarifying 
existing rules and ways or recourse, optimising the number of steps needed for a given decision to be taken and reducing as much as possible delays for each of these steps. While 
BAU is expected to lead to very limited streamlining and acceleration of permitting 
procedures only, option D2 would allow an accelerated treatment for European priority projects in those countries where priorities  have been defined or where fast-track procedures 
exist. It is considered that this would partia lly shorten the delays observed under BAU and  
allow improving infrastructure delivery significantly  in the electricity sector by raising the ratio 
"performed investments"/"scheduled investments" for the period 2010-2020 from 50% to 
75%. In the gas sector, the effect would be more limited (from 90% to 95%). This would 
considerably increase infrastructure investment from 102 bn€ under BAU to 130 bn€ over the period 2010-2020. The one-stop-shop approach (option D3) however would further facilitate administrative 
procedures and, combined with the limit of 5 years for a final authorisation decision to be 
taken by the authority for a given project, acce lerate permitting and increase project delivery 
compared to the investment needs. It is assumed that 100% of the scheduled market based investments in electricity, gas and CO2 transportation would be realised during the period 2010-2020. The additional investment due to option D3 would be about €53bn compared to BAU, further increasing infrastructure investment to 155.5 bn€, with most of the contribution coming from the electricity sector, where the problems due to delays in planning and 
permitting are biggest.. 
 The table below summarises the realisation rates assumed under BAU and with both options D2 and D3: 
 
Sector  
Selected scenarios 
 Realisation rate    
assumption  
(% of total investment1) 
business as usual (D1) 50% 
fastest national procedure (D2) 75% Electricity 
one-stop-shop (D3) 100% 
Gas business as usual (D1) 90% 
 
 40Sector  
Selected scenarios 
 Realisation rate    
assumption  
(% of total investment1) 
fastest national procedure (D2) 95% 
one-stop-shop (D3) 100% 
Table 3: Realisation rates und er different scenar ios (2010-2020)  
 
Concerning the macroeconomic impacts assessed using the E3ME model, both options 
would have significant positive overall effe cts on GDP and employment compared to BAU, 
with a cumulative effect of +0.42% of GDP and 410,000 additional jobs over the period 2011-2020 for option D3 (see Annex 3 for more details). This would correspond to a net cumulative increase in GDP of about 8.8 bn€ over the period
79. The positive impact of option D2 would 
only be about half (+0.22% of GDP, about 150,000 additional jobs). In any case, the 
additional investment made possible would ha ve positive impacts on small and medium 
enterprises, through the need for more employment generated in construction, mechanical engineering and business services. This would in turn increase incomes and household spending, confirming the positive social impacts of the policy.   
Contrary to policy areas A and B and C, policy area D would have considerable impact on 
the administrative burden and compliance cost for both companies and national administrations compared to BAU. The industry repeatedly pointed out reduced administrative burden as a major desired change. Option D2 would simplify procedures and reduce administrative burdens only for projects  in those Member States, where national 
priorities and fast-track procedures exist. The national "one-stop-shop" of option D3 however 
would reduce the amount of interlocutors for pr oject promoters to a single identified authority 
per Member State, as opposed to the current situation where the number of authorities can reach up to 20, yielding the largest positive administrative impact. It must be noted however that, while option D2 is assumed to be easy to comply with, option D3 would create compliance costs for Member State governments in terms of national transposition of new 
rules, re-design of existing permitting procedures and re-organisation of authorities in charge 
of these procedures. While this option would also necessitate more administrative resources to process permitting for projects of European interest, it is not considered that this would lead to crowding out effects when compared to the processing of national projects, given the limited number of projects concerned. 
Concerning environmental impacts, it must be underlined that both options D2 and D3 do not 
aim at reducing environmental standards for the evaluation of energy infrastructure projects. The compliance with EU environmental legislat ion is extremely important for the smooth 
implementation of energy infrastructure projects. All projects, if so required, will be subject to 
the appropriate environmental assessment in accor dance with existing EU legislation (mainly 
SEA directive
80, EIA directive81 Habitats directive82 and Water framework directive83), as is 
already the case in the current TEN-E guidelines. As a result, certain projects might have to 
change their technology choice (e.g. from overhead line to underground cable or special measures for gas pipelines in order to be able to cross Natura 2000 sites; direct current instead of alternating current to reduce the size of power poles). Others would have to change their routing or to adopt measures in order to prevent and mitigate the possible 
                                                 
79 Based on 2000 prices, the cumulative investment taking place under business as usual between 2011 and 
2020 is about 73.9 bn€ (down from 89 bn€ in 2008 prices),  while it is 117.8 bn€ under S1, yielding a difference of 
43.9 bn€. Comparing this number to the cumulative  annual GDP increase of 52.7 bn€, one obtains the net 
absolute GDP impact in 2000 prices. 
80 Directive 2001/42/EC on the assessment of the effect s of certain plans and pr ogrammes on the environment 
81 Directive 85/337/EEC on the assessment of the effects of  certain public and privat e projects on the environment 
82 Directive 92/43/EEC on the conservation of natural habitats and of wild fauna and flora 
83 Directive 2000/60/EC establishing a framework fo r the Community action in the field of water policy 
 
 41adverse effects on the environment or, if not possible, to compensate negative impacts, in 
particular on the conservation objectives and integrity of Natura 2000 sites.  
  
Following this assessment, it is considered that option D3 would be the most effective, while option D2 would imply lower compliance costs at Member State level.  However , the Communication covered by this impact assessment will only consider 
principles to make permitting procedures more efficient and transparent, whereas concrete 
rules to achieve this in the Member States will only be proposed in the Energy Security and 
Infrastructure Instrument to be tabled in 2011. A more detailed impact assessment will be prepared for this instrument, providing for an in-depth assessment of the different policy options with regard to the sectors covered, their compatibility with national legal systems and their compliance with the principle of subsidiarity, taking into account the importance of 
transparency and public acceptance. It will also include an analysis of the administrative 
burden and compliance costs for each policy option. It must be noted that these rules concerning permitting will only cover electricity transmission infrastructure as well as gas 
infrastructure transmission and storage infrastructure. Smart grid projects, which do not involve large visible infrastructure investment with high environmental impacts, and CO2 transport projects, which will see only limited investment up to 2020, should not be covered 
under these new rules. 
 In view of the next impact assessment, a study has been launched and will deliver first 
results by May 2011. The study will analyse the legal and regulatory framework as well as the effective practice concerning planning and permitting for electricity and gas infrastructure 
(covering spatial planning, environmental protec tion and public consultation rules), on which 
procedures and decisions are based. It will in particular assess the number and tasks of the authorities involved during each step of the permitting and licensing for typical infrastructure projects, as well as their respective level (local, regional, national).  
Based on this analysis, the study will make recommendations for improving the existing 
legal, regulatory and incentive framework at EU level, taking into account differences in the Member States, notably in terms of legal systems and local acceptance. The recommendations will pay due respect to the impact of the solutions proposed in terms of simplifying and accelerating permitting procedures, and their viability in terms of how administrations will be able to implement them technically and legally. The recommendations 
will further be reflected against the principles of proportionality and subsidiarity. 
 In addition to the study, extensive stakehol der consultations, involving national 
administrations, TSOs and NGOs are fores een. A dialogue with representatives from 
Member States where accelerated procedures have been or are about to be implemented 
has been initiated to enquire about best-practices and compliance costs incurred. 
 
6. COMPARISON OF POLICY OPTIONS AND CONCLUSION  
The four different policy areas, with between 2 and 3 maintained policy options for each, can 
be combined in numerous ways. In addition to BAU (analysed in the previous chapter), there are 8 possible policy sets combining different policy options in each area: 2 in area A, 2 in area B, 1 in area C and 2 in area D. However, the impacts of the different options within one 
policy area can be independent of those of another policy area. On the one hand, the scope 
of the policy instrument (policy area A) does not influence the effectiveness of the design of the instrument (policy area B); and the coordi nation between regional players (C) will impact 
each sector independently of the number of sectors targeted (A). On the other hand, while the impacts of the different permitting schemes  (D) on the speed of project implementation 
will not be affected by a variation in scope (A), it is likely that certain permitting policy options 
 
 42will be more effective if combined with certain options of policy instrument design (B) or 
coordination (C). 
 
The following table summarises the main impacts of each maintained policy option presented in chapter 5 in terms of economic, social and environmental impacts:  
 Economic impacts Social impacts Environmental impacts 
A: Scope 
A1 - more power losses,  more 
energy consumption and less transparency for the 
consumer due to insufficient 
smart grid - limited innovation in new 
technologies such as 
electricity storage, smart grids, CCS  - higher air pollution and 
CO2 emissions (due to limited development of 
renewables, smart grids, 
CCS) - higher environmental risks 
in case of oil supply 
disruption (due to increased oil tanker traffic) 
A2 - slightly diminished negative impacts compared to A1, notably for new technologies 
such as smart grids, 
electricity storage and CNG  - higher air pollution and 
CO2 emissions (due to limited development of CCS) 
- higher environmental risks 
in case of oil supply 
disruption (due to increased 
oil tanker traffic) 
A3 - best coverage of all 
sectors, in line with energy 
and climate policy objectives  - air pollution reduction and 
less CO2 emissions 
- more nuisance and negative local environmental 
impacts (due to additional 
infrastructure development) 
B: Design 
B1 - insufficient adequate transmission and storage capacity due to rigid, 
suboptimal priority setting, 
leading to congestion rents, price differences, price 
volatility 
- increased risk of electricity black-outs or gas supply 
shortages / disruptions - negative impacts on both 
electricity and gas consumers in case of black-
outs/shortages 
- energy poverty due to higher energy prices - local nuisance and 
environmental impacts limited 
- more CO2 emissions 
 
B2 - reduced impacts compared to B1, due to slightly 
improved priority setting - slightly reduced impacts as 
compared to B1 - slightly diminished effects 
as compared to B1 
B3 - significant positive impacts on market (price 
convergence, lowering effect 
on prices) and security of supply 
- significant development of 
renewables, smart grids, 
electricity storage and CCS, 
in line with energy and climate policy objectives - reduced security of supply 
risks and lowering effect on 
energy prices beneficial to 
final consumers - increased local nuisance 
and environmental impacts 
- lower CO2 emissions 
C: Coordination 
 
 43C1 - insufficient cross-border 
infrastructure investment, 
insufficient market integration and bigger risks to security of 
supply - negative impacts on both 
electricity and gas 
consumers in case of black-outs/shortages 
- energy poverty due to 
higher energy prices - local nuisance and 
environmental impacts 
limited - more CO2 emissions 
C2 - more cross-border 
infrastructure development 
and optimised design, better (regional) market integration 
- very limited administrative 
burden for various stakeholders - reduced security of supply 
risks and lowering effect on 
energy prices beneficial to final consumers - more CO2 emission 
reduction (e.g. through focus 
on offshore grids, CCS) 
D: Permitting 
D1 - significant delays in 
infrastructure delivery, 
insufficient development  - local nuisance and 
environmental impacts 
limited 
- more CO2 emissions 
D2 - reduced delays in 
infrastructure delivery, 
improved development - positive effect on GDP 
(+0.22% over the period 
2010-2020) - limited administrative cost - positive impact on job 
creation (+150,000 over the 
period 2010-2002) - more local nuisance and 
environmental impacts than 
in D1 - CO2 emission reduced 
compared to D1 
 
D3 - full delivery of commercially viable infrastructure projects - significant positive impact 
on GDP (+0.42%) 
- less administrative cost for 
operators 
- significant compliance cost for national administrations - significant positive impact 
on job creation (+410,000) and, to a lesser extent, 
SMEs 
 - more local nuisance and 
environmental impacts than in D2 
- CO2 emission reduced 
compared to D2 
 
 
As summarised above, the combination of options with the largest positive impacts would be 
A3, B3, C2 and D3, noting that the policy area of permitting will still have to be analysed 
more in depth. While BAU would lead to only 102 bn€ of investment, leaving an investment gap of 113.5 bn€, the most effective policy set as described above would significantly raise infrastructure delivery, with an investment level of 155.5 bn€. Our analysis also shows that this policy set would be most beneficial in economic, social and environmental terms. 
 
It must however be noted that even the most e ffective policy set would deliver 60 bn€ less 
than the identified investment need of 215.5 bn€. Indeed, the mere enlargement of the scope, as well as the proposed reforms on the design of the policy instrument, regional cooperation structures and permitting, will not, ceteris paribus , close the remaining huge 
investment gap and will not make those projects bankable, which are commercially non 
viable under BAU market and regulatory conditions. This applies in particular to certain 
cross-border electricity grid, smart grid
84 and offshore grid infrastructure, to gas cross-border, 
reverse flow and storage infrastructure and to certain CO2 transport infrastructure. At the same time, the potential for tariff increases to be able to create the regulatory conditions to 
                                                 
84 First studies and experiences do highlight the long-te rm economic viability of smart metering deployment alone. 
The UK Department for Energy and Climate Change (DECC)  has estimated that fitting 26 million homes with 
smart meters by 2020 would cost over 8 bn £. But this cost would be more than compensated for by 14.5 bn £ of 
savings in operational costs for powe r companies and lower bills for customers. However, the corresponding 
"smart" investments on the grid are not currently covered by the market. 
 
 44cover these investments is limited, given the investment amounts at stake85. Therefore, one 
could expect significantly higher positive im pacts under a policy set using public funding or 
dedicated regulatory measures to enable the implementation of all projects of European 
interest, including those, which are not commercially viable86. Establishing principles for the 
cost-allocation across borders could solve the issues where the commercial viability of a project is due to its uneven cost-benefit allocation to users. Regulators could agree on common principles in relation to cost-allocation of interconnection investments and related tariffs. In electricity the development of long term forward markets for cross-border capacity 
should be explored, whereas in the gas sector the investments costs could be allocated to 
TSOs in neighbouring countries, both for normal (based on market-demand) investments as well as those motivated by security of supply reasons. The Commission plans to put forward, 
in 2011, a proposal or guidelines to address cost allocation of major technologically complex or cross-border projects, through tariff and investment rules. Where a higher rate of return 
would be required to match the project risks and thus make them bankable, a regulatory 
approach could also be envisaged. Public funding could be explored for those areas, where the above-mentioned measures would fail. However, this needs detailed further analysis which will be included in the Impact Assessment to be prepared for the EU Energy Security and Infrastructure instrument.  
7. MONITORING AND EVALUATION  
Specific indicators to monitor the evolution of the policy will be:  
• The number of projects constructed, under  construction or commissioned by given 
target dates such as 2015, 2020 and 2030, compared to the number of projects 
identified as being of European interest. This indicator could also be measured in terms of installed capacity and length of new power lines or gas pipelines and capacity of other new electricity and gas infrastructure (storage, LNG/CNG). 
• To measure diversification of gas imports: the share of each import source and their 
concentration within the overall import (at national, regional and EU level), for 
example through the Herfindahl index
87. 
• To measure the integration of renewables: the share of (variable) electricity produced 
from renewable sources in the overall electricity generation. This will be monitored 
through the bi-annual reports Member States must submit to the Commission under 
article 22 of the renewables directive. 
• To measure market integration: the interconnection level between Member States 
and the evolution of energy prices. Concerning electricity, interconnector capacity 
defined as the ratio between import capacity and installed generation capacity in a given Member State could be used, as well price differentials observed between international interconnectors. Concerning gas, prices at major European hubs could 
                                                 
85 There are strong signs that energy pr ices will increase in the short and medium term to respond to changes in 
the EU's energy system. In comparison to investments lin ked to increased electricity generation from renewables 
and investments in distribution grids, the impact of grid investments is forecasted to be minor. ENTSO-E has 
calculated that 100 bn € of transmi ssion investment over the period 2010-2020 would represent only about 2% of 
bulk power prices. However, the combined impact of al l needed investments on prices could be significant. The 
UK energy regulator (OFGEM) for example has calculated t hat prices could increase over  the next 10 years by as 
much as 25%, while France has discussed a price increase of 20% over three years during 2009. 
86 The E3ME model confirms that such funding, if compens ated e.g. by a small increase in direct taxation rates, 
would be revenue neutral at macroeconomic level compared to  full funding of all the investment through higher 
energy prices. 
87 The Herfindahl index, also known as Herfindahl-Hirschm an Index or HHI, is a measure of the size of firms in 
relation to the industry and an indicator of the amount of  competition among them. It is defined as the sum of the 
squares of the market shares of t he 50 largest firms (or summed over all the firms if there are fewer than 50) 
within the industry, where the market shares are expressed as fractions. The result is proportional to the average 
market share, weighted by market shar e. As such, it can range from 0 to 1. 0, moving from a huge number of very 
small firms to a single monopolistic producer. 
 
 45be used. Price monitoring is already bei ng done by DG ENER’s Energy Market 
Observatory. 
• To measure the adoption of smart grid techno logies: the share of grid infrastructure 
(including lines, converter stations, substations etc.) equipped with new 
communication technologies compared to the total infrastructure for a given TSO as 
well as the number of electricity costum ers having signed up to smart grid enabled 
services. 
• To measure security of supply of gas: the compliance with the N-1 and reverse flow 
standards will be monitored under the security of gas supply directive. 
• To measure progress concerning permitti ng: the average duration of authorisation 
procedures for projects of European interest compared to the average duration of 
procedures for all infrastructure projects. This activity could be carried out by the ENTSOs. 
 
For monitoring and evaluation, like in the pas t, the Commission would assess the evolution 
via an implementation report on a bi-annual basis. 
 
 46ANNEX 1: ELECTRICITY TRANSMISSION CAPACITY INCREASES FOR THE PERIOD 2010-2015  
AND 2015-2025 
 
Major transmission capacity increase in Europe in the next 5 years 
(mid-term)
capacity increase greater than 500 MW
low er capacity increase 
 
 
Major transmission capacity increase in Europe in 2015 and beyond 
(longer term)
capacity increase greater than 500 MW
low er capacity increase 
 
Source: ENTSO-E 
 
 47ANNEX 2: CURRENT FINANCING OF TEN-E  PROJECTS  
 
  
Investments in infrastructure are mainly fi nanced from private sources, whereby the TSOs' 
own resources can vary between 20% and 100% of the total investment depending on the 
risks and the scale of the overall investment. The rest is typically covered by loans from 
commercial banks and international financial institutions. Partnerships with companies active in the gas and power sector, other than TSOs, may offer additional capital in the form of equity participations. Energy infrastructure can be corporate financed or project financed. 
The involved risks are different. As a general rule, if a project lies within the TSOs' own 
network and is mainly linked to domestic transmission or distribution, TSOs will invest at their own risk and cover the investment from their own corporate sources. Larger mid-stream (gas) and cross-border (gas or electricity) proj ects are often project-financed, with special 
purpose companies set up for them. Member States in most cases do not participate directly in financing the of energy infrastructure and in particular TEN-E projects.  
EU-funded support to TEN-E projects was based so far on the following instruments: 
– TEN budget of 155 mln € for the period 2007-2013 (see chapter 2.2): Although the 
maximum co-financing rate is up to 50% for studies and 10% of eligible costs for works, it has so far rarely amounted to more than 0,01-1% of the total investment cost of a project. 
– The European Investment Bank plays an important role in the implementation of the TEN-
E projects. In 2007-2009 the financial envel opes providing senior loans amounted to 
2.561 bn€ and 3.407 bn€ respectively for gas and electricity projects. 
– In recognition of their social and economic importance, energy infrastructure projects have 
risen in priority in other EU funding sources, including the Structural Funds, Instruments for Pre-Accession (IPA) and European Neighbourhood Policy (ENPI/NIF) as well as the RTD Framework Programme. These programmes have a significantly larger budget than 
TEN-E for energy-related measures.  However, from a total sum of 1.33 bn€ available 
under the structural funds for 2007-2013, only a fraction has been allocated to projects so far: 0.7% (7.5 mln €) for gas and 0.04% (12,000 €) for electricity. This is mainly due to the same difficulties as identified in chapter 2.3. 
– In 2009, the Council agreed exceptionally to allocate 3.98 bn€ to energy infrastructure and 
technology through the European Energy Programme for Recovery (EERP), out of which 
2.365 bn€ went to electricity and gas infrastructu re projects. These funds targeted projects 
where delays caused by credit withdrawal would not only have been detrimental to the EU's security of supply, and therefore to future economic growth, but would also have had a serious impact on employment and skills in  the energy and construction sectors. The 
remaining funds were aimed at the introduction of renewables (offshore wind, 565 m€) 
and other low carbon technologies (CCS, 1.05 bn€) into energy networks. For the supported offshore grid projects, a European added value was required, namely an "innovation component of large scale projects with cross-border significance", suggesting that "Such projects should include an integrative approach for interconnecting offshore wind power to provide transmission capacity in view of trading electricity between Member 
States." A large proportion of EERP funding will benefit the most mature Trans-European 
energy infrastructure projects, in order to speed up and secure investments and accelerate their realisation. 
 
 48ANNEX 3: E3ME  MODELLING SCENARIOS AND RESULTS  
 
 
 
1. Presentation of E3ME model 
 
The E3ME model was used to carry out a more advanced macro-economic analysis of the impacts of the different policy options exami ned in chapter 5. E3ME is a computer-based 
model of Europe’s economic and energy syst ems and the environment.  It was originally 
developed through the European Commission’s research framework programmes and is now 
widely used in Europe for policy assessment, for forecasting and for research purposes.  The structure of E3ME is based on the system of national accounts, as defined by ESA95 (European Commission, 1996), with further lin kages to energy demand and environmental 
emissions.  The labour market is also covered in detail, with estimated sets of equations for 
labour demand, supply, wages and working hours.  In total there are 33 sets of econometrically estimated equations, also including the components of GDP (consumption, investment, international trade), prices, energy demand and materials demand. Each equation set is disaggregated by country and by sector. 
 
E3ME’s historical database covers the period 1970-2008 and the model projects forward annually to 2050. The main data sources are Eurostat, DG ECFIN’s AMECO database and the IEA, supplemented by the OECD’s STAN database and other sources where appropriate.  Gaps in the data are estima ted using customised software algorithms. 
 
The other main dimensions of the model are: 
• 29 countries (the EU27 member states plus Norway and Switzerland) 
• 42 economic sectors, including disaggregation of the energy sectors and 16 service 
sectors 
• 43 categories of household expenditure 
• 19 different users of 12 different fuel types 
• 14 types of air-borne emission (where data are available) including the six 
greenhouse gases monitored under the Kyoto protocol. 
• 13 types of household, including income quintiles and socio-economic groups such 
as the unemployed, inactive and retired, plus an urban/rural split. 
 
Typical outputs from the model include GDP and sectoral output, household expenditure, 
investment, international trade, inflation,  employment and unemployment, energy demand 
and CO2 emissions.  Each of these is availabl e at national and EU level, and most are also 
defined by economic sector.  The econometric specification of E3ME gives the model a strong empirical grounding and 
means it is not reliant on the assumptions  common to Computable General Equilibrium 
(CGE) models, such as perfect competition or rational expectations.  E3ME uses a system of error correction, allowing short-term dynamic (or transition) outcomes, moving towards a long-term trend. The dynamic specification is important when considering short and medium-
term analysis (e.g. up to 2020) and rebound effects
88, which are included as standard in the 
model’s results. 
 More detailed information on the E3ME model can be found in the impact assessment study done by COWI, Cambridge Econometrics and KEMA.  
                                                 
88 Where an initial increase in efficiency reduces demand, but is negated in the long  run as greater efficiency 
lowers the relative cost and increases consumption. 
 
 49The graph below depicts the methodology applied to analyse the macroeconomic impacts of 
infrastructure investment in the framework of this study. 
Energy balances 
for electricity and 
gas
Electricity infrastructure 
requirements and 
modelling
Electricity investment 
needsGas infrastructure 
requirement
Gas investment needs
Definition of investment baseline and scenarios
E3ME macro-economic input modelling
Impact assessment results and conclusions
 
 
 
2. Policy sets 
 
Different combinations of policy options (policy sets) were designed to analyse the 
macroeconomic impacts of various policy options89. In addition to policy set (S1) combining 
all preferred options (A3, B3, C2 and D3), a policy set (S2) was established, where option D3 is replaced by option D2 to diminish Member State compliance costs. For the sake of 
comparison, an additional policy set (S3) was designed to take into account possible 
measures targeted at non commercially viable projects. Indeed, S3 assumes public support or regulatory measures (such as guidelines on remuneration of non commercially viable projects including for example capacity paym ents, compensation schemes, rate-of-return 
bonuses) to ensure full delivery of all investments needed, including non commercial 
projects. The three abovementioned scenarios (S1, S2 and S3) were compared to business 
as usual, using the E3ME model.  The following table summarises the policy sets  and the investment assumptions
90 made 
for their development, based on existing studies and expert analysis: 
                                                 
89 It must be noted that these policy sets could not stylis e the impacts of the options  in each policy area, but 
mainly relied on assumptions arising from policy area A and D. 
90 Under BAU and policy sets S1 and S2, total investment  corresponds to the investment assumed to be 
commercially viable under current market and regulatory conditions, not taking into account potential delays due 
to planning and permitting, which can reduce the realisation rate for a given period. Only under policy set S3, 
which assumes support targeted both at commercially viable and non-commercially viable projects, total 
investment corresponds to the identified investment need. 
 
 50 
Scenarios  Input assumptions for E3ME modelling (investment in the EU only) 
Investment electricity (including smart grids): 
45BN€ (50% of total market based investment needs) 
Investment gas: 
44.7BN€ (90% of total market based investment needs)  TOTAL:   89.7BN€  
2010-2020 
 
2010-2020  Business as usual                
(A1, B1, C1, D1) 
 (alias CS1) 
Financing: 
Energy price + x M€ EU funding
91 (60% electricity, 40% gas) 
Investment electricity transmission: 90BN€ (100% of a total commercially viable needs)  
Investment gas: 49.7BN€ (100% of a total commercially viable needs
92) 
 
Investment CCS: 2.5BN€   TOTAL:   142.2BN€  
2010-2020 
 2010-2020 
 
2015-2020 Policy set S1            
(A3, B3, C2, D3) 
 (alias CS4) 
Financing method: 
Energy price + x M€ EU funding (11/ 30 gas, 11/20 electricity, 1/12 CCS) 
Investment electricity transmission: 
68BN€ (75% of a total commercially viable needs) 
 Investment gas: 
47.2BN€ (95% of a total commercially viable needs) 
 Investment CCS: 2.5BN€ – 2015-2020 
 
TOTAL:   117.7BN€ 1/4 for 2010-
2015, 3/4 for 
2015-2020  
2010-2020 
 2015-2020 Policy set S2            
(A3, B3, C2, D2) 
 (alias CS3) 
 
Financing method: 
Energy price + x M€ EU funding (11/30 gas, 11/20 electricity, 1/12 CCS) 
Investment electricity transmission: 142BN€  
Investment gas: 57BN€ 
 Investment CCS: 2.5BN€ 
 
TOTAL:   201.5BN€ 2010-2020 
 
2010-2020 
 2015-2020 
 Policy set S3            
(A3, B3, C2, D3 and public 
support)  
(alias CS6) 
 
Financing method: 
Energy price + y M€ EU funding to be determined (11/30 gas, 11/20 electricity, 1/12 CCS) 
 
 
                                                 
91 The available amount under the current TEN- E programme is 155M€ for the period 2007-2013. 
92 It is important to note that the E3ME model only takes in to account investment taking place within the EU and 
therefore assumes a total investment need for gas of 57 bn€, with 49.7 bn€ corresponding to commercially viable 
projects.  
 
 51For oil , given the limited (around 600 million euros) and only hypothetical investment needs 
for the considered period, it was assumed that no investments would take place. 
 
 
3. Modelling results 
 
Concerning the macroeconomic impacts of the different scenarios on GDP and employment, 
it appears that policy set S1 has a significant positive overall impact compared to BAU. The 
positive impact of S2 is only about half. The biggest increase in GDP and employment could 
be expected from policy set S3. Table 4 gives a detailed presentation of impacts for each policy set
93. 
 
Policy set Infrastructure 
investment 
(in billion €, 2011-2020) GDP 
(cumulative percentage point 
difference compared to BAU, 
2011-2020) Employment 
(000s, cumulative difference 
compared to BAU,          
2011-2020) 
BAU 89.7 0 0 
S1 142.2 0.42 409 
S2 117.7 0.22 153 
S3 201.5 0.9 774 
 
Table 4: Impacts on GDP and employment 2011-2020 (E3ME model results)  
 
 Indeed, more investment creates the need for more employment in a first phase, notably in construction, mechanical engineering and business services. This in turn leads to higher 
incomes and household spending. Multiplier effects contribute in a second phase to 
increased employment in consumer sectors such as retail, even if these effects can be 
delayed in time. The model also concludes that  the forecasted investment will have small 
positive impacts on small and medium enterprises, even if the size of certain of the bigger 
infrastructure projects (notably in the gas sector) might favour large companies. This confirms the positive social impacts of the different policy sets studied. Table 5 summarises 
the positive impacts of all policy sets on t he main macroeconomic parameters for the year 
2020 when compared to BAU
94. The cumulative impact of S1 on household spending, 
investment, exports and imports roughly doubles the impacts of S2. The positive effect of S3 compared to S1 is even bigger, as it more than doubles investment, exports and imports.   
 
Cumulative percentage point 
difference compared to BAU      
2011-2020 S1 S2 S3 
Household spending 0.15 0.07 0.27 
Investment 1.30 0.68 2.93 
Exports 0.21 0.10 0.45 
Imports 0.21 0.10 0.48 
                                                 
93 Increases in GDP vary significantly between Member St ates depending on the level of investment taking place 
in each of them and can be superior to 1% in 2020 for smaller countries. 
94 As the model does not take into account the different  impact loops of infrastructure investment on gas and 
electricity prices, changes in inflation and sectoral prices are close to zero  for all policy sets . No distributional 
impacts appear, i.e. no differentiated impac t according to differ ent income levels.  
 
 52 
Table 5: Impacts on other macroeconomic  parameters 2020 (E3ME model results)  
 
It must be pointed out that due to the complexity of possible interactions between energy infrastructure investment and energy prices the analysis of their correlation at the macroeconomic level was only indicative and limited to gas. The model confirms that gas 
prices would decrease gradually over time  compared to BAU as new interconnection 
capacities come on stream, which in turn would have a positive effect on GDP outweighing the additional investment cost. Concerning electricity, it was assumed that there would be no direct knock-on effects on prices (through increased and smoother supply) from new interconnection investments
95. Given the positive price impact of the various policy options 
described in chapter 5, it can therefore be assumed that the model gives conservative 
estimates of the benefits provided by the different policy sets as compared to BAU. 
 
 
                                                 
95 Additional cross-border flows typically only occur at  times of peak electricity demand and may be in both 
directions, making it difficult to estimate changes on the average annual electricity prices used in the model. 
 
 53 ANNEX 4: DESIGN OPTIONS FOR AN INTEGRATED OFFSHORE GRID  
 
Various design options are currently studied for developing offshore grids (see graphs 
below). The OffshoreGrid96 study suggests that radial grid connections in general make 
sense up to 50 km distance from their connection points onshore. For larger distances (in the range of 50-150 km) from shore, the concentration of wind farms is a determining factor for the benefits of clustering. Above 150 km distance, offshore grid hubs are considered as typical solutions. In countries where such hubs can easily be defined, the connection costs of offshore wind farms could be reduced by up to 34%
97. The OffshoreGrid study has calculated 
that, assuming strong offshore wind development, the cost reduction for the North Sea area 
as a whole could be around 17% by 203098. 
 
Regarding integrated "wind farm connection and interconnector" solutions, these are beneficial in terms of infrastructure investments, as there is always a cost reduction. However, the cost savings have to be compared to the increased system costs that are the 
result of the constraints for electricity trading, which underlines the need for coordinated 
approaches involving developers, regulators and TSOs to identify optimal solutions.  
 
Currently available designs  
 
 Radial connection using alternating (AC) or direct current (DC) technology 
 
 Radial AC or DC connection of clustered 
offshore wind power plants 
                                                 
96 Financed by the Intelligent Energy Europe (IEE) program me has made a quantitativ e assessment of the costs 
and benefits of different design options in order to identify how much anticipatory investment would be needed 
while avoiding stranded costs. More informa tion can be found at: www.offshoregrid.eu 
97 Cost reduction calculated for Germany.  
98 According to the OffshoreGrid study, offshore grid infrastructure de velopment would cost 32 billion euros until 
2020 and 90 billion euros until 2030 considering radial connections. Clustering offshore wind farms at offshore 
hubs could reduce this investment need by 15 bn € be tween 2020 and 2030. Further investment need reductions 
could be gained by clustering wind farms before 2020 and by integrating wind farm hubs with interconnectors. 
According to the case study about the Great Britain / No rway / continental Europe area, an integrated solution 
could require 70-80% less grid investment, but would pr esent constraints for the us e of interconnectors between 
countries. However the net benefits ar e estimated to be significantly higher in this geographic area.  
 
 54
 
 Radial AC or DC connection of wind park 
clusters with point-to-point international 
interconnector 
 Target design 
 
 
 Meshed international offshore grid based on multi-terminal scheme 
 
Source: ENTSO-E / OffshoreGrid study 
 
 55ANNEX 5: INPUT DOCUMENTS  
 
 
 This impact assessment builds on the following general inputs: 
 - Current framework for Trans-European Energy Networks (TEN-E)
99 and its impact 
assessment100 
- Green Paper "Towards a secure, sust ainable and competitive European Energy 
Network"101 and its public consultation102 in the period November 2008 – March 2009. 
- Implementation Report103 on the TEN-E guidelines and TEN-E financial regulation  
- European Energy Plan for Recovery104   
- Priority Interconnection Plan 2007105 
- Third internal energy market package106 
- Climate and Energy package107 
- Directive 2009/28/EC on renewables energies108 and National Renewable Energy Action 
Plans109 
- Directive 2009/31/EC on the geological storage of CO2 - Directive 2008/114/EC on the identification and designation of European critical 
infrastructures and the assessment of the need to improve their protection 
- Regulation concerning measures to safeguard security of gas supply and repealing 
Directive 2004/67/EC, impact asse ssment and accompanying documents
110 
- Communication on Offshore Wind Energy111 
- Political Declaration of the North Seas Countries Offshore Grid Initiative112 
- Declaration of the Budapest V4+ Energy Security Summit 24 February, 2010113 
    
                                                 
99 Decision 1364/2006/EC and Regulation 680/2007 of  the European Parliament and of the Council  
100 SEC(2003) 742 
101 COM(2008) 781 
102 http://ec.europa.eu/energy /strategies/consultations/2 009_03_31_ gp_energy_en.htm 
103 COM(2010)203 and SEC(2010)505 
104 Regulation (EC) N°663/2009 of the European Parliam ent and of the Council of 13 July 2009 establishing a 
programme to aid economic recovery by granting Union fin ancial assistance to projects in the field of energy (OJ 
L 200, 31.7.2009) 
105 COM(2006) 846 final/2 
106 http://ec.europa.eu/energy/gas_electri city/third_legislat ive_package_en.htm : see notably Directives 
2009/72/EC and 2009/73/EC and Regulation s (EC) 713/2009, 714/2009 and 715/2009 
107 OJ L140 of 5.06.2009  
108 Directive 2009/28/EC OJ  L140 of 5.06.2009 p. 16 
109 Available at: http://ec.europa.eu/ energy/renewables/transparency_pl atform/transparency_platform_en.htm 
110 COM(2009) 363, SEC(2009) 979, SEC(2009) 977 
111 COM(2008) 768  
112 http://www.benelux.be/pdf/pdf_fr/ac t/act0170_NorthSeasCountriesOffshoreGridI nitiativePolitical Declaration.pdf 
113 http://visegradgroup.eu/main. php?folderID=859&arti cleID=27720&ctag=articlelist&iid=1  
 
 56 
The impact assessment also builds on the results of the following studies: 
 
1. General studies 
- EU Energy Trends to 2030: Update 2009  (Baseline 2009 and Reference scenario 2009) 
- World Energy Outlook 2009 . IEA 
- "The revision of the trans-European energy net work policy (TEN-E)", impact assessment 
study by COWI, Cambridge Econometrics and KEMA for the European Commission. 
October 2010 
- "Energy Infrastructure Costs and Investments between 1996 and 2013 (medium-term) 
and further to 2023 (long-term) on the Trans-European Energy Network and its Connection to Neighbouring Regions with emphasis on investments on renewable energy 
sources and their integration into the Trans-European energy networks, including an 
Inventory of the Technical Status of the European Energy-Network for the Year 2003" (TEN-Energy-Invest), study by Centro Elettrotecnico Sperimentale Italiano, Instituto de Investigación Tecnológica, Mercados Energeticos and Ramboll for the European Commission. October 2005 
 
2. Studies concerning fossil fuels 
- Ten Year Network Development Plan by ENTSOG
114 
- "Methodologies for Gas Transmission Tariffs and Balancing Fees in Europe", study by 
KEMA. December 2009 
- "Feasibility of Europe-wide CO2 infrastr uctures", study by Arup for the European 
Commission. To be published by end 2010 
- "Evolution of size and cost of a trans-European CO2 pipeline network", study by the Joint 
Research Centre (JRC) of the European Commission. 2010 
- "Technical aspects of variable use of oil pipelines coming into the EU from third 
countries", feasibility study by ILF and Purvin & Gertz for the European Commission (expected to be completed by autumn 2010) 
- "Model-based Analysis of Infrastructure Projects and Market Integration in Europe with 
Special Focus on Security of Supply Scenarios", study by EWI Institute of Energy Economics at the University of Cologne. May 2010 
- "Study on natural gas storage in the EU", study by Ramboll Oil and Gas. October 2008 
 
3. Studies concerning the power sector 
- Ten-Year Network Development Plan, ENTSO-E. 2010
115 
- "2009 Technology Map of the European Strategic Energy Technology Plan (SET-Plan) – 
Part I: Technology Descriptions", Chapter 12, JRC-SETIS Work Group. 2009 
- "The European Electricity Grid Initiative (EEGI): Roadmap 2010-2018 and Detailed 
Implementation Plan 2010-2012", ENTSO-E and EDSO. 25 May 2010 
- System Adequacy Forecast 2010-2025 , ENTSO-E. 2009 
- Power Choices , Eurelectric. 2009 
                                                 
114 http://www.entsog.eu/download/investment/ENTSOG_TYNDR_MAIN_23dec2009___.pdf 
115 https://www.entsoe.eu/fileadmin /user_upload/_library/SDC/TYNDP/TYNDP-final_document.pdf 
 
 57- Roadmap 2050: A Practical Guide to a Prosperous, Low-Carbon Europe , European 
Climate Foundation. 2010 
- Renewables 24/7: Infrastructure Needed to Save the Climate , Greenpeace/EREC. 2009 
- Transforming Europe’s Electricity Supply , EASAC. 2009 
- OffshoreGrid study116, consortium coordinated by 3E. July 2010 
- European Wind Integration Study (EWIS) , final report. March 2010 
- Pure Power: Wind energy targets for 2020 and 2030117, EWEA, December 2009 
- Oceans of Opportunity , report on offshore wind energy118, EWEA, September 2009 
- Reports produced under SUSPLAN, REALISEGRID and IRENE 40 projects financed 
under FP7. Forthcoming 
- “Influence of National and Company Interests on European Electricity Transmission 
Investments”. Study by Matti Supponen, Helsinki University of Technology. Draft version 
dated 1 August 2010 
 
4. Studies concerning smart grids 
- "Impacts of Information and Communication Technologies on Energy Efficiency"119, Bio 
Intelligence Service Final Report, September 2008. Supported by the European Commission DG INFSO 
- "Smart 2020: Enabling the low carbon economy in the information age"
120 by The Climate 
Group on behalf of the Global eSustainability Initiative (GeSI) 
- “The Green Grid: Energy savings and carbon emissions reductions enabled by a smart 
grid”, Electric Power Research Institute (EPRI), Palo Alto, California, United States, June 2008 
http://www.smartgridnews.com/artman/uploads/1/SGNR_2009_EPRI_Green_Grid_June_
2008.pdf  
- Findings of the High-Level Advisory Group on ICT for Smart Electricity Distribution 
Networks: “ICT for a low carbon Economy – Smart Electricity Distribution Networks”, July 2009. Supported by the European Commission, DG for Information Society and Media http://ec.europa.eu/information_society/activities/sustainable_growth/docs/sb_publication
s/pub_smart_edn_web.pdf  
- "Electricity Storage: Making Large-Scale Adoption of Wind and Solar Energies a Reality". 
Cornelius Piper, Holger Rubel, Boston Consulting Group. March 2010 
  
 
                                                 
116 Deliverables are available at: www.offshoregrid.eu   
117 http://www.ewea.org/fileadmin/ewea_documents/docum ents/publications/reports/Pur e_Power_Full_Report.pdf 
118 http://www.ewea.org/fileadmin/ewea_documents/ documents/publicatio ns/reports/Offshore_Report_2009.pdf 
119 http://cordis.europa.eu /fp7/ict/sustainable-g rowth/studies_en.html  
120 http://www.smart2020.org/_asse ts/files/02_Smart2020Report.pdf