ENCOURAGED Project title

Transcription

Project no.: 006588
Project acronym: ENCOURAGED
Project title: Energy Corridor Optimisation for European Markets
of Gas, Electricity and Hydrogen
Instrument: Coordination Action
Thematic Priority: Sixth Framework Programme Scientific Support Policy (3.2)
Work Package I
Deliverable number III
Final WP1 report on optimised electricity corridors
between the enlarged EU and the neighbouring areas
EXECUTIVE SUMMARY
Start date of project: 01-01-2005
Duration: 2 years
Organisation name of lead contractor for this deliverable: CESI RICERCA
Other organisations contributing: IAEW RWTH Aachen, ECN, ENVIROS, OME, BSREC, CEP, EnCog
IMEPOWER, IBS, CESI, REE, VTT
Project co-funded by the European Commission within the Sixth Framework Programme
(2002-2006)
PU
PP
RE
CO
Dissemination Level
Public
Restricted to other programme participants (including the Commission Services)
Restricted to a group specified by the consortium (including the Commission Services)
Confidential, only for members of the consortium (including the Commission
Services)
X
Final version
page 1/33
Final WP1 report on optimised electricity corridors between the enlarged EU and the neighbouring areas
Main Contributors Work Package 1 “Electricity corridors”
ENCOURAGED WP1 “Electricity corridors” was carried out under the co-ordination of CESI RICERCA; other
organisations involved are IAEW RWTH Aachen, ECN, ENVIROS, OME, BSREC, CEP, EnCog IMEPOWER,
IBS, CESI, REE, VTT.
Riccardo Vailati
+39 02 3992 5802
[email protected]
Thomas Hartmann
+49 (0) 241 80 97658
[email protected]
Frits van Oostvoorn
+31 22456 4438
[email protected]
Miroslav Maly
+420 284007491
[email protected]
Manfred Hafner
+33 (0) 4 9296 6691
[email protected]
Habib El Andaloussi
+33 (0) 4 9296 7464
[email protected]
Lulin Radulov
+359 2 980 68 54
[email protected]
Sergey Molodtsov
+7 495 6337627
[email protected]
Yuri Kubrushko
+38 044 289 5632
[email protected]
Alexey Romanov
+38 044 287 8677
[email protected]
David Tonge
+90 212 252 24 60
[email protected]
Bruno Cova
+39 02 2125 5431
[email protected]
Carlos Artaiz Wert
+34 91 453 32 32
[email protected]
Seppo Kärkkäinen
+358 20 7226406
[email protected]
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Acknowledgement
ENCOURAGED has been prepared by a consortium of ten European research organisations and has been
funded by the European Commission under the 6th Framework Programme for Research, Technological
Development and Demonstration (Scientific Support to Policies).
The consortium included the following organisations: Coordinator ECN (Energy research Centre of the
Netherlands), Work Package leaders OME (Observatoire Méditerranéen de l’Energie, France), CESI RICERCA
(Italy), FhG-ISI (Fraunhofer Institute for Systems and Innovation Research, Germany) and partners ENVIROS
(Czech Republic), CEP (Centre for Energy Policy, Russian Federation), EnCoG IMEPOWER (ENergy
COnsulting Group, Ukraine), IBS Research & Consultancy (Turkey), BSREC (Black Sea Regional Energy
Centre, based in Bulgaria), IAEW (Institute of Power Systems and Power Economics) at RWTH (RheinischWestfälische Technische Hochschule) Aachen University (Germany).
The studies for the electricity corridors were coordinated by Riccardo Vailati of CESI RICERCA.
The main contributors to “electricity corridors” studies were: Riccardo Vailati, Antonio Gatti, Paola Bresesti,
and Roberto Bernante from CESI RICERCA, Thomas Hartmann from IAEW RWTH Aachen, Frits van
Oostvoorn, Michiel van Werven, and Jeroen de Joode from ECN, Miroslav Maly from ENVIROS, Manfred
Hafner, and Habib El Andaloussi from OME, Lulin Radulov (BSREC), Sergey Molodtsov (CEP), Yuri
Kubrushko and Alexey Romanov (EnCoG), David Tonge and Ceren Uzdil (IBS). In addition to the
aforementioned team members, the following experts and organisations participated and actively contributed to
ENCOURAGED “electricity corridors” studies and activities: Bruno Cova from CESI (Centro Elettronico
Sperimentale Italiano, Italy), Carlos Artaiz Wert from REE (Red Eléctrica de España, Spain), Seppo Kärkkäinen
from VTT (Technical Research Centre of Finland). Comments were given by Robert Gould from Helio
International (France).
Domenico Rossetti di Valdalbero (European Commission, Directorate General Research) has supervised the
project and work.
We gratefully acknowledge the following experts for assistance in collection of project information and/or
assistance in the preparation of the reports and/or comments on draft documents:
Alexandru Sandulescu (ANRE, Autoritatea Nationala de Reglementare in domeniul Energiei, Romania), Awad
Mohamed, Kamel Yassin (EEHC, Egyptian Electricity Holding Company, Egypt), Goran Granic (Energy
Institute “Hrvoje Pozar”, Croatia), Hilmo Sehovic (Federal Ministry of Energy, Mining and Industry, Bosnia
and Herzegovina), Fathi Abougarad, Ibrahim Falah, Haddud Haddud (GECOL, General Electricity Company Of
Libya, Libya), Nikola Cerepnalkovski (Ministry of Economy, the Former Yugoslav Republic of Macedonia),
Gheorghe Indre (Ministry of Economy and Trade, Romania), Miroslav Kukobat (Ministry of Mining and
Energy, Serbia), Kucher Maksym Vasyliovych, Korniush Sergii Volodymyrovych (NEC “Ukrenergo”,
Ukraine), Vassil Anastassov (NEK National Electric Company, Bulgaria), Rime Bouaroudj, Rabah Touileb
(Sonelgaz, Algeria), Souad Allagui, Abderraouf Ben Mansour, Mohieddine Mejri, Taoufik Zarouk (STEG,
Société Tunisienne de l’Electricité et du Gaz, Tunisia).
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Consultations with stakeholders and discussions of findings and recommendations of ENCOURAGED have
been held in the period from February till December 2006 by means of workshops and seminars on study results
with respectively the electricity, gas and hydrogen stakeholders (representatives from industry, regulators,
investors, traders, policy makers, etc). “Electricity” seminars were held in Milan, Algiers, Ankara and finally in
Brussels. In addition to aforementioned project contributors, these seminars benefited from the participation and
comments of the following experts.
Seminar on the first study results regarding the “Assessment of the electricity interconnections in the European
Union and with the neighbouring countries”, 9 May 2006, Milan:
Pavel Svejnar (CEPS), Romano Ambrogi, Cristina Cavicchioli, Angelo Invernizzi, and Nikola Kuljaca (CESI
RICERCA), Daniele Canever, Sefkija Derviskadic, Luca Imperiali, and Uberto Vercellotti (CESI), Jan Strunc
(Czech Energy Regulatory Office), Yves Schlumberger (EDF), Marco Bottoni, Mario Cumbat, Antonella
Garavaglia, and Clara Risso (EDISON), Fabio Caiazzi, and Raffaella Porri (EDISON Trading), Francesco
Scarpamattachini (ENEL Produzione), Domizia Novati (Enipower), Eva Hoos (EURELECTRIC), Matti
Tähtinen (Fingrid), Sami Demirbilek (Ministry of Energy, Republic of Turkey), Rime Bouaroudj (Sonelgaz),
Simone Autuori, and Pier Filippo Di Peio (Sorgenia), Claudio Di Mario, Claudio La Ianca, and Mario Valente
(Terna Rete Elettrica Nazionale), Fabio Zanellini (Università degli Studi di Pavia).
Regional seminar on “Electricity and gas interconnections from North Africa to the EU”, 16 November 2006,
Algiers:
Amadou Thierno Diallo (African Development Bank), Farid Rahoual, and Mohand Sand Taibi (CREG),
Jacques Schutz (EDF), Mario Cumbat (EDISON), Fabio Caiazzi, and Raffaella Porri (EDISON Trading), Nehal
Abdel Aziz Mobarak (Egyptian Electricity Holding Company), Fabrizio Scaramuzza (ENEL), Cristobal Burgos
Alonso (European Commission, DG Energy and Transport), Youcef Abchi, Arabi, Madina Benhamouda,
Mohamed El-Faït Bensalah, Mahdi Bichari, Ghezali, Ahmed El Hachemi Mazighi, and Mohamed Nait-Cherif
(Sonatrach), Abdelhafid Adnane, Abdelali Badache, Rime Bouaroudj, Merouane Chabane, Kamel Dermoune,
Tahar Djouambi, Fergani, Daouadji Kinane, Djamila Mohammedi, Tarar Ouaret, Kamel Sid, El Hachemi
Touaouaza, and Chérif Zeghoud (Sonelgaz), Lakhdar Chouireb (Sonelgaz and COMELEC), Rabah Touileb
(Sonelgaz GRTE), Alaoua Saidani (Sonelgaz GRTG), Abderraouf Ben Mansour (STEG), Michelangelo
Celozzi, and Angelo Ferrante (Terna Rete Elettrica Nazionale).
Regional seminar on “South-East Europe gas and electricity corridors”, 5 December 2006, Ankara:
Erjola Sadushi (Albanian Regulatory Commission), Adriatik Bego, Eda Gjergji, Agim Nashi, and Elis Sala
(Albanian Regulator for Electricity), Gokhan Yardim, (Anadolu Natural Gas Consultancy), Mehmet Akif
Duman, Kubilay Aktan, Ozden Alp, Mesude Arabacioglu, Eda Ceuheroglu, Ozlen Dudukcu, Hüseyin Saltuk
Düzyol, Mr. Eker, Emre Engür, Erdem Getinkaya, Erdem Gordebak, Orhun Kanik; Vicdan Kayi, Mehmet
Kosker, Sinar Ozcar, Selim Ozdemir, Erdinc Ozen, Cenk Pala, Bora Sokal, Murside Taymaz, Gokhan V. Toker,
and Yavuz Yilmaz (BOTAŞ), Zeyno Basak Elbasi Akkol (BP Turkey), Pinar Yapanoglu (British Embassy in
Turkey), Philippe Saintes (Electrabel), Mete Baysal (Enerco Enerji), Gürbüz Gönül (Energy Charter
Secretariat), Fatih Bilgic, Gökhan Efe, Hulusi Kara, and Bagdagül Kaya, (Energy Market Regulatory Authority
- Turkey), Haygrettin Acar, Mehtag Emri, and Mehmet Zeyrec (EÜAS), Roman Igelpacher (EVN), Peter
Graham and Murat Orekli (International Power), Emir Asadollahi (Islamic Republic of Iran Embassy in
Turkey), Nurey Atacik, Orhan Remzi Karadeniz, Nuri Dogan Karadeniz, Yasin Suudi, and Ali Can Takunyaci
(KARTET), Dimitrios Mavrakis (KEPA, Energy Policy and Development Centre at National and Kapodistrian
page 4/33
University of Athens), Nilgün S. Acikalin, Begum Babali, Sinem Caynak, Kenan Erol, Jülide Gültekin, Ciydem
Hatinoglu, and Halime Semerci (Ministry of Energy & Natural Resources of Turkey), Gülsun Erkal (Ministry of
Foreign Affairs of Turkey), Nenko Gamov (NEK EAD), Alesa Svetic (Petrol), Nusret Cömert and Ayhan
Kirbas (SHELL Turkey), Mahdi Bichari (Sonatrach), Rachid El Andaloussi (Sonelgaz), Simone Autuori
(Sorgenia), Per Myrvang and Ilknur Yenidede (STATOIL), Mounir Ben Hamida (STIR), Joe Mcclintock
(Stratic Energy), Yusuf Bayrak, Yildiz Durukan, and Doruk Özkök (TEİAŞ Turkish Electricity Transmission
Company), Vedii Yesilkilic and Filiz Yurdakul (TEDAS), Cem Duygulu and Bumin Gürses (TEKFEN), Ayhan
Isen, Azmi Kücükkeles, and Serpil Serdar (TETAS), Jacques Chambert-Loir and Olivier Gouraud (TOTAL),
Aysegul T. Bali, Serdar Demiralin, Bureu Gunal, Kutluhen Olcay, Murat Ulu, and Hüseyin Yakar (TPAO),
Reha Gülümser (TURUSGAZ), Aysem Sargin and David Kenan Young (US Embassy in Turkey), Graham
Freedman and Tim Lambert (Wood Mackenzie), Mustafa P. Kokcu and Yurdakul H. Yigitguden.
Final stakeholders’ seminar on “Energy corridors between the EU and neighbouring countries”, 12 December
2006, Brussels, with contributing experts among others:
Carine Swartenbroekx (Banque Nationale de Belgique), Enrique Iglesias Barbero (CEPSA), J. Wind (Daimler
Chrysler), Frédérik Boujot (EDF), Jean-Claude Dorcimont (Electrabel), Giuliano Basso (Energy Solutions),
Manuel Coxe (ETSO), Juho Lipponen (EURELECTRIC), Peter Nagy (European Commission, DG RELEX),
Gilles Lequeux, and Raffaele Liberali (EC, DG RTD), Jean-André Barbosa, Cristobal Burgos Alonso, and JeanPaul Launay (EC, DG TREN), Alfonso Vigre, and Enrique Iglesias Barbero (Gas Natural), M. Innocenti, and R.
Carta (GE Nuovo Pignone), T. I. Sigfusson (IPHE), Yasin El Suudi (KARTET), Dimitrios Mavrakis (KEPA,
National and Kapodistrian University of Athens), J. Reijerkerk (Linde), Robertas Alzbutas (Lithuanian Energy
Institute), Johann Gallistl (OMV Gas International), S. Berger (Opel), J. Thon (Statkraft), Souad Allagui
(STEG), Olivier Gouraud, and Olivier Ricard (TOTAL), Jean-Michel Glachant (University Paris Sud).
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Table of Contents
1.
OVERVIEW AND SCOPE OF THE STUDY ...........................................................................................8
2.
BACKGROUND AND METHODOLOGY .............................................................................................10
2.1
BACKGROUND .........................................................................................................................................10
2.2
THE CONCEPT OF ELECTRICITY CORRIDOR..............................................................................................11
2.3
METHODOLOGY.......................................................................................................................................11
3. BARRIERS AND DRIVERS OF NEW INTERCONNECTIONS BETWEEN EU AND NON-EU
ELECTRICITY SYSTEMS ...............................................................................................................................13
4.
3.1
BACKGROUND AND OBJECTIVES .............................................................................................................13
3.2
ADVANTAGES, DRIVERS AND BENEFITS OF INTERCONNECTION .............................................................14
3.3
BARRIERS TO AND COSTS AND DRAWBACKS OF INTERCONNECTION ......................................................14
3.4
REGULATORY ISSUES ..............................................................................................................................14
REPRESENTATION OF THE SYSTEM AND MAIN ASSUMPTIONS ............................................16
4.1
REPRESENTATION OF THE SYSTEM ..........................................................................................................16
4.2
THE OPTIMISATION MODELS....................................................................................................................17
4.3
THE MAIN INPUT DATA ............................................................................................................................17
5. ASSESSMENT OF OPTIMAL TRANSFERS AMONG EU AND WITH NEIGHBOURING
COUNTRIES .......................................................................................................................................................19
6.
7.
5.1
MAIN RESULTS OF THE OPTIMISATION ANALYSIS (YEAR 2015) ..............................................................19
5.2
MAIN RESULTS OF THE OPTIMISATION ANALYSIS (YEAR 2030) ..............................................................20
COST OF AND INVESTMENTS FOR CROSS-BORDER INFRASTRUCTURES...........................23
6.1
COLLECTION OF COST INFORMATION FOR CROSS-BORDER INFRASTRUCTURES .....................................23
6.2
INVESTMENTS FOR CROSS-BORDER INFRASTRUCTURES .........................................................................23
COST-BENEFIT ASSESSMENT FOR EACH INTERCONNECTION CORRIDOR .......................25
7.1
INTRODUCTION AND STRUCTURE OF THIS SECTION ................................................................................25
7.2
INTER-AREA CONNECTION UCTE - NORTHERN AFRICA .......................................................................25
7.3
INTER-AREA CONNECTION UCTE – TURKEY..........................................................................................26
7.4
INTER-AREA CONNECTION UCTE - EASTERN EUROPE ..........................................................................26
7.5
OTHER INTER-AREA CONNECTIONS .........................................................................................................27
7.6
INTERCONNECTION WITH ICELAND, MALTA AND CYPRUS .....................................................................27
7.7
INTERNAL EU CUT-SETS .........................................................................................................................28
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8.
SYNTHESIS OF DISCUSSION WITH STAKEHOLDERS AND RECOMMENDATIONS ............30
9.
SYNTHESIS OF CONCLUSIONS ...........................................................................................................32
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1. OVERVIEW AND SCOPE OF THE STUDY
The work package 1 (WP1) of the ENCOURAGED project concerns the assessment of optimal configurations
of future electricity corridors between the European Union (EU) and the neighbouring countries. WP1
conducted a complete assessment of the technical and economic viability of the future electricity corridors at the
external borders of the EU with the neighbouring regions/countries and investigated some major bottlenecks
internal to the European Union as well. The costs of different configurations and routes for the new electricity
corridors were evaluated and finally recommendations, based on an optimisation model analysis, are formulated.
The activity was subdivided in four tasks, as described in Fig. 1.
Projection of the demand and
production/supply in EU and
neighbouring countries. Assessment
of interconnection transfer capacities
Assessment of technical, economic,
regulatory and environmental
barriers/solutions for the development of
electricity interconnection corridors
Analysis based on an integrated model for the
optimisation of the electricity exchanges
across interconnection corridors
Analysis of costs and investments to
implement the corridors, estimation of
benefits and cost-benefit assessment.
Conclusions about optimal electricity
transmission corridors
Fig. 1 - Structure of ENCOURAGED “Electricity corridors” study
The report and its Executive Summary mainly illustrate the optimisation of the future electricity exchanges
between the European Union and the neighbouring countries and at some main internal EU borders, which was
performed by a least-cost approach based on short run marginal costs of thermal generation. They also presents
the estimation of the economic benefits which could be gained in the mid-term and in the long-term by the
development of new electricity corridors.
The report and its Executive Summary are organised as follows:
•
chapter 2 introduces the current status of cross-border electricity trades in EU and the methodology we
adopted in this study;
•
chapter 3 describes the drivers and barriers to the realisation of interconnections among electricity systems,
discussing technical, economic and regulatory aspects;
•
chapter 4 presents the description of the format and the treatment of the input data, the definition of system
modelling and of the main assumptions adopted in the optimisation analysis, the summary of the main data
about load demand and supply, and the mathematical description of the model used by IAEW RWTH for
the mid-term analysis (year 2015) and of the model used by CESI RICERCA for the long-term analysis
(year 2030);
•
chapter 5 illustrates the first part of optimisation results, concerning the electricity exchanges, and some
preliminary conclusions, which need to be integrated with the cost-benefit assessments;
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•
chapter 6 reports, first, a collection of cost information about recently-developed interconnection
infrastructures and currently ongoing cross-border projects, which is used to assess costs of possible types
of transmission corridors reinforcements, i.e. AC1 overhead lines, AC cables and HVDC undersea cables.
Then, the second part of chapter 6 explains the methodology adopted to calculate a simplified equivalent
“transmission charge” for the developers of new cross-border infrastructures;
•
chapter 7 evaluates the benefits that could be obtained by the realisation of new cross-border connections.
Those benefits are used to perform a cost-benefit assessment for each one of the main electricity corridors
between the European Union and the neighbouring countries and inside the EU;
•
chapter 8 summarises the contents of stakeholders’ discussions and reactions to project findings, achieved
also by “stakeholders meetings” held during the project;
•
chapter 9 draws the main conclusions.
1
AC stands for alternating current, DC for direct current and HVDC for high voltage direct current.
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2. BACKGROUND AND METHODOLOGY
2.1 Background
European electricity transmission systems were originally designed by national vertically integrated electricity
utilities (responsible for providing adequate generation, transmission and distribution on a national level) for
transmitting electricity from power plants to load demand centres. E.g. the UCTE system (the interconnected
extra high-voltage grid under control of Union for the Co-ordination of Transmission of Electricity, which is the
association of transmission system operators in continental Europe) was mainly designed to link the different
participating countries in order to increase the level of security of supply by providing backup in case of local
shortages and to lower the necessary reserve margins for each country. The system was not designed to face the
currently increasing amount of cross-border exchanges among countries for economic trade reasons (see Fig. 2).
The growth of cross border trades in UCTE
400
Cross border exchanges [TWh/year]
348,0
350
300
287,8
269,2
299,1
299,2
225,5
250
205,8
200
185,9
150
+87.2% Exchanges in 7 years
100
50
0
1998
1999
2000
2001
2002
2003
2004
2005
Year
Fig. 2 - The growth of cross-border exchanges in the UCTE system 1998 - 2005 - Source: UCTE
In response to this situation, which is leading to congestion in the cross-border connections throughout the
European Union, the EU institutions emphasised in a number of Directives and other statements over recent
years the importance of interconnection capacity expansion for a further development of an EU internal
electricity market. In the Green Paper on a “European Strategy for Sustainable, Competitive and Secure Energy”
the development of a “priority interconnection plan”, in order to increase interconnection capacity, has been
suggested as a priority issue for EU energy policy for the coming years.
The objective to remove intra-EU bottlenecks is as much important in the short-medium term, as, over a
medium-long term horizon, the objective to expand the “EU power system” eastwards and southwards in
response to requests coming from neighbouring systems (e.g. Turkey, Ukraine, Russian Federation, Northern
African countries). This will lead to further opportunities of electricity trades increase and to a substantial
growing need for interconnection capacity as well.
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2.2 The concept of electricity corridor
According to the recent “ETSO2 position paper on Roles and Responsibilities of TSOs and other actors in
Cross-Border Network Investment”:
Historically two approaches have been used as a means of identifying whether or not a transmission system
is adequate i.e. a deterministic approach to comply with security criteria and a cost-benefit approach to
compare costs of incremental transmission investment with benefits provided by the investment (also taking
account of costs avoided e.g. constraint costs).
In most countries in Europe the two approaches are used together: initially an assessment is made using the
deterministic approach and then it is backed-up by using a cost-benefit approach. For the deterministic
approach models and procedures exist, however the approach to evaluate the cost-benefit may differ widely,
and is subject to regulatory approval.
ETSO also proposes the following definition of transmission adequacy:
“Adequate transmission capacity, including interconnection capacity, is that which enables operational
security standards to be met in the reasonably foreseeable circumstances and meet “economically” the
requirements of the market. The latter is achieved when you do not expect any additional net socio-economic
benefits from additional investments in transmission capacity.”
In this ENCOURAGED “Electricity corridors” study, we define an electricity corridor as each point of the
system where transmission/interconnection capacity risks to be not adequate, in other words each point of the
pan-European system where there could be an additional net socio-economic benefit from additional
investments in interconnection capacity.
On the basis of such definition, taking into account the historical development of European electricity systems,
the electricity corridors are normally located at the borders between countries, at the borders between the
different EU power pools and, obviously, at the borders between European Union and the neighbouring
countries, which are the main focus of the ENCOURAGED “Electricity corridors” study.
2.3 Methodology
For each electricity corridor first we estimate the costs of the possible reinforcement projects, according to a
“data and info collection” about them, and second we calculate by means of an optimisation analysis the
benefits3 which can be obtained by each proposed reinforcement. The optimisation analysis performs a thermal 4
2
ETSO, which stands for European Transmission System Operators (TSOs), is an international association with
direct membership of European TSOs.
3
The benefits of transmission reinforcements are calculated referring to the effect of substitution of expensive
generation with cheaper one and including the economic effect of reduction of greenhouse gas emissions.
Benefits in terms of system reliability and adequacy, which are normally low in strong systems as the European
one, are not taken into account. Benefits in terms of increased competition among market participants - which
could be significant in some cases - are also not considered. Benefits in terms of improved security of supply for
the EU countries, export diversification and creation of internal value for the neighbouring countries (which are
exporters of natural gas) are not explicitly considered, because the translation of these concepts into monetary
value is difficult and questionable. Therefore, the interconnection development resulting from cost-benefit
analysis could be considered to be based on a relatively conservative estimation of benefits.
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economic dispatch for a multi-area system characterised by limited inter-area transfer capacities with the
objective to globally minimise the “electricity costs” needed to cover load demand.
We refer to “electricity costs” and not to prices because we need to compare EU systems and their electricity
markets with neighbouring countries often characterised by vertical integrated structures, or still ongoing
liberalisation processes, and by the consequent absence of price signals. In this study, “electricity costs” are the
fuel production costs in the various countries and take into account the effect of sustainability targets by means
of a monetary value of greenhouse gases emissions.
The aforementioned optimisation supports us to perform a traditional social cost-benefit evaluation of the net
benefit achieved by selected reinforcements of the interconnection corridors. These evaluations lead us to draw
conclusions, which could be useful to support the part of the EU priority plan concerning interconnection
corridors between European Union and the neighbouring countries.
4
Thermoelectric fossil and nuclear generations are optimised. Hydroelectric controllable generation is also
optimised in the mid-term analysis (year 2015). Other renewables sources, including run-of-river hydro, are
defined according to national and EU forecasts and imposed as input data.
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3. BARRIERS AND DRIVERS OF NEW INTERCONNECTIONS BETWEEN EU AND NONEU ELECTRICITY SYSTEMS
3.1 Background and objectives
An important objective of the European Commission, Member States regulators, and other stakeholders, is to
work towards the creation of an efficient and effectively competitive single electricity market. The European
Commission states that the overall objective of the internal electricity market is the creation of a competitive
electricity market for an enlarged European Union, where not only customers have choice of supplier, but also
all unnecessary impediments to cross-border electricity exchanges are removed. As far as economically
beneficial, electricity should be free to flow between Member States as easily as it currently flows within each
Member State.
Currently, Member States are not always well interconnected. However, certain countries and regions within the
EU have already adopted common harmonised rules. This development of regional markets, containing Member
States between which interconnection is reasonably strong, can be considered as an interim stage to the creation
of an integrated single electricity market in Europe. Fig. 3 gives an overview of regional electricity markets that
may develop or have been already established within the EU.
Fig. 3 - Potential regional electricity markets within the European Union
In addition to the objective of completion of the Internal Electricity Market, the EU target is to extend it to the
neighbouring countries in order to increase the economic stability and co-operation, as well as security of supply
in Europe. Bearing in mind this objective of a pan-European electricity market, the EU supports the idea of
studying and promoting additional interconnections with its neighbouring electricity systems.
This chapter identifies and assesses economic and regulatory drivers and barriers for new (or additional)
interconnections. It will mainly look at key advantages, drivers, barriers and costs for new interconnections in
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general, describing the main aspects which play a role in the planning of new interconnections or in the
reinforcement of the existing ones. The chapter gives a checklist of (qualitative and quantitative) drivers and
barriers. The findings can be used as a background to assess local or regional initiatives to increase
interconnection capacity.
3.2 Advantages, drivers and benefits of interconnection
Interconnection lines can provide different advantages and benefits at the national level and on a European scale
too. This paragraph summarises the main advantages and drivers of investments in interconnection of different
power systems, which can be valued and used for assessing the benefits of new or additional interconnection
with non-EU regions:
•
promotion of competition and efficiency at both sides of the interconnection;
•
existence (and possible reduction) of price differences between regions, which could be related to
differences in fuel mix and primary resources;
•
existence of differences in daily load patterns;
•
existence of differences from a lack of level playing field - being a possible “false driver” for
interconnection;
•
increase of system reliability, whose additional gains however normally become progressively less
important when interconnections become stronger.
3.3 Barriers to and costs and drawbacks of interconnection
The advantages of interconnection described above come at a cost, and, partly due to the structure of the
electricity system, the advantages may not be fully exploited.
First, there are investment costs, which could be high for building new interconnections. These investment costs
and the long lifetime of interconnection and transmission lines cause TSOs and regulators to be cautious with
investment decisions. Second, there are energy losses caused by electricity transmission, which depend not only
on the length of the interconnection lines themselves, but also on the distance over which electricity is
transmitted. A third possible barrier results from the fact that the electricity grid in Europe cannot be considered
a copper plate. Relatively small cross-border capacities and insufficient allocation of these capacities can lead to
congestion within the EU, which could impede to electricity imported from the neighbouring regions to freely
flow to demand areas (and hinders the export of electricity to neighbouring regions). The advantages of
interconnecting non-EU regions could be not achievable if internal congestion occurs.
Fourth, because interconnection capacity competes with domestic generation, interconnection could lead to an
increasing import dependency, which may create political resistance. Last but not least, there may be opposition
from residents in the areas where the transmission and interconnection lines have to be built.
3.4 Regulatory issues
The more market designs and rules between countries/regions differ, the more likely trade between markets is
impeded or distorted. The presence of different national or regional approaches may impact upon cross-border
trade. As a general rule, different designs and rules impede trade opportunities. Compatibility between key
market rules therefore is important so that opportunities for trade can be fully realised. Regulatory issues
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comprise rules concerning the timing of gate closure, imbalance arrangements, the firmness of transmission
access rights, the type of tariff regulation, unbundling and the ownership of interconnectors. There may be a lot
of other regulatory issues that are of importance when considering interconnection, e.g. the market structure
(including the mechanism through which trade occurs) in adjacent countries/regions and the extent to which
national measures for ensuring security of supply are compatible.
However, the above discussion does not necessarily mean that full harmonisation of all trading rules and
arrangements is required for effective trade interaction between markets. But regulatory arrangements need to
be independent, with regulatory processes characterised by transparency, objectivity and consistency.
Furthermore, it is worth to note that price differences that result from different regulatory structures may not
form a basis for structural exchange, as it is expected that these differences will fade away in the long run. It
may be a “false driver” for interconnection. Therefore, it is of major importance to evidence if price differences
between different markets are the result of a lack of level playing field. In that case, investment in
interconnection may not be justified.
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4. REPRESENTATION OF THE SYSTEM AND MAIN ASSUMPTIONS
4.1 Representation of the system
At the start of the project it was agreed to perform two detailed simulations to assess and optimise the transfer
capacities between EU and the neighbouring countries:
•
A mid-term (year 2015) assessment. This simulation takes into account the presence of major current
internal bottlenecks in the EU electricity transmission system (e.g.: Spain - France, the Italian border,
Belgium - France, etc.);
•
A long-term (year 2030) assessment. For this year it is assumed that the development of the Internal
Electricity Market is completed and that the transmission network is not hampered by major congestion in
cross-border interconnections among the EU countries.
For an effective analysis, it was also agreed how to group the 44 countries investigated by ENCOURAGED
“Electricity Corridors” study, taking into account the presence of large interconnected power systems in the
European Union. The groups are: UCTE (Albania, Austria, Belgium, Bosnia Herzegovina, Bulgaria, Croatia,
Czech Republic, France, Germany, Greece, Hungary, Italy, Luxembourg, Macedonia, the Netherlands, Poland,
Portugal, Romania, Serbia and Montenegro, Slovakia, Slovenia, Spain), BRITISH ISLANDS (Ireland and
United Kingdom), NORDEL (Denmark5, Finland, Norway and Sweden), Baltic States (Estonia, Latvia,
Lithuania), NORTHERN AFRICA (Morocco, Algeria, Tunisia, Libya and Egypt), EASTERN EUROPE
(European part of Russian Federation, Belarus, Ukraine and Moldova) and TURKEY. In addition, the
interconnection of the islanded system of CYPRUS, ICELAND and MALTA were investigated in the long-term
analysis (year 2030). For British Islands and Eastern Europe, we also use the short names UKIRE and IPSUPS
respectively.
As shown in Fig. 4, which depicts the separation of the system for the mid-term analysis (year 2015), UCTE
was separated into smaller “blocks”: Iberian Peninsula (Spain and Portugal), France, Italy, the German block
(Germany, Belgium, the Netherlands, Luxembourg, Switzerland and Austria) and the Central European block
(the other countries). As shown in the figure, different short names are used in 2015 to distinguish blocks with
respect to 2030.
5
All Denmark was considered as a part of the NORDEL block. Basically, two reasons led to this choice: the
most important is that the transfer capacity at the border between Denmark and Germany is lower than the one
at the internal Danish section and than the one between Denmark and the other NORDEL countries. For an
effective analysis, the system has to be separated at the weakest section in terms of transfer capacity. The second
reason is that the choice to consider Western and Eastern Denmark as a unique country allows to use the
aggregated national values about generating capacities and demand, with no need to search or hypothesize
disaggregated values for each part of Denmark.
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NO
BA
GB
RU
D
F
CE
I
EP
TR
NA
Fig. 4 - Definition of cut-sets (blocks) in the UCTE system and of inter-area connections 2015
4.2 The optimisation models
The basic idea of the optimisation analysis is to simulate the operation of the electricity systems in the European
Union and in the neighbouring countries in order to work out economically optimal configurations for the
electricity corridors. One of the basic assumption is that, at least in a long-run perspective, the market prices,
that are the main drivers of electricity exchanges among countries and regional systems, will follow production
costs. Therefore, the evaluation of the future energy exchanges is performed by means of a multi-area
production optimisation tool that allows determining the least-cost dispatch of generating units while taking
account of limited transfer capacities between the areas in which the full system is subdivided.
The total energy cost to be minimised is the sum of the energy production cost for thermoelectric generators, of
the cost of load shedding and, optionally, of the transport fees on the interconnections.
To take into account the effect of greenhouse gas emission constraints, a opportunity cost approach is adopted,
adding to the fuel cost an extra-cost defined for each type of generator, related to the future price of Emission
Trading allowances in the EU-ETS scheme. This means that each generating company owns emission
allowances, including the ones they received for free, whose value is exactly equal to the price determined in the
emission market mechanism and therefore each variation of greenhouse gas emission by electricity generation at
national level has a social value equal to the emission market price. As price of emission allowances for all the
countries fulfilling Kyoto targets and listed as Annex I Party to the United Nations Framework Convention on
Climate Change, we adopted 20 €/tCO2, which was the average value in the year 2005.
4.3 The main input data
In the “data collection” phase, all partners and contributors of ENCOURAGED “Electricity Corridors” study
provided the information to set up correct and consistent input scenarios for model analysis. To complete the
"general-purpose" development scenarios prepared by the European Commission, detailed information on the
electrical systems was collected at national/regional levels. The data collection was performed by means of a
questionnaire (for each reference year of the study and for each country interested by the project). In this
summary we give a short overview of the future demand of electrical energy, one of the factors which more
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strongly influence the electricity exchanges between the European Union and the neighbouring regions. The
figures below present the electrical demand for the regions/blocks considered in 2015 and in 2030.
Fig. 5 - Yearly electricity demand 2015 and percentage growth 2005-2015 in each area of the system
Fig. 6 - Yearly electricity demand 2030 and percentage growth 2005-2030 in each area of the system
The electricity consumption is represented starting from the total annual consumption and separating
consumption for each season. The load profiles of typical days (working and not-working days in Spring,
Summer, Autumn and Winter) were necessary since the demand characteristic in the system under investigation
may vary for climate and typical business activities. In addition, the time zone was considered for the load
profiles in order to have time consistency in the simulation results. With this choice, the representation of
electrical consumption was limited to 192 hour intervals (24 hours in the 8 typical days) to keep acceptable time
requirements for the model simulations. Finally, the annual figures are obtained by giving opportune weights to
each hour interval.
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5. ASSESSMENT OF OPTIMAL TRANSFERS AMONG EU AND WITH NEIGHBOURING
COUNTRIES
5.1 Main results of the optimisation analysis (year 2015)
The mid-term optimisation analysis investigated the optimal exchanges at the corridors between European
Union and the neighbouring countries and focused as well on the future exchanges at some “internal” main
bottlenecks of the European system (see Fig. 4 in chapter 4 for the definition of the blocks of countries and of
short names).
The simulation results for the “reference scenario” show that the electricity transfer from Iberian peninsula to
France increases significantly (net export 15 TWh). This can be explained by the new generation capacity of
high efficient combined cycle gas turbines in Spain and Portugal. This situation is supported by the large import
of energy from North Africa to Spain (15 TWh, 100% utilisation). Due to the fact that the countries of Northern
Africa are assumed not to be subject to emission constraints, the production costs are noticeable below the costs
in the European countries.
Italy remains a large importer country (40 TWh) in 2015 on almost the same level as in 2005 with a tendency of
more import from France and more export to Slovenia and Central Europe countries. In addition, the new
transmission line between North Africa and Italy is fully used (100%) for import due to the low production costs
in Northern Africa.
A significant change can be observed at the cut-set between the German block and Central Europe. The
electricity exchange towards CE increases, whereas the flow backwards reduces remarkably. This can be
explained with the generation mix in the CE block: in 2015 there is still a large amount of hard coal and gas
fired power plants in operation, that are old and relatively inefficient. The type of power plants necessary to
cover the demand is at most of the time more expensive than the “over-capacity” in neighbouring blocks.
Hence, the energy is imported from Germany, Austria and Italy, instead of being produced locally in the CE
block.
This situation is even more significant for the “RU” block composed by Russian Federation and Ukraine. The
type and age pattern, i.e. relatively low efficiency rates, of installed generating capacity together with the
expected lower margin of free generating capacity leads to a strong import situation. Hence, the neighbouring
countries (Central Europe, NORDEL and Baltic) export a large amount of energy towards the “RU” block
(about 50 TWh).
The new interconnection from Turkey to Central Europe (which is assumed to have a 2000 MW capacity) is
exclusively and fully used for energy export to CE (17 TWh). Although Turkey is assumed to apply CO2
emission constraints in 2015, the production costs are still below the costs of neighbouring regions, probably
due to high renewal of the generating set and low cost of natural gas in Turkey. The exchange between Baltic
Countries and RU is bi-directional with a tendency of export from BA towards RU.
Other simulations (variants) were performed to guarantee the robustness of the findings obtained in the
“reference scenario” simulation. A scenario 2 with higher prices of oil and gas was considered. Then two
scenarios with a different development of generation in Northern Africa and in Russia were analysed: scenario 3
covers the variant of additional transfer capacity from NA to I (1000 MW), additional 1000 MW from NA to
EP, and additional 2000 MW generation capacity installed in block NA. Scenario 4 considers additional 6 GW
of nuclear power plants in the RU block, replacing old units.
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All the variants confirm the full utilisation - close to 100% - of the capacities for export from the Northern
African countries to Southern Europe (Italy and Spain) and of export capacities from Turkey to South-Eastern
Europe. In variants 2 and 4, the most significant deviation from the reference scenario can be noticed for the cut
set between Central Europe and RU block (characterised in the reference scenario by a 38 TWh CEàRU gross
export and a net export about 30 TWh6). As a consequence, RU is reducing its import and is exporting more
energy to the neighbouring regions CE and NORDEL, but remains an area with a (relatively small) import
balance. This change of flow causes deviations to the cut-sets inside the EU, due to the interconnected system.
An energy flow from Central Europe to the German block can be observed and the exchange from NORDEL to
the German block increases slightly.
The reduction of costs (for the entire system) by the installation of additional transmission capacity represents
an important indicator for the profitability of the augmentation of transfer capacity. This cost reduction equals
zero for the case of available or unused transfer capacity but becomes greater than zero for the case of
congestion. Hence, the reduced costs can be regarded as the benefit, i.e. the “value” of a capacity increase for
the hour of congestion. By this indicator, a total benefit per year can be obtained by multiplying the reduced
costs by the expected energy transfer that is flowing via the additional capacity. This total benefit can finally be
compared to the annuity of investment costs for the additional transmission capacity in order to evaluate the
profitability of an investment project. The average reduced costs result to be lower than 2 €/MW for all the
“internal” borders, while their values are very high for the case of interconnections to Northern Africa
(9.5 €/MW in the reference scenario, up to 18 €/MW in case of scenario 2 with high gas price differentials) and
to Turkey (6-7 €/MW in all the variants investigated).
As a conclusion it can be stated that the most significant benefit in terms of cost reduction for the supply of the
system demand can be achieved by increasing the transmission capacity between the North Africa region and
Southern Europe. Furthermore, the expansion of the interconnection Turkey - Central Europe is favourable due
to the identified cost reduction. The advantage of an augmentation of interconnections inside the EU is
significantly lower but may have lower investment costs for the realisation. A comparison of the reduced costs
to investment costs and an assessment of the feasibility of exemplary projects for each cut set is necessary (see
section 7) to derive final recommendations for the optimal electricity corridors.
5.2 Main results of the optimisation analysis (year 2030)
The electricity exchanges at the EU borders are expected to be a small percentage of system demand in 2030:
the total demand of the ENCOURAGED system (including the demand in neighbouring countries) in 2030 is
8000 TWh; total bi-directional exchanges of electricity in the reference scenario (which consider a relatively
low growth of transmission capacities at the main European borders) are estimated to be 170 TWh.
Therefore, electricity exchanges has not to be seen as a possible substitute of gas imports for the European
Union, but they must have a complementary development, with its own drivers, to gas trade and long distance
energy transportation among countries. The exchanges of electricity are therefore expected - and have to be
optimised - to be complementary to the forecasted large imports of natural gas.
It has to be mentioned that this 2% percentage of exchanges at the EU borders to the total system demand would
represent, however, a massive increase with respect to the current situation, characterised by the exchange of a
6
Note that the gross export refers to the mono-directional electricity exchange, whereas the net export is the
balance of flows in both directions.
page 20/33
few TWh between Spain and Morocco and at the border EU - Ukraine, plus a tenth of TWh imported by Finland
at the border with the Russian Federation.
Fig. 7 - Synthesis of the energy exchanges (2030, reference scenario)
Significant power flows are expected from Northern Africa countries to Southern Europe (24 TWh) and from
Turkey to South-Eastern Europe (15 TWh). In both cases, there is a strong utilisation (more than 90%) of the
transfer capacities assumed to be available in 2030. The IPSUPS area is characterised by bi-directional energy
exchanges with the neighbouring regions, except than in the case of Baltic States, which result to be a net
importing area. In the winter season the high values of internal demand drive power exchanges from other
countries to Russian Federation and Ukraine, while in the other seasons (especially in summer) the lower load
demand in Russia and Ukraine allows to export a consistent amount of energy towards the neighbouring
systems.
In order to evaluate the sensitivity of the results and to guarantee the robustness of the findings obtained in the
“reference scenario” simulation, three variants were performed. In scenario 2 higher prices of oil and gas were
considered, while two scenarios analysed a different development of generation in Northern Africa and in
Russia. Scenario 3 covers the variant of additional transfer capacity from AFRICA to UCTE (2000 MW) and
additional 2000 MW generation capacity installed in AFRICA. Scenario 4 considers additional 25 GW of
nuclear power plants in the IPSUPS area, replacing old units.
All the variants are characterised by a large utilisation - close to 100% - of the export capacities from the
Northern African countries to Southern Europe (Italy and Spain). This result, which is partially related to the
absence of CO2 extra-cost for gas-based thermal generation in Northern Africa, has to be compared with the
relatively high costs needed for submarine HVDC interconnection (hundreds of million Euros to realise a
1000 MW capacity link) to obtain the optimal development configuration of electricity corridors. It is
underlined that this result depends on the realisation of the planned investments in generation capacity in these
countries that are currently facing a remarkable electricity load growth (more than 5% each year) and could also
experience difficulties in establishing a stable framework for generation and transmission investments.
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In the same way, all the variants investigated are characterised by high utilisation rates - more than 90% - of the
capacities available for export from Turkey to South-Eastern Europe (Bulgaria and Greece). Turkey is expected
to take advantage of its position as a gas transit country to Europe, which could allow lower gas prices and of
the development of large investments in new generation units (around 100 GW in the period 2005-2030), which
will be needed to meet the expected high load demand growth in Turkey.
All the variants show that the Baltic countries are expected to become a net importer in 2030, with the risk of
being hampered by possible transit flows among UCTE, NORDEL and Russian Federation.
The future development of exchanges at the borders of Eastern Europe is more uncertain: large exports
(40 TWh) from Russian Federation and Ukraine to the European Union could be possible in case of a massive
development of nuclear power (e.g. a doubling of the existing capacities, scenario 4) or in case of high gas price
differential between Russian Federation and the European Union (scenario 2). Otherwise, bi-directional
exchanges are expected, with massive power flows to Russian Federation and Ukraine in the winter season,
when these countries have a very high electricity demand. It has to be noted that the result of electricity exports
to the countries of Eastern Europe is probably “unexpected”. The achievement of this interesting result was
possible by a wide (pan-European) model analysis performed within the ENCOURAGED WP1 “Electricity
Corridors”, which includes in its medium-term and long-term scenario analysis not only the European Union but
also all its neighbouring countries.
The indicator “average marginal benefit” given by the increase of transfer capacity (i.e. the average reduction of
total system costs thanks to a marginal increase of the transmission capacity) shows the highest value (from
6 €/MW up to 9 €/MW7) at the border AFRICA - UCTE. This corresponds to a 50-80 k€/year reduction of
system costs thanks to a 1 MW increase of Net Transfer Capacity between Northern Africa and Southern
Europe. Therefore, it seems to be economically interesting to increase the transfer capacities of the transmission
corridors AFRICA - UCTE. The economic interest in augmenting the capacity of corridors NORDEL BALTIC and NORDEL - IPSUPS (calculated as the sum of the marginal benefits in both directions) reaches
5.0 €/MW and the value at the border TURKEY - UCTE is higher than 3 €/MW.
Finally, it is recalled that the indication given by average marginal benefits is only a part of the assessment of
the optimal electricity corridors. A comparison between the reduced costs and the required investment costs and
an assessment of the feasibility of exemplary projects for each cut set / inter-area connection (see section 7) is
necessary to derive final recommendations for the optimal electricity corridors.
7
Referred to a time interval lasting one hour.
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6. COST OF AND INVESTMENTS FOR CROSS-BORDER INFRASTRUCTURES
The objective of this section is twofold:
•
Presenting a summary of costs of cross-border infrastructures.
•
Discussing the issue of financing investments for interconnection reinforcement and calculating a
transmission charge for the developers of interconnections.
6.1 Collection of cost information for cross-border infrastructures
We investigated and collected information about the costs incurred for the recent HVDC interconnectors (such
as the HVDC Italy - Greece and the Swepol link, comparing them with data from Statnett, Norway and with the
international bibliography on converter station cost) and forecasted for the new transmission projects. An
average specific cost for the stations resulted to be 92 k€/MW8 for each station, that is 184 k€/MW for both
converter stations.
On the basis of the cost estimation collected for DC ongoing and future projects (the ongoing DC links NorNed
between Norway and the Netherlands, Estlink between Estonia and Finland, and the projects for Iceland cable,
BritNed and the North Sea Interconnector), it was concluded that large variations can occur for the power
cables, due to a variety of reasons including the power rating, the type of cable system, the additional elements
for each project, the depth to be crossed, etc.. For the investment analysis of a new HVDC interconnection
project the following figures were adopted:
•
Undersea pair of power cables: 1000 k€/km
•
Pair of converter station (monopolar or bipolar): 184 k€/MW
6.2 Investments for cross-border infrastructures
We calculated a “transmission charge” for the developers of new cross-border infrastructures. The analysis
refers to the realisation of the aforementioned undersea HVDC link. Two case studies are investigated:
•
Traditional development of cross-border infrastructure
•
Private development of the so-called “merchant transmission” projects
The case studies consider the remuneration of the investment and the operation & maintenance costs, not
considering the possible impact of power losses on the new transmission infrastructure. The analysis pointed out
that the equivalent “transmission charge”9 in case of merchant transmission approach results to be significantly
higher than the one in case of traditional system development. This result substantially depends on the higher
Weighted Average Cost of Capital (WACC) that characterises a merchant transmission project and is related to
the higher financial risk with respect to a regulated project. We calculated WACC for both type of projects by
considering a relationship between the cost of equity and a risk factor coefficient. The risk factor coefficient was
determine on the basis of the volatility of company stock value in stock exchanges compared to the volatility of
8
The value of € is referred to year 2005.
9
Due to the fact that the term “transmission charge” is not applicable for merchant transmission, it has to be
intended as the expected revenue, which a merchant entrepreneur needs for developing the transmission
investment.
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the stock exchange. By this analysis, we obtained WACC = 0.065 for companies under the regulated framework
and WACC = 0.095 for merchant development. Furthermore in the case of the regulated project we took into
account a longer economic lifetime of the interconnection project.
Referring to a very high utilisation of the new transmission infrastructure (e.g. 8000 hours per year,
corresponding to 8 TWh per year), that is considered to be realistic to justify the merchant transmission
approach, the annual charge for an HVDC interconnection project result to be in the range 8 €/MWh10 (first year
of operation) to 3 €/MWh (last year of operation), with an average value of 5.5 €/MWh.
Given that the project investigated is a 1000 MW undersea HVDC cable with a 200 km length, the transmission
charge results to be about 2.75 €/MWh per 100 km. This value is used as a reference in the cost-benefit
assessment of the optimal interconnection corridors for the case of submarine HVDC links.
10
Values in Euro referred to year 2005.
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7. COST-BENEFIT ASSESSMENT FOR EACH INTERCONNECTION CORRIDOR
7.1 Introduction and structure of this section
This chapter presents the details of cost-benefit assessment performed for each major electricity corridor
analysed in the ENCOURAGED “Electricity corridors” study, with special focus on UCTE - Northern Africa;
UCTE - Turkey and UCTE - Eastern Europe.
As for the assessment of optimal electricity transfers, the analysis of the future development of the inter-area or
EU-internal connections referred to a mid-term (year 2015) and a long-term (year 2030) evaluation. Indeed, we
assessed the benefits achievable by step-by-step increases of the transmission capacity and then we compared
these yearly benefits to overnight construction costs related to the realisation of specific interconnection projects
(when possible and applicable, with real interconnection projects already investigated by the concerned
countries and parties). Even if the analysis is limited to the two simulation years 2015 and 203011 due to the
great effort required for modelling of a pan-European wide system composed by more than 40 countries, we
believe that the comparison between total costs for each project and yearly expected benefits in the two
simulation years allows to draw some conclusions on the economic interest to develop the proposed
reinforcements.
However, it is worth to observe that the implementation of each reinforcement needs to be supported by
individual feasibility studies tailored to each project. The value of the ENCOURAGED analysis is the
possibility to define an overall “picture of the recommended optimal electricity corridors” which is not possible
in “local” studies devoted to individual projects.
7.2 Inter-Area Connection UCTE - Northern Africa
We conclude that the future possible reinforcement of the UCTE - Northern Africa interconnection seems to be
an interesting option, at least up to about 5000 MW.
In addition to the purely economic evaluations, considerations on the enlargement of economical and energy
cooperation between the two sides of the Mediterranean Sea, the diversification of energy inputs and the
improved security of supply for Europe, and the possibility to find a new export market for Northern Africa
electricity production raises the interest for these connections. But the very high costs for the development of
submarine HVDC interconnections (estimated to be €400-700 million for a 1000-MW rated link depending on
its length) and their possible consequent impact on the national transmission tariffs, led REE and TERNA, the
transmission system operators of Spain and Italy respectively, not to include in their national transmission
planning these projects up to now. However, their interest in the analysis of possible interconnection options is
proved by the promotion and active participation in several feasibility studies.
11
It is recalled that, for the internal cut-sets, simulations and cost-benefit analyses are limited to the time
horizon 2015 (that is to say in the mid-term). In the long run, it is assumed that the Internal Electricity Market is
completed and transmission network is without major congestion in intra-country cross border connections
among the different EU countries (except the connection among different power pools). On the contrary, the
possible benefits of interconnections with the islands of Cyprus, Iceland and Malta is analysed only in the long
run (i.e. 2030).
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The alternative investment option of merchant transmission, which does not impact on regulated tariffs, could
be a solution. In the case study already presented in the previous section (200 km undersea HVDC link between
UCTE and Northern Africa, with an estimated investment of € 384 million) we showed that the average yearly
“equivalent charge” for a merchant link is about € 45 million each year, which is well below the estimated
yearly benefits (revenues) available to developers of the first UCTE - Northern Africa links. For an effective
development of merchant transmission, a stable climate for investments needs to be guaranteed to the possible
future developers in order to cope with the associated risks. The lack of a stable climate for generation
investments in Northern African countries, which are supposed to experience a massive growth of electricity
demand and consequently of generation capacity in the future 25 years, could reduce the generation
“overcapacity”, determine scarce adequacy of the generation sets and consequently allow lower benefits from
the realisation of the new interconnections. The expected future economic-optimal exchanges of electricity with
Africa will take place if investment plans for generation in Northern Africa will be fulfilled by the countries
(plans for generation: +300% in the period 2005-2030) and if sound operational mechanisms for cross-border
transactions (e.g. extension of existing EU regulations and policies) will be set up.
7.3 Inter-area connection UCTE – Turkey
The future possible reinforcement of the UCTE - Turkey interconnection seems to be an interesting option, at
least up to about 5000 MW. Such reinforcement could be obtained by the realisation of AC overhead lines,
whose estimated costs are about € 70 million for each connection. In addition to economic evaluations,
considerations on the enlargement of economical and energy cooperation, the diversification of energy inputs
and the improved security of supply for Europe, the possibility to find a new market for Turkish electricity
productions could raise the interest for these connections.
Large exports from Turkey (85-100% utilisation of the capacity up to 5000 MW) are foreseen and justify the
economic efficiency of reinforcement projects. This result is directly related to the forecasted massive
development of generation in Turkey, which is expected to face the highest load growth throughout the
ENCOURAGED regions (a 313% load growth in the period 2005-2030).
7.4
Inter-Area Connection UCTE - Eastern Europe
Two sections are considered to analyse the “Eastern border”: Russian Federation / Belarus+Ukraine and
Belarus+Ukraine / UCTE.
Thanks to existing lines, a 5100 MW transfer capacity is theoretically available at both borders UKR+BY UCTE and Russian Federation - UKR+BY, even if the first one is not fully usable today due to nonsynchronous systems. In case of connection of the IPS/UPS and UCTE systems exploiting these capacities,
large trades in both directions (40 TWh/year) are foreseen, with remarkable seasonal variations. Similar results
are obtained for the borders Baltic - Russia and Finland - Russia, with a bi-directional exchange of
30 TWh/year. Various uncertainties about Russian development (e.g. the level of fuel prices in Russia, the
future of nuclear energy, the level of renewal of the generating set) determine uncertainties on the direction of
future exchanges at IPSUPS borders. If the current lack of investments in the Russian generation sector will
continue, we foresee electricity exports from EU to Russian Federation and Ukraine.
The result of our “data collection” is that the system section at the border between Russia and Ukraine+Belarus
is expected to have in the future a lower transfer capacity than the interconnection between Ukraine+Belarus
and UCTE. For this reason we referred to interconnection reinforcement and consequent NTC increases at the
section between Russia and Belarus+Ukraine. The cost-benefit analysis allows us to conclude that the future
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possible need and the economic efficiency of further developing cross-border capacities with the IPS-UPS
systems (in addition to the aforementioned 5100 MW) are not sure.
7.5 Other inter-area connections
We conclude that the future possible reinforcement of the UCTE - Baltic Countries interconnection (in addition
to the back-to-back project Alytus - Elk which is assumed to be already completed within 2015) are at the costbenefit equilibrium. But some results envisage the risk of a parallel flow12 UCTE - IPSUPS across Baltic
countries. In this sense, the alternative solution of increasing the transfer capacity UCTE - IPSUPS appears to be
a better solution, allowing to increase direct transfers.
The economic interest of the future possible reinforcement of the NORDEL - Eastern Europe (including Baltic
Countries) interconnection, in addition to the ongoing Estlink 350 MW connection project between Estonia and
Finland, is not sure.
The simulations show a clear economic net benefit in the future possible reinforcement of the UCTE NORDEL interconnection given by the AC project Kassø - Audorf. The economic interest in the realisation of
expensive HVDC interconnections (at a cost of several hundreds of million Euro) is not achieved.
Finally, we conclude that the future possible reinforcement of the UCTE - British Islands interconnection does
not appear to be economically efficient, especially due to the high costs of HVDC links (e.g. € 300-400 million
for the BritNed project). Also the realisation of the North Sea Interconnector does not appear to be economically
efficient, due to the extremely high costs of the HVDC link (€ 1000 million). A future technological
development of the DC technology and a possible consequent reduction of costs could determine a less
unfavourable assessment.
7.6 Interconnection with Iceland, Malta and Cyprus
Interconnection with Iceland, Malta and Cyprus were analysed in the long term (year 2030).
The realisation of electrical interconnections with Iceland appears to be an interesting option, even if the costs of
the HVDC links are extremely high (€ 695 million for a 600-MW rated cable between Scotland and Iceland).
But it has to be underlined that the benefits calculated for the case “Iceland” do not take into account the costs
and investments needed for the development of the new “equivalent generator” from renewable sources in
Iceland. In other words, the injection from Iceland was assumed to have no fuel cost in the sensitivity analysis.
The future value of “clean energy” for Europe, such as the geothermal and hydro productions of Iceland, is a
key factor for the possible development of new transmission links Iceland - European Union.
12
The term “parallel flow” here adopted does not mean a physical parallel flow of power (because the grid is
not represented and because the BTB solutions could allow control of power flows), but intends to highlight the
pattern of power which could flow across the BTBs at the border UCTE - Baltic Countires. The possible future
need of reducing transfer at the border UCTE - Baltic Countries to avoid the physical parallel flow of power has
to be assessed with technical studies.
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We analysed the realisation of a new interconnection between Italy and Malta, because the southern coast of
Sicily is closer and closer to Malta than the Northern African countries. Additional reasons for this choice are
that:
•
it is possible that the relatively small distance (100 km) Sicily - Malta13 could allow the realisation of an AC
synchronous connection;
•
a possible transit flow from Northern Africa to Malta across Sicily, after the realisation of Northern Africa .
Italy links, should not represent a major problem for the Sicilian grid, due to the relatively low power
transfers involved (e.g. 300 MW).
It is worth to note that in the optimisation analysis a constraint on the maximum import of Malta (and Cyprus)
island systems was considered to take into account the technical constraints related to the need of dynamic
response of the island system and an increased amount spinning reserve. It is supposed that the island cannot
import more than 40% of its load demand14.
We conclude that in the long-term the realisation of an electrical interconnection between Italy and Malta by
means of 2x150 MW AC cables or a 300 MW DC cable seems to be an economically interesting solution. In the
short run, it can be argued that the benefits could be lower, due to the lower energy transfers (lower load in
Malta: today annual energy consumption is slightly above 2 TWh, in 2030 it is expected to grow up to 5 TWh).
It has to be underlined that the benefits calculated for the year 2030 depends on the rough assumption that the
Malta system cannot import more than 40% of its load demand due to security reasons. A detailed feasibility
study should be performed to evaluate the technical constraints needed for the security of the power system. On
the other hand, should an AC connection be feasible, various technical benefits would be given by the
synchronous operation.
Concerning the realisation of an electrical interconnection between Turkey and Cyprus by means of e.g. a
500 MW DC cable, we conclude that it looks to be efficient in the long term. As for the case of Malta, it can be
argued that the benefits in the short run could be lower, due to the lower energy transfers (lower load in Cyprus)
and a tailored feasibility study should evaluate the technical constraints needed for the security of the power
system.
7.7 Internal EU cut-sets
It was concluded that in the mid-term the realisation of a first reinforcement of the interconnection France Spain is economically efficient. On the contrary, the cost-benefit balance for a second reinforcement is not fully
achieved, also due to the long distance to be crossed by the future AC line. It must be underlined that the benefit
associated to the second reinforcement is significantly lower than the first one15, according to the theory of
decreasing marginal benefits for further increases of transmission capacities.
Concerning the cut set between France and the German block it is difficult to conclude if further interconnection
reinforcements (in addition to the first Avelin - Avelgem) are economically efficient or not, also due to the very
small cost figures involved with respect to other borders (about € 20 million).
13
The distance of the link was estimated on a geographical map by a straight line. As for all the submarine
cables, survey of the seabed are needed to define the feasible route.
14
We are well aware that this figure must be evaluated with tailored technical calculations and that the proposed
value is purely subjective.
15
This is probably due to the fact that the first reinforcement allows to double the current NTC France - Spain.
page 28/33
At the Italian northern border it seems that the joint set of the three proposed interconnection reinforcements
(one line to France, one to Austria and one to Slovenia) do not fully reach the cost-benefit balance in the midterm (year 2015). The result could look to be very strange given that Italy is at present the largest European
electricity importer, with a significant price difference with respect to the other EU countries, but it should be
mentioned that in winter 2005-2006 a reduction of the price differentials between Italy and rest of Europe was
registered, leading to unexpected situations of Italian export towards the neighbouring countries. A future
electricity price convergence to the EU average level appears possible for Italy, also due to the ongoing massive
development of combined cycle plants in the country, plants which could result to be the system marginal unit
in various countries throughout Europe.
Finally, the relatively less expensive reinforcement of the interconnection Germany+Austria / Poland+Czech
Republic+Hungary - two projects with costs below € 50 million - could reach a cost-benefit equilibrium in the
mid-term (year 2015). However, this result is weakened by the lack of information about the possible gains of
transfer capacity with these projects.
page 29/33
8. SYNTHESIS OF DISCUSSION WITH STAKEHOLDERS AND RECOMMENDATIONS
The consultation process with stakeholders during the ENCOURAGED project revealed a number of barriers
for the exploitation and development of electricity corridors. The major obstacles, different in nature at the
various borders, are:
•
between Turkey and South East Europe, the current obstacle for the exploitation of existing and underconstruction interconnection capacity is mainly technical (i.e. the need of adaptation of the Turkish power
system to UCTE standards, especially concerning the improvement of frequency control);
•
at the ‘Eastern Europe’ border, the main technical barrier is the asynchronous operation of the large power
systems IPS/UPS, UCTE and NORDEL. This issue determines the need of relatively large investments,
whose allocation among countries remains a point of discussion;
•
between Northern Africa and Southern Europe, national Transmission System Operators (TSOs), and their
countries, are interested in new interconnection projects as is clearly demonstrated by various feasibility
studies. But the possible impact of very high investments on national tariffs is today an important drawback.
For this reason Red Eléctrica de España (Spain) and Terna Rete Elettrica Nazionale (Italy) do not include
interconnection projects with Northern Africa in their present national transmission planning. The
alternative to regulated investment, namely a ‘merchant’ approach with private investors, is now under
investigation by some companies and seems to be a feasible alternative option.
The discussions with stakeholders revealed that the financing of electricity corridors is not considered to be a
major barrier for the regulated investments by the TSOs. TSOs are prepared to undertake the necessary
investments in interconnection capacity provided that this is done within a stable regulatory investment climate
and this is supported by the TSO of the neighbouring country. However, the lack of a stable and coherent legal
and regulatory framework for interconnection corridors (incomes of TSOs are often regulated through different
national regulatory schemes) acts as a barrier to investment and as a delaying factor. In addition, long approval
procedures could hinder grid development. Regulation should be made more stable and predictable and possibly
harmonised and authorisation procedures should be faster and more efficient.
According to some discussants, there could be a conflict of interest between electricity generating companies
and the social objectives of TSOs. This aspect could represent a barrier to investments when generation
companies have a certain control on the investment decisions of the TSO. Even if there is no general consensus
on this statement, it could be recommended to improve the current process towards unbundling of TSOs,
particularly including ownership independence from major electricity companies.
While policy and regulatory risks hamper the realisation of regulated electricity corridors, market risks are
mainly associated with merchant corridors. These market risks stemming from inefficient and flawed price
signals can be mitigated through the acceptance of long-term contracting and supporting instruments for
international joint-ventures. In order to minimise the negative impact of long-term contracting on wholesale
market competition attention should be given to the presence of competitive elements in these long-term
contracts. In case of merchant joint-ventures it should be recognised that a proper evaluation and sharing of
project costs/risks and of project revenues among the involved companies is a basic precondition to the
development of interconnection corridors. Furthermore, the role of regulators and TSOs in merchant electricity
corridors should be clarified. Regulators should provide guidelines on exemption from third party access, in
compliance with Regulation 1228/2003/EC, to potential merchant developers and, with the support of TSOs if
needed, ensure their compliance. The potential role of a “public” TSO in merchant projects is questionable and
should be clarified too.
page 30/33
In either regime, regulated or merchant, the risk of wasting public or private money can be reduced by
improving the reliability of the investment signal provided by the liberalised electricity markets. Therefore
policy-makers and regulators should improve the investment conditions for interconnections between EU and
neighbouring countries: the removal of wholesale market price distortions (e.g. through market concentration,
market captivity etc.), if present, and the implementation of market-based mechanisms for cross-border capacity
allocation can assist electricity corridor investors providing more reliable price information signals for
investment.
Furthermore, increased coordination of TSOs on a regional level would enhance the transparency and feasibility
of both regulated and merchant electricity corridor projects. Regional coordinated planning should be further
improved to optimise the total system for the benefit of all consumers in the region.
The recent decision on European energy priority projects16 proves an increased EU awareness of the importance
of electricity corridors between EU and its neighbouring countries: two out to 31 electricity projects of
European interest concern the main borders of the European Union and involve an EU Member State and a
(current) neighbour. They are the line between Greece and Turkey (priority axis EL.4) and the “electrical
connection to link Tunisia and Italy” (priority axis EL.9)17. It is recommended that this awareness will be
increased in the future. A more explicit role for social cost-benefit analysis can assist the national, regional and
EU governmental and regulatory bodies in the assessment of the impact of the proposed projects on
sustainability, competition and security of supply. When an interconnection project is evaluated as beneficial for
the country and for EU, proper financial support schemes need to be defined to favour its development.
Furthermore, new mechanisms for monitoring the status, the progress and the possible problems in development
of electricity projects should be enforced at national, regional and EU level.
16
Decision No 1364/2006/EC of the European Parliament and of the Council of 6 September 2006 laying down
guidelines for trans-European energy networks and repealing Decision 96/391/EC and Decision No
1229/2003/EC.
17
The border between Denmark and Norway (and the related project of submarine cable Skagerrak 4) is not
included in our definition of ‘main EU borders’.
page 31/33
9. SYNTHESIS OF CONCLUSIONS
The ENCOURAGED “Electricity Corridors” study performed an assessment of the optimal network
expansions, leading to the realisation of efficient transmission/interconnection corridors between European
Union and the neighbouring countries up to 2030, by means of a multi-area optimisation analysis and a followup detailed cost-benefit assessment for each corridor.
A significant growth of electricity trades is expected for future cross-border exchanges at EU boundaries, with
respect to current trades Finland - Russian Federation, Central Europe - Ukraine, and Spain - Morocco (total
about 20 TWh/year). Nevertheless, the total exchanges at the “main borders” (South border with North Africa,
South-East border with Turkey, East border with IPS/UPS system) will represent a relatively small percentage
of electricity demand in the EU and neighbouring regions. The exchange volumes (calculated as sum of the
exchanges in each direction) are estimated to range from 110 TWh/year up to 180 TWh/year, that is from
10 Mtoe to 15 Mtoe, which correspond to 2-4% of total electricity demand in EU-27 (about 4700 TWh/year in
2030) or 1-2% of total electricity demand in the 44 countries investigated in the study (8000 TWh/year in 2030).
Consequently, the assessed optimal electricity exchanges have not to be seen as a substitute of gas imports for
the European Union, but they will have a complementary role to gas trades. Electricity exchanges are expected and have to be optimised - to complement the forecasted large imports of natural gas.
Regarding the optimal development of electricity interconnection capacity between EU and neighbouring
countries, the main results of the study are:
•
Need of new cross-border capacity between Turkey and South-Eastern Europe
Large exports from Turkey (85-100% utilisation of the capacity) are foreseen. A 2000 MW short-term transfer
capacity is expected for the next years, while currently the interconnection is out of operation due to technical
reasons. An increase of transmission capacity up to 5000 MW is economic-efficient in the long run, using AC
overhead lines, whose estimated costs are about € 70 million for each connection.
•
Need of new interconnection capacity between Northern Africa and Southern Europe.
Despite the high investment costs (e.g. €400 million for a 1000 MW submarine link), large benefits can be
gained by means of large exports from Northern Africa, as the 90-100% utilisation rate of the available capacity
shows. The benefits could justify an increase of the interconnection capacity up to about 5000 MW in 2030 (the
current transfer capacity is 800 MW).
The expected future economic-optimal exchanges of electricity with Africa will take place if generation
investment plans for generation in Northern Africa will be fulfilled by the countries (plans for generation:
+300% in the period 2005-2030) and if sound operational mechanisms for cross-border transactions (e.g.
extension of existing EU regulations and policies) will be set up.
National Transmission System Operators, and their countries, are interested in new interconnection projects as
demonstrated by various feasibility studies, but the possible impact of very high investments on national tariffs
is a severe drawback. For this reason Red Eléctrica de España (Spain) and Terna Rete Elettrica Nazionale (Italy)
do not include interconnection projects with Northern Africa in their national planning. The “merchant”
approach with private investments, which is now under investigation by some companies, appears to be a
feasible alternative option.
•
Expectation of large bi-directional electricity trades at the “Eastern Europe” border
Thanks to existing lines, a 5100 MW transfer capacity is theoretically available at both borders Ukraine+Belarus
- UCTE and Russian Federation - Ukraine+Belarus, even if the first one is not fully utilized today due to nonpage 32/33
synchronous systems and consequent “island mode” operation. The opportunity to interconnect the IPS/UPS
and UCTE systems and to exploit these existing capacities is emphasized by large trades (40 TWh/year) in both
directions foreseen by the ENCOURAGED study. A similar result is obtained for the borders Baltic Countries Russian Federation and Finland - Russian Federation, with total exchanges about 30 TWh/year.
The bi-directionality of the expected electricity trades is characterised by remarkable seasonal variations.
Especially in the cold period, UCTE and NORDEL are expected to supply electricity to the IPS/UPS system,
contributing to face severe peak loads in Russian Federation and in Ukraine and reducing the need of electricity
production from obsolete power plants. This “unexpected” phenomenon witnesses the need and the importance
of interconnection capacity expansion for the neighbouring countries too.
Various uncertainties about Russian development (e.g. the level of fuel prices in Russia, the future of nuclear
energy, probably the level of renewal of the generating set too) determine uncertainties on the direction of future
exchanges at IPS/UPS borders. In particular, if the current lack of investments in the Russian generation sector
will continue we foresee net electricity exports from the EU towards the Russian Federation. The need and the
economic efficiency of further developments of the cross-border capacity between UCTE and IPS/UPS systems
(in addition to the aforementioned value: 5100 MW) appears to be not sure in the long run.
•
Need to connect the Mediterranean island countries in the long run
The analyses evidenced the opportunity to interconnect the Mediterranean island countries to the pan-European
system (a connection Cyprus - Turkey rated about 500 MW and a connection Malta - Italy rated about 300 MW)
in a long-term horizon. Especially for these possible interconnections, we remind that the aim of the
ENCOURAGED project is to give a wide system overview, covering a very large area. It should therefore be
seen a preliminary analysis pointing out the need of detailed feasibility studies on specific projects, which will
better take care of the technical issues.
According to the assessment of optimal interconnections at “EU main borders”, the total investments needed for
the realisation of these economic optimal infrastructures are estimated as:
•
at least € 300 million to realise four new alternating current (AC) lines between Turkey and EU;
•
about € 2000 million to realise four submarine high voltage direct current (HVDC) links between Northern
Africa and Southern Europe (rating: 1000 MW each cable);
•
about € 200 million to realise a submarine HVDC link connecting Turkey and Cyprus.
The investments needed for a “first-step” future interconnection between the Eastern Europe countries
(European part of Russian Federation, Belarus, Ukraine and Moldova) and the UCTE system were not
quantified, because these figures are strongly dependent on the technical solutions which will be adopted. The
list of necessary investments and their associated costs to be made on both sides of the investigated electrical
interface are one of the main objectives of the ongoing feasibility study “Synchronous Interconnection of the
Power Systems of IPS/UPS with UCTE”, financed by the European Commission. This study is also expected to
present in 2008 an open outlook on other non-synchronous system coupling possibilities with the aim at a global
benchmark in terms of economic efficiency for the investigated system coupling.
In addition to the aforementioned uncertainties on future development of generation mix and capacity in
Russian Federation, Northern Africa and Turkey, it is worth to remind that technical compatibility and future
transmission development in these countries and the energy price level in medium and long term in these
regions and versus EU are the major uncertainties of the study.
page 33/33

ENCOURAGED Project title

Transcription

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