5th research framework programme of the european union · decent final report summary izt, cogen...

W. Joerss, B. H. Joergensen, P. Loeffler, P.E. Morthorst, M.A. Uyterlinde, E.J.W. van Sam-beek, T. Wehnert, B. Groenendaal, M. Marin, H. Schwarzenbohler, M. Wagner

5th Research Framework Programme

of the European Union

Energy, Environment and Sustainable Development, Part B Energy

Decentralised Generation Technologies

Potentials, Success Factors and Impacts in the Liberalised EU Energy Markets

DECENT

Final Report

Contract NNE5-1999-593

IZT Institute for Futures Studies and Technology Assessment gGmbH

COGEN Europe – European Association for the Promotion of Cogeneration

RISØ National Laboratory

ECN Netherlands Energy Research Foundation

unit[e] unit energy europe ag

Jenbacher AG

October 2002

Project Co-Ordinator: Wolfram Jörß IZT - Institute for Futures Studies and Technology Assessment Schopenhauerstr. 26; 14129 Berlin; Germany [email protected] phone: +49 30 803088-17 fax: -88

DECENT Final Report

IZT, COGEN Europe, RISØ, ECN, unit[e] and Jenbacher October 2002

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Authors:

IZT: Wolfram Jörß Timon Wehnert COGEN Europe: Peter Löffler Mercedes Marín Nortes RISØ: Poul Erik Morthorst Birte Holst Jørgensen ECN: Martine Uyterlinde Emiel van Sambeek Bas Groenendaal unit[e]: Heinz Schwarzenbohler Jenbacher: Michael Wagner

DECENT Final Report Summary


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Summary In the coming 20 years, decentralised generation (DG) is expected to play an increasingly important role in the European electricity infrastructure and market. DG can be defined as small-scale generation connected to the distribution network or on the customer side of the meter. The application of DG is often highly location specific and depends on such diverse issues as the possibilities of technical implementation, resource availability, environmental aspects, social embedding of the project, regulation and market conditions. These factors vary considerably among technologies and among the EU Member States. The DECENT project has identified the main barriers and success factors to the implementa-tion of DG projects within the EU and has formulated a number of related recommendations to EU and Member State policy makers to enhance the feasibility of DG projects within the internal energy market. Most of the barriers identified are attributable to electricity regulatory regimes that hardly recognise the values of DG, in particular those related to environmental benefits, to electrical or grid services, and to security of supply in the EU. It is therefore essential that future energy policies for the electricity sector acknowledge and value the qualities of DG. Considering the ongoing trend of liberalisation and the increased use of market mechanisms as policy instru-ments it is recommended to take an approach to policy development that is market compati-ble. The ultimate goal should be to design markets that ensure a level playing field for central-ised and decentralised generation. Markets must be open and transparent, and should give fair chances to different types of actors. Finally, in the long run, the environmental values of DG should be acknowledged in a market compatible manner while energy prices reflect external costs.

Tackling DG connection and system integration barriers

DG connection and system integration can be improved by enhancing the transparency on the terms, conditions, and procedures for connection. Particularly important in this regard is the standardisation of the technical interface between DG and the grid, and the existence of clear non-discriminatory rules on the allocation and sharing of connection costs. These cost alloca-tion rules should take into account the benefits of DG to the network, such as avoided grid investments and grid losses. However, the application of these recommendations may be in-sufficient when network companies have incentives not to connect DG under the applicable regulatory regime. Economic regulation of network companies should therefore be neutral to the integration of DG into the network. Furthermore, stricter unbundling of network opera-tions and ownership from generation and supply of electricity is a prerequisite to prevent such incentives on the part of network companies.

Improving DG authorisation and permitting procedures

Acquiring authorisation and planning consents for the establishment of DG installations is a major barrier to many projects, due to non-transparent and time-consuming procedures, as well as local opposition. Furthermore, network planning and spatial planning and planning of the use of renewable energy sources (RES) currently take place in a non-co-ordinated manner, thus raising the cost of DG integration. The means to overcome this barrier are streamlining

DECENT Final Report Summary


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planning and authorisation procedures for small-scale RES and combined heat and power (CHP) production, involvement of local actors, pro-active designation of areas for DG devel-opment in spatial plans for RES and heat planning for CHP, and finally co-ordination of spa-tial planning, network planning and integration of RES.

Enhancing the financing of DG

Due to the lack of a level playing field in present electricity markets, and because the external cost of electricity production are not reflected in the prices, many DG technologies need fi-nancial support to be viable under current market conditions. In the long run, internalising the environmental benefits of DG should diminish the need for support. However, in the mean-time, support mechanisms should be market compatible and in line with the trend of liberali-sation. To reduce the uncertainty to investors, support policies should take into account and anticipate the future harmonisation of support frameworks across the EU. With a view to pro-viding a more stable long-term policy framework, it is desirable that long-term targets for the integration of renewables and cogeneration are fixed at the EU level. As many DG projects are set up by small-scale players, it is important to reduce the transaction costs in using sup-port mechanisms and in operating on the electricity market.

Recommendations for further research

There are many subjects that are important to the integration of DG in EU electricity systems which could not be studied within the DECENT project, but which deserve further attention in future research projects. First, given the expected growth of the market share of intermittent renewables and heat-based CHP, the costs of imbalances will become increasingly important, and the application of priority dispatch mechanisms may become increasingly less feasible. Therefore, further research on technical and market solutions to balancing problems is crucial. Secondly, it is recommended that further research on the role of information and communica-tion technology (ICT) in co-ordinating market and network operations should be conducted.

DECENT Final Report Contents Overview


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Contents Overview Summary ...................................................................................................................................iii Contents Overview....................................................................................................................v Table of Contents .....................................................................................................................vi List of Annexes .........................................................................................................................ix List of Tables..............................................................................................................................x List of Figures...........................................................................................................................xi Acknowledgements ..................................................................................................................xii 1 Introduction......................................................................................................................1 2 What is Decentralised Generation? ...............................................................................3 3 Outline of Research Methodology ..................................................................................5 4 Status Quo and Developments of DG Technology ......................................................17 5 Liberalisation and Decentralised Generation in the EU Member States.................79 6 Scenarios: Europe’s DG Power Generation in the Year 2020...................................95 7 Case Study Analysis.....................................................................................................107 8 Barriers and Success Factors for DG.........................................................................129 9 Policy Implications .......................................................................................................140 10 Security of Supply in Relation to the Deployment of Decentralised Energy

Technologies.................................................................................................................193 11 EU Energy Technology R&D Policy ..........................................................................203 12 Conclusions and recommendations ............................................................................211 References..............................................................................................................................217 Annexes ........................................................................................see List of Annexes, page ix

DECENT Final Report Table of Contents


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Table of Contents Summary ...................................................................................................................................iii Contents Overview....................................................................................................................v Table of Contents .....................................................................................................................vi List of Annexes .........................................................................................................................ix List of Tables..............................................................................................................................x List of Figures...........................................................................................................................xi Acknowledgements ..................................................................................................................xii 1 Introduction......................................................................................................................1 2 What is Decentralised Generation? ...............................................................................3 3 Outline of Research Methodology ..................................................................................5

3.1 The 4-Dimensional Analytical Approach in DECENT............................................5 3.2 DG Project Stages ....................................................................................................7

3.2.1 Detailed Characterisation of the Implementation of a DG project.............7 3.3 Conceptual Framework ..........................................................................................13

4 Status Quo and Developments of DG Technology ......................................................17 4.1 Renewable Energy Sources ....................................................................................17

4.1.1 Photovoltaics ............................................................................................17 4.1.2 Wind Turbines ..........................................................................................20 4.1.3 Hydro power.............................................................................................30 4.1.4 Biomass ....................................................................................................35

4.2 Combined Heat and Power (CHP) .........................................................................44 4.2.1 Steam Turbines.........................................................................................44 4.2.2 Reciprocating Engines..............................................................................45 4.2.3 Gas Turbines ............................................................................................46 4.2.4 Combined Cycle Gas Turbines ................................................................47 4.2.5 New Small-Scale CHP Technologies.......................................................47 4.2.6 Fuel Cell Technology...............................................................................49

4.3 Future Decentralised Energy Systems 2020...........................................................59 4.3.1 Introduction..............................................................................................59 4.3.2 General Remarks......................................................................................59 4.3.3 General Framework Topics Important for Decentralised Energy

Generation in the EU up to 2020..............................................................61 4.3.4 Ranking of Topics ....................................................................................62 4.3.5 Environment and Cost of Energy.............................................................65 4.3.6 Period of Occurrence................................................................................69 4.3.7 Constraints for Realising the Topic..........................................................73 4.3.8 Other Comments of Survey Respondents ................................................78

5 Liberalisation and Decentralised Generation in the EU Member States.................79 5.1 Status of Electricity Market Liberalisation in the EU Member States ...................79

5.1.1 The Directive on Liberalisation of the Electricity Market .......................79 5.1.2 Overview on Member States....................................................................83

5.2 Use of Renewables.................................................................................................85 5.2.1 Motivations for RES-support ...................................................................86 5.2.2 Type of Support........................................................................................86

5.3 Use of CHP.............................................................................................................90 5.3.1 CHP Policies ............................................................................................90 5.3.2 CHP Support Schemes in the EU Member States....................................91



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6 Scenarios: Europe’s DG Power Generation in the Year 2020...................................95 6.1 Scenario I – Green Power and Nuclear Ecology....................................................98 6.2 Scenario II – Huge Fossils ...................................................................................101 6.3 Scenario III – Widespread Economic Niches ......................................................103 6.4 Scenario IV – Hip Ecology ..................................................................................105

7 Case Study Analysis.....................................................................................................107 7.1 Expert Interviews .................................................................................................107 7.2 Choice of Case Studies.........................................................................................122 7.3 Short Presentation of Case Studies.......................................................................123

8 Barriers and Success Factors for DG.........................................................................129 8.1 Characterisation of Actors....................................................................................129 8.2 Identified Barriers and Success Factors ...............................................................130

8.2.1 Policy/ Institutional Dimension..............................................................132 8.2.2 Market/ Financial Dimension.................................................................135 8.2.3 Technological Dimension ......................................................................137 8.2.4 Social and Environmental Dimension....................................................138

9 Policy Implications .......................................................................................................140 9.1 Introduction..........................................................................................................140 9.2 Authorisations and Permitting..............................................................................144

9.2.1 Construction Permits and Spatial Planning............................................144 9.2.2 Local Resistance.....................................................................................148 9.2.3 Permitting Problems for Biomass Plants based on wood or waste ........150

9.3 Grid Connection...................................................................................................152 9.4 Market Access and Contracting ...........................................................................162

9.4.1 Balancing and Settlement Systems ........................................................162 9.4.2 Transaction Costs ...................................................................................166 9.4.3 Gas Liberalisation ..................................................................................166

9.5 Financing..............................................................................................................168 9.5.1 Financing Issues, Barriers and Solutions ...............................................168 9.5.2 Support Mechanisms ..............................................................................171

9.6 Operation..............................................................................................................174 9.6.1 Grid Use Fees.........................................................................................174 9.6.2 Ratio of Gas and Electricity Prices for CHP ..........................................180 9.6.3 Biomass Fuel Supply..............................................................................182

9.7 Barriers and Success Factors not Specific to a Particular Stage ..........................183 9.7.1 Other Benefits of Decentralised Generation ..........................................183 9.7.2 Uncertainty on Policy Development ......................................................184 9.7.3 Market Power of Utilities .......................................................................187 9.7.4 Specific Difficulties of Small Independent Power Producers (IPPs) .....188 9.7.5 Lack of the Skills Required to Plan and Install a CHP Plant .................188

9.8 Policy Implications of the Outlook to 2020 .........................................................190 9.8.1 Scenario I – Green Power and Nuclear Ecology....................................191 9.8.2 Scenario II – Huge Fossils .....................................................................191 9.8.3 Scenario III – Widespread Economic Niches ........................................191 9.8.4 Scenario IV – Hip Ecology ....................................................................192

10 Security of Supply in Relation to the Deployment of Decentralised Energy Technologies.................................................................................................................193 10.1 Introduction..........................................................................................................193 10.2 The Dependence of the Energy Supply on Imported Fuels .................................193 10.3 The Availability of the Required Energy Production Capacity ...........................195



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10.4 Evaluation of Decentralised Plants in Relation to Security of Supply.................196 10.4.1 Criteria for Evaluating decentralised plants...........................................196 10.4.2 Substitution of Imported Fuels ...............................................................196 10.4.3 Reliability...............................................................................................197 10.4.4 Flexibility ...............................................................................................197 10.4.5 Economic Attractiveness ........................................................................198 10.4.6 Financial Risk.........................................................................................199 10.4.7 Vulnerability...........................................................................................200

10.5 Conclusions and Recommendations .....................................................................200 11 EU Energy Technology R&D Policy ..........................................................................203

11.1 Introduction..........................................................................................................203 11.2 EU Research and Development Policy ................................................................203 11.3 Assessment of Non-Nuclear Energy Proposals....................................................205 11.4 Results From the DECENT Futures study...........................................................206 11.5 The Future of European Energy Research ...........................................................208 11.6 Conclusion............................................................................................................209

12 Conclusions and recommendations ............................................................................211 12.1 DG interconnection and system integration.........................................................211 12.2 DG authorisations and permitting ........................................................................213 12.3 Financing DG .......................................................................................................213 12.4 The impact of DG on the security of supply ........................................................214 12.5 EU energy technology R&D................................................................................215 12.6 Recommendations for further research................................................................216

References..............................................................................................................................217 Annexes .........................................................................................see List of Annexes, page ix

DECENT Final Report List of Annexes


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List of Annexes Annex A: EU energy legislation applicable to DG Annex B: Survey Questionnaire of the DECENT Futures Study Annex C: Expert Interview Reports Annex D: Hypotheses on Barriers and Success Factors for DG Annex E: Case Study Reports

DECENT Final Report List of Tables


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List of Tables Table 3-1: DG project implementation stages.............................................................................9 Table 4-1: Average PV costs in Germany.................................................................................19 Table 4-2: Cost structure for a 1MW wind turbine ...................................................................22 Table 4-3: Investment costs related to the Tunø Knob wind farm............................................27 Table 4-4: Unit costs for hydropower in the EU.......................................................................32 Table 4-5: Investment and Unit Costs for Small Hydro Plants.................................................33 Table 4-6: Cost of biomass technologies ..................................................................................40 Table 4-7: Emissions from biomass fired processes .................................................................41 Table 4-8: Steam turbine characteristics ...................................................................................45 Table 4-9: Reciprocating engine characteristics .......................................................................46 Table 4-10: Gas turbine characteristics .....................................................................................47 Table 4-11: Combined cycle gas turbine characteristics...........................................................47 Table 4-12: Micro Turbine characteristics................................................................................48 Table 4-13: Stirling engine characteristics ................................................................................49 Table 4-14: Key properties of a PEM fuel cell .........................................................................50 Table 4-15: Key proportion of a DMFC fuel cell .....................................................................51 Table 4-16: Key properties of a SOFC fuel cell........................................................................53 Table 4-17: Key properties of a PAFC fuel cell........................................................................54 Table 4-18: Key properties of a MCFC fuel cell ......................................................................56 Table 4-19: Key properties of an Alkaline fuel cell..................................................................57 Table 4-20: Impact of topics on decentralised energy generation in the EU. ...........................61 Table 4-21: Characteristics of top ten topics.............................................................................63 Table 4-22: Barriers to the Top Ten Topics ..............................................................................64 Table 4-23: Higher middle list ..................................................................................................64 Table 4-24: Lower middle list...................................................................................................65 Table 4-25: Bottom list .............................................................................................................65 Table 4-26: Top ten of beneficial impact on global environment.............................................66 Table 4-27: Bottom list of beneficial impact on global environment .......................................67 Table 4-28: Top ten [nine] list of beneficial impact on cost of energy.....................................68 Table 4-29: Bottom list of beneficial impact on cost of energy................................................68 Table 4-30: ”Never” responses .................................................................................................69 Table 5-1: Overview on Liberalisation Status of EU Member States (I)..................................83 Table 5-2: Overview on Liberalisation Status of EU Member States (II) ................................84 Table 5-3: Support systems for electricity from renewable energy sources in the EU.............88 Table 5-4: Share of Renewable Energy Sources in Gross Inland Energy Consumption..........89 Table 5-5: CHP Support Systems in the EU Member States ....................................................92 Table 7-1: Expert Interview Partners in DECENT .................................................................108 Table 7-2: Leading questions of expert interviews .................................................................109 Table 7-3: Key results from expert interviews ........................................................................110 Table 7-4: Overview on Case Studies.....................................................................................122 Table 8-1: Overview on barriers and success factors for DG .................................................131 Table 9-1: Examples of schemes to involve local actors in the development of a DG

project ...................................................................................................................149 Table 10-1: Overview of the evaluation results for decentralised technologies .....................201 Table 11-1: Ratings for selected groupings of energy proposals ............................................205 Table 11-2: Top ten of beneficial impact on global environment...........................................207 Table 11-3: Top list of beneficial impact on cost of energy ...................................................208 Table 11-4: Financial overview of 5th and 6th Framework Programmes.................................208

DECENT Final Report List of Figures


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List of Figures Figure 3-1: The four analytical dimensions in DECENT ...........................................................5 Figure 3-2: Conceptual framework of DECENT analytical methods. ......................................13 Figure 3-3: Links between working steps in DECENT ............................................................15 Figure 4-1: Wind turbine sizes and productivities. ...................................................................21 Figure 4-2: Wind turbine costs..................................................................................................23 Figure 4-3: Wind Energy Unit Costs.........................................................................................24 Figure 4-4: Off-shore wind energy unit costs I.........................................................................28 Figure 4-5: Off-shore wind energy unit costs II........................................................................29 Figure 4-6: Hydropower Principle ............................................................................................30 Figure 4-7: Cost structure for a new hydropower plant ............................................................32 Figure 4-8: Level of expertise of survey participants ...............................................................60 Figure 4-9: Expertise of survey participants according to energy type.....................................60 Figure 4-10: Combined index of global environmental impact and cost production

impact.....................................................................................................................62 Figure 4-11: Index of beneficial impact on global environment ...............................................66 Figure 4-12: Index of beneficial impact on cost of energy production.....................................67 Figure 4-13: Time of occurrence for all decentralised energy topics .......................................69 Figure 4-14: Time of occurrence by energy types ....................................................................70 Figure 4-15: Time of occurrence for wind power topics ..........................................................70 Figure 4-16: Time of occurrence for PV topics ........................................................................71 Figure 4-17: Time of occurrence for biomass topics ................................................................71 Figure 4-18: Time of occurrence for small hydro topics ..........................................................72 Figure 4-19: Time of occurrence for CHP topics......................................................................72 Figure 4-20: Time of occurrence for fuel cell topics ................................................................73 Figure 4-21: Barriers for realising the topics ............................................................................73 Figure 4-22: Barriers for realising the topic by energy type .....................................................74 Figure 4-23: Barrier for wind power topics ..............................................................................75 Figure 4-24: Barriers for PV topics...........................................................................................75 Figure 4-25: Barriers for biomass topics...................................................................................76 Figure 4-26: Barriers to small hydro power topics ...................................................................76 Figure 4-27: Barriers to CHP topics..........................................................................................77 Figure 4-28: Barriers to Fuel Cell topics...................................................................................77 Figure 5-1: Renewables' share of electricity generation in EU Member States, 1996..............89 Figure 5-2: Approximate CHP share of total electricity production in EU Member States

in 1998....................................................................................................................91 Figure 6-1 : Four scenarios characterised by 2 drivers .............................................................96 Figure 7-1: Expert Interviews per EU Member State .............................................................107 Figure 7-2: Expert Interviews per Technology Focus .............................................................107 Figure 7-3: Distribution of Case Studies Generation Technologies .......................................123 Figure 7-4: Distribution of Case Studies on EU Member States ............................................123 Figure 9-1: DG and the legal and regulatory environment .....................................................141 Figure 9-2: Actor-phase diagram for DG in a liberalised market ...........................................143 Figure 9-3: Classifying renewables support mechanisms .......................................................172 Figure 9-4: Drivers for scenarios for DG futures in 2020.......................................................190 Figure 10-1: Business as usual scenario for final energy consumption in the European

Union until 2030...................................................................................................193 Figure 10-2: Business as usual scenario for energy supply originating from within the

European Union until 2030. .................................................................................194 Figure 10-3: The EU dependence on imported energy resources. ..........................................194

DECENT Final Report Acknowledgements


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Acknowledgements The authors would like to thank the following persons that facilitated the successful execution of the DECENT project through their valuable contributions as interview partners, case study contact persons, reviewers and/or linguistic advisors. Thomas Ackermann, Royal Institute of Technology (KTH), Sweden José Luis García Angulo, IDAE, Spain André Bandilla, Plambeck Neue Energien, Germany Femke Bartels, Greenpeace Netherlands, Netherlands S.I. Bestebroer, Agency for Research in Sustainable Energy, Netherlands Carlos Itoiz Beunza, EHN, Spain Hilmar Bieder, Tzschelln Hydropower, Germany John Bird, St. Pancras & Humanist Housing Association, UK Martin Bogaard, Nuon International/ Renewable Energy, Netherlands Mads Borup, RISØ, Denmark Rien Bot, Nuon, Netherlands Gilles Boving, Ministry of the Flemish Community, Belgium Martin Bucher, Voltwerk, Germany Marcello Capra, ENEA, Italy Eugene Cross, ECN, Netherlands Gabriela Prata Dias, CEEETA, Portugal Pamela Finzer, unit[e] Germany Anna Fraccalvieri, Ancinale Idroelettrica, Italy Amparo Fresneda Garcia, IDAE, Spain Reinhard Göttlicher, unit[e], Germany Walter Graf, ARGE Biogas, Austria Reinhard Grünwald, Office for Technology Assessment at the German Parliament

(TAB), Germany J.H.P. Haagen, Medisch Centrum Alkmaar, Netherlands Hans Häge, unit[e], Germany Jan Erik Hanssen, DG TREN, European Commission Jeremy Harrison, EA Technology, UK Mark Hinnells, ETSU, UK Andreas Höllinger, unit[e], Germany Cynthia Horn, RISØ, Denmark Jari Ihonen, Lumituuli Oy, Finland Boris Jovkov, unit[e], Germany Helma Kip, EnergieNed, Netherlands Corinna Kleßmann, IZT, Germany Michael Knoll, IZT, Germany Søren Krohn, Wind Turbine Manufacturers’ Association, Denmark Stefan Lang, SenerTec, Germany



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Cerstin A. Lange, Energiekontor, Germany Theo de Lange, ECN, Netherlands Gilles Laroche, Club Cogénération, France Jens Larsen, KMEK, Denmark Jesper Lorentzen, DG TREN, European Commission Lars Malmrup, Turbec, Sweden Lutz Mez, Freie Universität Berlin, Germany Catherine Mitchell, Warwick Business School, UK Gerard Moerman, Public Hospital of Ronse, Belgium João Montez, ECOGEN, Portugal Armin Müller, SenerTec, Germany Carl Henrik Neland, Vindinge Wind Turbine, Denmark Lars Nielsen, DG TREN, European Commission Flemming Nissen, ELSAM, Denmark Bruno Oberhuber, Energie Tirol, Austria Walt Patterson, Royal Institute of International Affairs, UK Inneke Peersman, Cogen Vlaanderen, Belgium Uli Prochaska, MENAG Energie, Germany Josef Raab, Brennpunkt, Germany Elmar Reitter, Association of Small Hydro-Plants (DGW), Germany Siegfried Rettich, Energieagentur Lippe, Germany Fieke Rijkers, ECN, Netherlands Ulrich Sawetzki, Jenbacher, Austria Werner Schnurnberger, German Aerospace Centre DLR/TT, Germany Wolfgang Schönharting, Unit Energy Portugal, Portugal Alwin Schoonwater, Nuon International/ Renewable Energy, Netherlands Bernard Schuijt, Association for Wind turbine owners in North-Holland, Nether-

lands Knut Stahl, T.B.E., Germany P. Steijn, Windpark Zwaagdijk, Netherlands Christoph Strobl, Thöni Industriebetriebe, Austria Søren Tafdrup, Danish Energy Agency, Denmark Bjørn Teislev, Babcock & Wilcox Vølund, Denmark Klaus Thiessen, WISTAsolar, Germany Daniela Velte, Prospektiker, Spain Mark van Wees, ECN Netherlands Jens Windelev, Danish Energy Agency, Denmark A.W.M. van Wunnik, Project Agency for Renewable Energy – PDE, Netherlands



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DECENT Final Report Introduction


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1 Introduction Decentralised generation (DG) technologies have the potential to significantly contribute to savings in CO2-emissions and energy consumption. This applies both for renewable energies and decentralised CHP (combined heat and power) applications. Many studies in the field suggest, that there could be as much as 30 % reduction in final energy consumption if the po-tential could be exploited. To allow for the integration of long-term oriented goals, e.g. environmental concerns, an ap-propriate framework for renewables and decentralised CHP has to be installed. This is needed in order to meet the EU Kyoto-target for CO2-reduction and the 12 % goal for the share of renewable energy in 2010 . A thorough understanding of the relation of the ongoing liberalisa-tion in the Internal energy markets to decentralised generation is of great importance for set-ting an appropriate framework for the markets to develop. As the European energy markets change from a monopoly situation to a more and more liber-alised environment, the potentials for the absorption of decentralised generation technologies also change: The recent liberalisation of the European energy markets has completely changed the way the Energy sector is functioning. New actors have appeared in the energy markets (Independent Power Producers (IPPs), Energy Service Companies (ESCOs), traders of electricity) and decision-makers tend to be much more oriented on short-term benefits to put up with the competition. A key factor for the efficient mobilisation of the existing potential is a thorough understand-ing of success factors on the project level. To overcome the barriers and constraints imposed by the liberalised market framework an efficient strategy is needed. Thus, the objectives of the present study were to identify success factors and impeding factors for decentralised generation in the liberalised European energy markets and to analyse policy implications for the setting of the appropriate frameworks. Taking that decentralised power production based on renewable energy sources and on CHP can significantly contribute to CO2 and energy savings, the guiding research questions can be narrowed down to “How do Decentralised Generators “survive” in the liberalised markets?” and “How can the framework be influenced in order to create a level playing field and thus facilitate the development and operation of decentralised, environmentally friendly genera-tors?”. To that end the study employs a bottom-up approach which directly accesses the experience gained with decentralised generation technologies on project and regional level via a number of case-studies. The results were then linked to an analysis of policy instruments. Supported by the results of a futures study for DG, DECENT thus provides orienting knowledge and technical input to the Commission’s considerations with respect to installing an appropriate framework. The present DECENT final report presents: • the basic analysis of the status and possible developments of DG technologies and mar-

kets, • the critical barriers and success factors that were identified for DG in Europe and

DECENT Final Report Introduction


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• the policy oriented analysis of policy implication in order to come up with conclusions and recommendations for DG-related European policies.

In particular, the final report presents the working definition of “Decentralised Generation” (DG) within DECENT in order to create a clear idea of the subject of the research project and set the basis for comparison with other work done in this field (chapter 2). In the following, an insight into the methodologies used in the project is given (chapter 3). Further on, an update of the status quo of DG technologies and costs is given (chapter 4); this overview is complemented with the results of a survey on expected technology developments among European energy experts (chapter 4.3). In parallel, an overview is given on DG related policies and the use of renewables and CHP in the EU Member States (chapter 5). This is aug-mented by scenarios for Europe’s DG power generation in the year 2020 (chapter 6). Furthermore, the main elements of the empirical analysis of DECENT are given, featuring expert interviews and case study analysis (chapter 7) and critical barriers and success factors for DG in Europe (chapter 8). In the subsequent analysis of policy implications (chapter 9) barriers and success factors are discussed policy recommendations both on EU and Member State Level are being developed. The policy analysis is completed with chapters on the relation of Security of Supply and Re-search policies to DG (chapters 10 and 11). Finally, the conclusions and recommendations of the DECENT project are summarised (chapter 12).

DECENT Final Report What is Decentralised Generation?


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2 What is Decentralised Generation? A definition for the purpose of the DECENT research project.

In the scientific and energy community many views and names of decentralised generation (DG) exist: Other often used terms are “distributed generation” and “embedded generation”1. Further terms often used are “distributed energy resources” or “embedded resources”. Differ-ent aspects play roles in the perspective on the topic. The “resources” access widens the scope to energy management techniques like energy storage and demand side management, com-pared to the more restricted view on generation. Within the “generation” access some see an important distinction that the DG unit can be placed close to the actual power (or heat) de-mand, while others have rather the widespread use of (renewable) energy sources in mind, at the sites where they are usable which are not necessarily where the actual demand is. Other discussed factors are ownership, module size, interconnection to the power grid, grid inter-connection voltage, grid interconnection level (transmission, distribution, customer side of the meter). However there is no generally accepted definition of DG, since the objective of the stakeholders are very different. While some focus on an academical definition for electrical systems, others focus on economical aspects of grid structures, others focus on development perspectives for non-electrified regions and again others focus on environmental benefits. When defining decentralised Generation (DG) for DECENT we take into account the objec-tives of DECENT. The political background of DECENT is to research possibilities to sup-port the Kyoto targets of the EU. The idea is basically to study aspects of typically environ-mentally friendly generation technologies that bring along a new, decentralised structure to the generation network. This exercise is carried out in the framework of national energy mar-kets which are being transformed to competitive structures and a single European internal market. Thus the first restriction of a DECENT DG definition is that we look at generation technolo-gies which have no or a low environmental impact in terms of CO2 emissions. For renewables we study PV, hydropower, wind power and biomass (single power production and CHP ap-plications). Additionally natural-gas-fired combined heat and power (CHP) installations and fuel cells which are operated in CHP mode are covered. For CHP installations an annual en-ergy efficiency of 70 % should be a benchmark. A relatively well established academic definition2 of DG focuses only on the connected grid level and declares “all generators that are interconnected to the distribution grid, or on the customer side of the meter” to be DG. This should be accomplished for DECENT with an indicative size threshold, since for political and economical analysis of DG the size of the generating unit (as well as the size of the developing and/or operating company) are of rele-vance, especially when transaction costs and market entry procedures are discussed. Since

1 Cf. i.a. the discussion that took place in the newsgroup “Distributed-Generation” in 2000

(http://groups.yahoo.com/group/distributed-generation).

2 Thomas Ackermann: “What is distributed generation?” in: Conference Proceedings “International Symp osium on Distributed Generation: Power System and Market Aspects, June 11-13, 2001, Stockholm, Sweden”

DECENT Final Report What is Decentralised Generation?


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many of the structural conditions that DG projects face are thus linked to the installation size, and indicative upper size threshold of 10 MWe is chosen. However, as DECENT does not come forward with a legal definition of DG installation, the limit value or threshold should not be seen too strict. DECENT is thus not restricted to exam-ine generation projects that might not be part of the formal definition, if they are interesting as a comparison object (e.g. off-shore wind park connected to the transmission network). A formal lower size threshold for DG to be analysed is not necessary: The evaluation of DG projects (especially CHP) in the case studies, however, is restricted to sizes that are already commercialised or are close to commercialisation. On the other hand, one focus of the evalua-tion of future developments are the perspectives of small-scale CHP applications. Based on these considerations a short working definition : Decentralised Generation in DECENT comprises all generation installations that are connected to the distribution network or on the customer side of the meter, and that are based on the use of renewable energy sources or technologies for combined heat and power (CHP) generation not exceeding a size of approx. 10 MWe.

DECENT Final Report Outline of Research Methodology


5

3 Outline of Research Methodology

3.1 The 4-Dimensional Analytical Approach in DECENT The aim of the DECENT research project is to investigate the regulatory, economic, market, social and environmental aspects that influence the development of decentralised power gen-eration and the way they can be influenced by EU and national policies. To that end, within DECENT a four-dimensional analytical model was developed to structure the influences on the development and operation of a decentralised generation (DG) project. These four dimensions are: I. Technology dimension II. Market and Financial dimension III. Policy and Institutional dimension IV. Social and Environmental dimension The model is depicted in Figure 3-1 and further described below:

Policy DG - Project

Social and environmental framework

Market structure

Technology structure

Project evaluationin 4 dimensions

Identification ofsuccess and failure factors

Policyrecommendations

distinguishedbetween

EU and MSFilter:Policies on liberalisationPolicies on RES / CHPOther DG TREN policies

Political/Institutionalinterface

Market/technological/social interface

Analysis Model

Figure 3-1: The four analytical dimensions in DECENT

Technology Dimension

The technology dimension comprises all technological aspects related to the DG project itself and the market in which it is implemented. More specifically it concerns the technical con-figuration of the DG device, the transmission and distribution (T&D) network including gen-erators, interconnection facilities, as well as technical operation, operational standards relating to safety, reliability and stability of the network, etc. Moreover, aspects that are an immediate consequence of the above technological aspects are included in the technology dimension.



6

Particularly important in this respect is the environmental profile of DG technologies and the existing electricity infrastructure.

Market and Financial Dimension

The market and financial dimension covers all economic aspects of the DG project itself and the market structure in general. The market structure refers to the number and size distribution of the players, the pricing and trading mechanisms, the level of competition, the faculty of entry to and exit from the market and the form of economic regulation. Economic aspects related to the DG project include the cost of equipment, operating cost, financing, output con-tracting, fuel contracting, etc.

Policy and Institutional Dimension

The policy and institutional dimension relates to all the policy mechanisms that directly and indirectly impact on DG projects, as well as the institutional structure and mechanisms through which these policies are formed, implemented and administered. There is some over-lap with the market structure where it concerns economic regulation of the electricity market.

Environmental and Social Dimension

The environmental and social dimension comprises all environmental and social aspects re-lated to a DG project itself, the current electricity infrastructure, and the potential future elec-tricity infrastructure with an increased penetration of DG. The environmental profile of DG projects and conventional electricity supply are considered from a life cycle perspective. Spe-cific social aspects include the motivation of the project developers and project operators, job effects, regional development, and effects on communities.

Relationship between The Four Dimensions

The four dimensions help to put in perspective all the factors that are identified under the im-plementation characterisation. Moreover it helps to identify flaws, inconsistencies and voids in the analytical framework. Figure 3-1 explains the relationship between the three dimensions of the research project and the distributed generation project. The effects of policy on distributed generation projects can be both direct and indirect. The indirect effects occur through its effects on the market struc-ture in which DG is to develop, e.g. by tariff regulations, and through its effects on the tech-nological structure, e.g. by stimulating DG technology R&D, or through network expansion and upgrade regulations. The technological structure in the above diagram refers to all techno-logical aspects as described above under the technological dimension. Technology and Mar-ket also strongly influence each other. A market structure that provides few opportunities for DG will provide poor incentives for further DG technology development. On the other hand, targeted R&D policies can enhance the maturing of DG technologies, and facilitate an alterna-tive electricity infrastructure and market structure. The direct effects of policy on DG projects occur through policy measures such as direct subsidy schemes, environmental permitting, tax regulations, etc. By entering into the market DG projects of course also affect the technologi-cal and market structure.



7

It should be noted that most aspects in the above dimensions are dynamic rather than static. They therefore change over the course of time. Scenarios can be developed to account for this change.

Interfaces

Two interfaces are of critical importance to the potential for DG projects and the effectiveness and efficiency of policy. These interfaces are the policy/institutional interface and the mar-ket/technological/social interface. The policy/institutional interface determines the effective-ness of the implementation of various policies, while the market/technological/social interface determines the effects of these policies on DG projects.

3.2 DG Project Stages In addition to the above mentioned 4-dimensional structure, the DG implementation process was differentiated into project stages. Major project stages, which will i.a. be used in the analysis of policy implications in chapter 9, are: • Authorisation and Permitting

• Interconnection • Contracting

• Financing

• Operation However, in the following subchapter, a more detailed structure is presented which consti-tuted the starting point for the project stage-related analysis.

3.2.1 Detailed Characterisation of the Implementation of a DG project The characterisation of the DG implementation traject starts with the identification of the need or opportunity for DG, and ends with decommissioning of the DG device. For illustrative pur-poses the implementation of a DG project is divided into 16 stages (see Table 3-1). These stages are not discrete consecutive steps, but are overlapping and interrelated subprocesses. Table 3-1 lists the most important project determining policy, technology and market aspects, as well as the main actors involved with each specific aspect, in each conceptual stage of DG project implementation. The table is not an exhaustive list of aspects and actors that need to be covered in the research project. Rather it provides a starting point for finding relevant is-sues for DG development and operation that are to be analysed within DECENT. Since in many policies “the devil is in the details”, it is paramount to have a more ore less complete list of potentially important issues. Detailed case studies are consequently important to support sound policy recommendations. The issues listed in the following table should be considered under the aspects e.g. of the connected risk, its development over time, its quantifiability and its importance to each of the actors involved.



8

It would appear that DG project implementation is most sensitive to external factors over which the project developer has little or no control. In this respect the following stages are particularly important:

Identification of DG need or opportunity

A project developer must be able to identify the opportunity or need for DG of a certain kind at a specific location. This means that the project developer should receive clear economic signals to guide DG project development. These economic signals may derive from the pro-ject developer, customer demand and/or from the network configuration. In the latter case network costs and constraints would ideally be clearly reflected in the electricity and T&D tariff structure. Tariff structures in turn are subject to regulation. Other factors that play an important role are the possibility of participating in green electricity markets, resource avail-ability, opportunities/need for cogeneration and process integration.

Interconnection request and contracting

Interconnection is crucial to the proposed operation and market participation. The intercon-nection procedure, technical (safety) standards and the contents of the interconnection con-tract emanating from this procedure are typically determined by transmission system opera-tors, distribution utilities and regulators. Important aspects of the interconnection procedure are the rules, timing, possibilities for appeal against decisions and mechanisms of dispute resolution.

Regulatory approval

Within liberalising electricity markets DG project developer may have to demonstrate that the project complies with electricity sector regulations and ask for regulatory approval of the pro-posed operations and market participation.

Permitting and siting

The main potential problem with permitting and siting is the time the procedures may take to acquire all the necessary permits to site a DG device. Moreover, depending on protest and appeal procedures local resistance to DG siting may play an important role.

Financing

Financing can be a sensitive issue as DG technologies are often relatively new and unknown to the financial market. This can drive up financing cost. Furthermore, the potential financing structure is dependent on the owner/project developer of the DG project. Market regulations and utility and TSO practices may restrict a DG’s market participation. They thereby limit the potential revenues and complicate financing. Financing also depends on the contracts for both fuel and electricity and heat output.



9

Table 3-1: DG project implementation stages

DG project im-plementation

stages

project determining aspects

actors3

Iden

tific

atio

n of

DG

opp

ortu

nity

/nee

d

Technology: planned T&D upgrades/expansions congestion relief load growth voltage drops/reactive power requirements energy losses alternative options (capacitators, etc) Market & Commercial: fixed capital cost variable cost tariff structure T&D costs costs of lost load green electricity market resource availability (gas, wind, bio residues) cogeneration/process integration Policy & Institutional: tariff structure financial incentives Social & Environmental developer’s motivation local wish for environmentally friendly generation regional/agricultural development plans

Ut, PD Ut Ut Ut Ut TM TM TM, PD, FP Ut, TSO, PD Ut, TSO, Reg PD PD, ? PD, FP PD Reg, Ut, TSO Gov PD Com Com, Gov

Tech

nica

l and

eco

nom

ic

prop

ositi

on/

“sco

ping

”

Technology: Technology choice (~ operating and capacity cost, and application) generator type: synchronous/induction/inverter capacity application: base load, peak shaving, cost -optimisation, heat fuel supply to local area/grid or self-generation Market & Commercial: self-generation power market participation (spot energy, capacity, ancillary services, bilateral contracts,

green power, CO2 markets) financing Policy & Institutional: sector regulation spatial planning

PD PD, Ut PD, Ut PD, Ut PD, Ut PD, Ut, TSO PD PD, Ut, Reg, TSO PD, FI Gov, Reg Gov

Prel

imin

ary

proj

ect

feas

ibili

ty a

sses

smen

t

Technology: fuel infrastructure T&D infrastructure generator configuration and operation operation and maintenance

Market & Commercial: financial scoping: financing possibilities tariff structure expected project cost

Social & Environmental support schemes for regional/agricultural development

FS Ut, TSO, PD TM, PD TM, PD FI, TM, PD TSO, Ut, Reg, MO PD Com, Gov

3 The abbreviations are explained at the end of the last page of the table.



10

Table 3-1continued In

terc

onne

ctio

n re

ques

t and

con

tract

ing

Technology: capacity generator type: synchronous/induction/inverter location and T&D infrastructure (loop/radial) dispatch reliability system protection safety aspects: islanding/de-energised lines/isolation voltage level interconnection standards (technical and operational) interconnection facilities metering

Market & Commercial: interconnection procedure interconnection cost determination and allocation power market participation stranded assets liability insurance

Policy & Institutional: regulatory approval

PD PD, Ut, TSO PD, Ut, TSO PD, TM PD, Ut Ut, TSO Ut, TSO C, PD, TSO, Ut, MO, Reg Ut, TSO, Reg Ut, TSO, Reg, PD TSO, Reg, Ut, PD Ut, TSO, Reg Ut, TSO, PD Reg, PD

Perm

ittin

g/sit

ing

Technology: emissions profile (abatement options) noise pollution visibility issues fuel infrastructure adjustments (environmental risks?) T&D infrastructure adjustments Waste

Policy & Institutional: environmental regulation public consultation and appeal procedures

PD, TM PD, Com, Gov PD, Com, Gov Reg, FS, Gov, PD Ut, TSO, Gov PD, TM, Gov Gov Gov, Com

Fina

ncia

l fea

sibili

ty a

sses

smen

t

Technology: Reliability Detailed technical design: Technology and fuel choice capacity/efficiency emission control technology fuel delivery, storage, preparation, administration interconnection facilities heat transport

Market & Commercial: tariff structure: backup/standby charges, exit fees, sharing in network benefits market pricing mechanisms interconnection cost allocation fixed capital cost variable cost insurance

Policy & Institutional: tax and fiscal policies

TM PD PD, TM Reg, TM, PD FS, PD, TM Ut, TSO PD, TM Ut, TSO, Reg, Ut, TSO, Reg, MO Ut, TSO, Reg TM TM PD Gov

Impl

e-m

enta

tion

deci

sion

All previous and expected following PD


stages


Actors



11

Table 3-1continued Fi

nanc

ing

Technology: Novelty/experience Reliability Market & Commercial: tariff structure power purchase agreements market pricing mechanisms competition

Policy & Institutional: tax regulations

FI, TM TM, FI Ut, TSO, Reg PD, C Ut, TSO, Reg, MO Gov

Pow

er/h

eat

outp

ut

cont

ract

ing Technology:

reliability capacity dispatch

PD, TM PD, TM TSO, Ut, PD

Proc

urem

ent

of e

quip

men

t

Technology: manufacturing, economies of scale shipping

TM TM

Fuel

pro

cure

men

t and

co

ntra

ctin

g

Technology: fuel infrastructure fuel capacity fuel supply reliability dual fuelling capability gas pressure fuel quality (heating value, chemical composition) safety aspects

Market & Commercial: fuel prices

Policy & Institutional: tax regulations

FS FS FS PD, TM FS FS PD, TM FS Gov

Con

-str

uctio

n

Technology: construction lead time

CC

Impl

emen

tatio

n of

m

eter

ing,

acc

oun-

ting

and

data

man

-ag

emen

t sys

tem

s

Technology: metering equipment

accounting software

Ut, TSO, Reg, PD, TM, C SE, PD

Phys

ical

in

terc

on-

nect

ion

Technology: interconnection facilities Market: market participation (interface)

Ut, TSO, Reg Ut, TSO, Reg, PD, MO


stages


actors



12

Table 3-1continued C

omm

erci

al o

pera

tion

Technology: reliability capacity maintenance

Market: market participation contracting accounting

settling

Environmental: operational environmental performance

TM, PD PD PD PD PD, C PD, MO, TSO, Ut PD, MO, TSO, Ut PD

Dec

om-

miss

ion-

ing

Technology: safety Market: salvage value decommissioning reserve

DC C PD

List of abbreviations of actors: C customer CC construction contractor Com local community DC decommissioning contractor FI financial institutions

FS fuel supplier Gov government MO market operator PD project developer4 Reg regulator

SE Software Engineers TM technology manufacturer TSO transmission system

operator Ut utility

4 The PD does not have to be a small independent power producer. It can for example also be an industrial con-

sumer, a municipality, an office bloc, a shopping mall, a utility, or even a system operator.


stages


actors



13

3.3 Conceptual Framework

Literature Review & Expert Interviews

Overview

Policy & Institutional

EU liberalisation policyOther EU policiesMember States:- Progress of liberalisation- Relevant policies- Institutional setting

Market & Financial

Member States:- Progress of liberalisation- Market structure- Economic valuation- Market interfaces

Technology

- Externalities- T&D infrastructure aspects- technology options- technological interfaces

Social & Environmental

- Motivation of DG developer- Regional econonmic structure- Ecological impacts

Further identification, specification, actualisation and prioritisation of policy, market andtechnological aspects that need to be considered, plus working definition of DG

Overview on relevant issues for the development and operation of DG installations

Identification and categorisation of case studiesIdentification of uncovered aspects - focusing of case studies

Future Analyses

Future study survey - working withresults to explore future scenarios forthe role of DG

Case Studies

Empirical complementation,illustration and validation of theoutcome of literature review andexpert interviews.Analysis of specific priority issues.

Discounted Cash Flow Analysis

Identification of main policy andeconomic sensitivities of DG

Policy Implications

Analysis of possible impacts of EU /national policy fields on identifiedissues

Results:key barriers and success factors (sensitivities, technical factors and policy levers)

Policy Recommendations

Peer Review

Figure 3-2: Conceptual framework of DECENT analytical methods.



14

The conceptual framework is illustrated in Figure 3-2 on the previous page: The project started with an extensive literature review and expert interviews to get an over-view of technology, policy, market and social/environmental aspects that affects DG project implementation. As a starting point for this inventarisation a matrix featuring DG project im-plementation stages, determining aspects, and relevant actors was developed. An overview on the relevant issues then gives a clear picture of the entire subject field. This overview guided the process of identifying and selecting case studies, and helped to ensure that all priority as-pects are covered by one or more case studies. The result of all previous steps was a descrip-tion of barriers and potentials for the implementation of DG projects. Within the case studies different analysis steps are carried out: Where the economical data was available in sufficient detail, an economical evaluation of the DG development was performed with the help of a discounted cash flow (DCF) model, which also allowed to vary relevant input parameters in order to model the influence of different policies/ framework conditions. In addition social and environmental effects, as well as the influence of energy, tax, environ-mental, permitting/siting and spatial planning policies and frameworks are analysed. This was used to further clarify the critical issues for DG developments within the given na-tional settings. As the direct result of the case study analysis (in combination with the previous working steps) a number of barriers and success factors for DG project were identified which were used to focus the analysis of policy implications.



15

The link between the case studies, the futures study, and policy recommendations are further explained in Figure 3-3:

literature review /

interviews

case studies

Issues barriers and

success factors

Policy packages

Future study -

visions

Policy recommendations

Policy instruments / best practices

Current policy

evaluation

Peer review

Policy analysis

literature review / interviews

case studies

Issues barriers and

success factors

Policy packages

Future study -

visions

Policy recommendations

Policy instruments / best practices

Current policy

evaluation

Peer review

Policy analysis

Figure 3-3: Links between working steps in DECENT The outcome of the literature review and the expert interviews were condensed to a number of approximately 20 relevant issues/hypotheses. These issues were especially checked in the case studies. The issues thus finally identified as barriers and success factors, were input to both futures studies and policy implications analysis:

• In the futures study these issues are integrated in a Delphi-style survey (featuring addi-tional technological items, e.g. development of PV, fuel cells, micro-CHP) in order to submit them to the evaluation of experts, identify key drivers, and elaborate visions of DG development. These visions were then used in the policy analysis for validation purposes in a robustness check.

• In the policy implications analysis these issues serve as a basis for the identification of best practices and barriers (“worst practices”) and, based on that, for the elaboration of policy options. For all issues it is checked, whether they can be approached within the framework of current EU level policies (DG TREN), or whether they could be ap-proached through future commission’s initiatives or through policies on Member State level.



16

Policy recommendations are thus based on evaluation of policy instruments, best practices, current policies, and future visions. The recommendations were finally subject to a peer re-view before final results are were presented in a workshop5.

5 “The European Energy Market – Liberalisation, Decentralisation, Cogeneration”

Joint workshop with the CHP STAGAS project (funded by the EU under the SAVE programme). Brussels, European Commission, DG TREN, 9th July 2002

DECENT Final Report Status Quo and Developments of DG Technology


17

4 Status Quo and Developments of DG Technology In this chapter, first an overview on present DG technologies and their cost structures is given. Here, technologies based on renewable energy sources (PV, wind power, hydropower, bio-mass) are covered as well CHP technologies based on natural gas (both combustion machines and fuel cells). Second, the results of a survey on future developments of DG technologies in Europe are pre-sented. This survey and the building of scenarios (cf. chapter 6) were part of the futures study that was performed in the framework of DECENT.

4.1 Renewable Energy Sources

4.1.1 Photovoltaics Photovoltaic (PV) solar cells consist of semiconductor materials that produce electric current when exposed to sunlight (photo effect). PV-systems exist in a broad range of sizes, from mi-cro applications in the milliwatt range up to large power generation plants of several mega-watt capacity. Regarding decentralised generation, the commonly used PV-systems combine standard modules of 50 or 100 watt each.

4.1.1.1 Types of photovoltaic cells Today there are basically three types of industrial manufactured photovoltaic cells in use: mono-crystalline silicon cells, which hold a share of app. 50% of the world market, multi-crystalline silicon cells with a market share of app. 30%, and amorphous silicon cells, which hold a market share of app. 20%. Crystalline cells are made out of wafers cut from a large silicon block. Mono-crystalline cells reach with 13-15% the highest conversion efficiency, followed by multi-crystalline cells with 12-14%. Significantly higher efficiencies of up to 24% can be reached with high efficiency silicon cells, but they are still in the stage of pilot production6. Amorphous cells consist of a very thin and flexible layer of uncrystallised silicon that is de-posited on a carrier material (mostly glass). Their conversion efficiency only reaches about 6-8%, but since they are better suited to cost-effective mass production processes, they are in-creasingly regarded as the preferred option for PV-modules in the long term. Several other thin-film technologies - notably Cadmium Telluride and Copper Indium Diselenide - are now approaching the commercialisation stage.

4.1.1.2 Photovoltaic modules A PV-module is composed of interconnected cells that are encapsulated between a glass cover and weatherproof backing. The modules are typically framed in aluminium frames suitable for mounting. Typical sizes of modules are 0.5 x 1 m2 and 0.33 x 1.33 m2, and they contain about 40 cells. However, modules of any desired size can be produced, although in practice, modules larger

6 Fuhs, p.14, Umweltbundesamt, p.36f.



18

than 1m2 are not often used. Typical modules reach a performance of 50 or 100, sometimes 150 watt. In Northern Europe, the average energy harvest of a module is 750-850 kWh/kWp, in Southern Europe, significantly higher figures are reached. A sub-optimal placement of a module, e.g. a false angle or orientation, leads to significant performance losses. If part of the module is shaded, the performance will break in drastically, since the current produced by the other cells is consumed by the shaded cells. To limit these losses, bypass diodes are sometimes built in parallel to a string of cells, so the current can bypass the shaded cells.

4.1.1.3 Photovoltaic systems A photovoltaic system consists of one or more photovoltaic modules. The PV-modules are connected in series and parallel to form an array of modules, thus increasing total available power output to the needed voltage and current for a particular application. Because PV-generators are built with PV-modules of 50 or 100 watts each, photovoltaic systems are ex-ceptionally modular, which provides for easy transportation and rapid installation, and enables easy expansion if power requirements increase. To be able to use the generated electricity, more components need to be added to the system. PV-systems for stand-alone applications may comprise also a control, storage (e.g. battery), cables and a load (e.g. lights, radio, television). PV-systems for grid-connected applications need an inverter to convert the Direct Current (DC), generated by the PV-modules, into Alter-nating Current (AC). Stand-alone systems are rarely installed in industrialised countries. However, even in these countries some off-grid applications exist for which PV-systems prove to be a suitable and economical attractive option, e.g. lighting and other low-voltage applications in isolated areas. In the third world, the potential for stand-alone PV-systems is extremely high, since few countries have an extended power grid. In a grid-connected system the grid acts like a battery with an unlimited storage capacity. Therefore its total efficiency will be better than the efficiency of a stand-alone system, even though the inverter causes energy losses. As long as only the power generation costs are com-pared, nowadays grid-connected PV-systems cannot financially compete with other power generation technologies, neither conventional nor renewable. If the avoided pollution of the environment and the positive image are taken into account, the PV-technology becomes much more attractive.

4.1.1.4 Costs The investment costs of a photovoltaic system based on mono-crystalline cells are estimated to 7 €/Wp for small plants (~2 kWp) and 5 €/Wp for large plants (~100 kWp)7

. More than half of the costs are caused by the modules. The power generation costs are derived to approximately 0.75 €/Wp for small plants and 0.50 €/Wp for large plants (>100 kWp)8. Another source mentions 0.35 – 0.70 €/Wp for multi-crystalline cells9. 7 Staiss, p.I-60



19

In the last ten years, the overall costs decreased by almost 50%10. A further decrease of 50% is expected until 2010 if the production volume will continue to increase by 20% every year11. A typical distribution of investment cost for PV installations in Germany is given in the fol-lowing table: Table 4-1: Average PV costs in Germany

Component Cost (€/Wpeak)

Frame / rack 0.75 Module 3.75 inverters 1.25 Wiring 0.5 Erection 0.75 Total 7.0 Source: Prochaska 2001

4.1.1.5 Environmental considerations PV-systems pose few environmental problems. The generating component produces electric-ity silently and does not emit any harmful gases during operation. The basic photovoltaic ma-terial for most common modules (silicon) is entirely benign, and is available in abundance. There are, nevertheless, some potential hazards allied to the production of some of the more exotic thin film technologies. The two most promising options, cadmium telluride and copper indium diselenide, both incorporate small quantities of cadmium sulphide, which poses poten-tial cadmium risks during module manufacture and the later disposal. One criticism of early PV-modules was that they consumed more energy during their produc-tion than they generated during their lifetime. With modern production methods and improved operational efficiencies this allegation is no longer true. The exact energy payback is obvi-ously dependent on the availability of solar resource and on the degree to which the system is operational. Typically energy payback will be realized within two years for thin-film and app. seven years for mono-crystalline cells12. Other sources estimate payback-times of 2-5 years for poly- and multi-crystalline cells13.

8 Staiss, p.I-60

9 Kaltschmitt/Wiese, p. 233

10 Staiss, p. I-59

11 Fuhs, S.17

12 Fuhs, p. 16

13 IEA, Knapp/Jester



20

4.1.2 Wind Turbines

4.1.2.1 Introduction Within the last 10 years wind power has on a global scale developed incredible fast. In 1990 total installed capacity of wind power in the World amounted to approx. 2.0 MW – by the end of 2000 this capacity has increased to 18.5 GW. This more than nine fold increase equals an annual growth rate of almost 25%. And the rate of growth is still high - in 1999 global in-stalled capacity increased by 37 % and by 32% in 2000. But European countries dominate the wind power scene. In 2000 more than 85% of total installed wind turbine capacity was estab-lished in Europe, and the only major contributors outside Europe were the US with a total installed capacity of approx. 2.6 GW and India with 1.2 GW [BTM Consult 2001]. But even within Europe a few countries are the dominant ones: Germany, Spain and Denmark accounts for approx. 85% of the growth in European installed wind turbine capacity in 2000, and correspondingly these three countries together has installed more than 80% of the total accumulated capacity in Europe. Especially Germany has had a rapid development. In 1991 total accumulated capacity in Germany was approx. 100 MW; by now the annual capacity increase is approx. 1600 MW and total installed wind power capacity is above 6.1 GW. Simi-lar developments are found in Denmark and Spain, although not to the same extent. Denmark by now has a total installed capacity of almost 2.4 GW and a growth rate of almost 35% in 2000, while Spain in total has installed 2.8 GW with a tremendous growth rate of more than 50% in 2000. Other contributors in Europe to be mentioned are the Netherlands (0.5 GW), UK (0.4 GW), Italy (0.4 GW), Greece (0.3 GW) and Sweden (0.3 GW) [BTM Consult 2001]. The main reasons behind the development in these three above-mentioned dominant countries in Europe (i.e. Germany, Spain and Denmark) is a fast improvement of the cost-effectiveness of wind power during the past ten years [Redlinger et al. 1998], combined with long-term agreements on fixed feed-in tariffs (at fairly high levels), altogether making wind turbines some of the most economically viable renewable energy technologies today [European Com-mission 2000]. And the national policies of fairly high buy-back rates and substantial subsi-dies from governments to a certain extent reflect the need for a development of renewable energy technologies to cope with the greenhouse gas effect. According to the Kyoto protocol the European Union has agreed on a common greenhouse gas (GHG) reduction of 8% by the years 2008-12 compared with 1990. And all the three above-mentioned countries have adopted a policy of GHG-limitations in accordance with the agreed burden sharing in EU.

4.1.2.2 Economics of Wind Energy Wind power is used in a number of different applications, including both grid-connected and stand-alone electricity production, as well as water pumping. This section analyses the eco-nomics of wind energy primarily in relation to grid-connected turbines, which account for the vast bulk of the market value of installed turbines. The main parameters governing wind power economics include the following: • Investment costs, including auxiliary costs for foundation, grid-connection, and so on.



21

• Operation and maintenance costs • Electricity production / average wind speed • Turbine lifetime • Discount rate Of these, the most important parameters are the turbines’ electricity production and their in-vestment costs. As electricity production is highly dependent on wind conditions, choosing the right turbine site is critical to achieving economic viability. The following sections outline the structure and development of land-based wind turbines’ capital costs and efficiency trends. Offshore turbines are gaining an increasingly important role in the overall development of wind power, and they are thus treated in detail in a separate section. In general, two trends have dominated grid-connected wind turbine development: 1) The average size of turbines sold on the market has increased substantially 2) The efficiency of production has increased steadily. Figure 4-1 shows the average size of wind turbines sold each year using the Danish market as a proxy. As illustrated in Figure 4-1 (left axis), the average size has increased significantly, from less than 50 kW in 1985 to almost 1 GW in 2000. In late 2000 the best-selling turbine had a rated capacity of 750-1000 kW, but turbines with capacities of the MW-size are increas-ing their market shares.

0

100

200

300

400

500

600

700

800

900

1000

1980

1983

1986

1989

1992

1995

1998

kW

0

100

200

300

400

500

600

700

800

900

1000

kW

h/m

2/y

ea

r

Average size (leftax is)

Yearly production(right axis)

Development of average wind turbine size sold in the market (left axis) and efficiency, measured as kWh produced per m2 of swept ro-tor area (right axis).

Figure 4-1: Wind turbine sizes and productivities.

Comparing to other countries the Danish market is fairly representative for the development of the average size of turbines sold. The average size sold in Denmark in 2000 was 930 kW – only Germany was above with an average size of 1100 kW, while the average in UK and Sweden was approximately 800 kW and approximately 650-700 kW in Spain and US.



22

The development of electricity production efficiency is also shown in Figure 4-1, measured as annual energy production per swept rotor area (kWh/m2 on the right axis). Measured in this way, efficiency has increased by almost 3 percent annually over the last 15 years. This im-provement in efficiency is due to a combination of improved equipment efficiency, improved turbine siting, and higher hub height. The decrease in efficiency shown in Figure 4-1 are due to a lower average wind speed at those sites available for the latest established turbines14. Capital costs of wind energy projects are dominated by the cost of the wind turbine itself (ex works)15. Table 4-2 shows a typical cost structure for a 1 MW turbine in Denmark. The tur-bine’s share of total cost is approximately 83 percent, while grid-connection accounts for ap-proximately 8 percent and foundation for approximately 4 percent. Other cost components, such as control systems and land, account for only minor shares of total costs. Table 4-2: Cost structure for a 1MW wind turbine

Investment (1000 €)

Share (%)

Turbine (ex works) 870 82.7 Foundation 40 3.8 Electric installation 20 1.9 Grid-connection 80 7.6 Control systems 2 0.2 Consultancy 8 0.8 Land 15 1.4 Financial costs 10 0.9 Road 7 0.7 Total 1052 100

Note: Based on Danish figures for a 1 MW turbine, using average 2000 ex-change rate 1€ = 7.45 DKK.

Figure 4-2 shows changes in capital costs over the years. The data reflects turbines installed in the particular year shown. All costs at the left axis are calculated per kW of rated capacity, while those at the right axis are calculated per swept rotor area. All costs are converted to 1999 prices. As shown in the figure, there has been a substantial decline in per-kW costs from 1989 to 1996. In this period turbine costs per kW decreased in real terms by approximately 4 percent per annum. At the same time, the share of auxiliary costs as a percentage of total costs has also decreased. In 1989 almost 29 percent of total investment costs were related to costs other than the turbine itself. By 1996 this share had declined to approximately 20 percent. The trend towards lower auxiliary costs is continuing for the last vintage of turbines shown

14 The efficiency measure is based upon Danish turbine statistics and sites available for new turbines are increas-

ingly getting more limited in number.

15 ‘Ex works’ means that no site work, foundation, or grid connection costs are included. Ex works costs include the turbine as provided by the manufacturer, including the turbine itself, blades, tower, and transport to the site.



23

(1000 kW), where other costs amounts to approximately 17 percent of total costs. But a little surprisingly investment costs per kW have increased for this last-mentioned machine com-pared to a 600 kW turbine. The reason has to be found in the dimensioning of the turbine. With higher hub heights and larger rotor diameters the turbine is equipped with a relative smaller generator although it produces more electricity. This is illustrated in Figure 4-2 at the right axis, where total investment costs are divided by the swept rotor area. As shown in this figure the cost per swept rotor area has decreased continuously for all turbines considered. Thus, overall investment costs per swept rotor area have declined by approximately 3 percent per year during the period analysed.

0

200

400

600

800

1000

1200

1989 1991 1993 1995 1996 2000

Year of installation

€/k

W

0

100

200

300

400

500

600

€ p

er

sw

ep

t ro

tor

are

aPrice of turbine per kW

Other costs per kW

Total cost per swept m2

150 kW225 kW

300 kW

500 kW1000 kW

600 kW

Left axis: Wind turbine capital costs (ex works) and other costs per kW rated power (€/kW in constant 1999 €). Right axis: Investment costs divided by swept rotor area (€/m2 in constant 1999 €).

Figure 4-2: Wind turbine costs

Reductions in capital costs are expected to continue for the foreseeable future. EPRI [EPRI 1997], for instance, predicts that capital costs per swept area ($/m2) should decline by 23 per-cent between 1997 and 2000, and by a further 10 percent between 2000 and 2005. The total cost per produced kWh (unit cost) is calculated by discounting and levelling invest-ment and O&M costs over the lifetime of the turbine, divided by the annual electricity production. The unit cost of generation is thus calculated as an average cost over the turbine’s lifetime. In reality, actual costs will be lower than the calculated average at the beginning of the turbine’s life, due to low O&M costs, and will increase over the period of turbine use. Figure 4-3 shows the calculated unit cost for different sizes of turbines based on the above-mentioned investment and O&M costs, a 20 year lifetime, and a real discount rate of 5 percent per annum. The turbines’ electricity production is estimated for roughness classes one and



24

two, corresponding to an average wind speed of approximately 6.9 m/s and 6.3 m/s, respec-tively, at a height of 50 meters above ground level.

0

2

4

6

8

10

12

95 150 225 300 500 600 1000

k W

€c

en

t/k

Wh

Average wind speed 6.9 m/s

Average wind speed 6.3 m/s

Total wind energy costs per unit of electricity produced, by turbine size, based on hub height of 50 meters. (€ cents/kWh, constant 1999 prices).

Figure 4-3: Wind Energy Unit Costs

Figure 4-3 illustrates the trend towards larger turbines and greater cost-effectiveness. For a roughness class one site (6.9 m/s), for example, the average cost in 1999 € has decreased from over 7.4 €cents/kWh for the 95 kW turbine to under 4 €cents/kWh for a new 1000 kW ma-chine, an improvement of more than 45 percent over a time span of 10-11 years. The discount rate has a significant influence on electricity production costs and hence on wind projects’ financial viability. For a 1000 kW turbine, changing the discount rate from 5 to 10 percent per year (in real terms) increases the production cost by a little more than 30 percent.

Observe that wind energy project capital costs as reported by the International Energy Agency [IEA 1997] show substantial variation between countries, due to factors such as market struc-tures, site characteristics, and planning regulations. According to the IEA, total wind project capital costs vary between approximately US$ 900/kW and US$ 500/kW in different coun-tries. Caution should therefore be exercised in making cross-country cost comparisons, par-ticularly as currency exchange rates also significantly impact apparent costs in any given country.



25

4.1.2.3 The development of offshore turbines in Denmark In a number of countries offshore turbines are getting an increasingly important role in the development of wind power, particularly in the north-western part of Europe. Without doubt the main reasons are that on-land sitings are limited in number and that the utilization of these sites to a certain extent is exposed to opposition from the local population. More over, there seems to be fewer restrictions on the utilization of offshore sitings. This seen in relation to an unexpected high level of energy production from offshore turbines compared to on-land sit-ings (based on the experiences gained until now), has paved the way for a huge interest in offshore development. What follows are mostly based on Danish experiences. A number of different interest groups are struggling for rights to the sea. Among these can be mentioned: the fishing industry, the navy, nature conservancy associations and marine ar-chaeologists. To select an area for wind turbine sitings and at the same time meet the most important claims of the other parties, the Danish Government set up a committee to define the main areas in Danish waters suitable for establishing offshore wind farms. In total an area of approx. 1000 square kilometres has been pointed out, corresponding to the siting of 7000-8000 MW wind turbines. Most of the areas are located at a distance from the coast of 15-30 kilometres, and at a water depth of 4-10 meters [Fenhann et al. 1997]. In total four areas were identified. In collaboration between the Danish Utilities and the Danish Energy Agency the possibilities for utilizing these areas for offshore turbines were evaluated and an action plan put forward. The plan states that 750 MW of wind power has to be established before 2008 with the Dan-ish utilities as the main entrepreneur. If the wind farms are equipped with 1.5 - 2 MW tur-bines, it will be possible to achieve a production cost for electricity of approx. 4.7 to 5.1 cEUR per kWh, thus ranging at the same level of production costs as an on-land siting with average wind conditions16. In Germany a strong development of offshore turbines is foreseen. In a first phase up to 500 MW will be established (until 2007), followed by 2000-3000 MW until 2010. In the sec-ond development phase until 2030 a total installed capacity of 20000-25000 MW is planned, delivering 70-85 TWh per year. Looking at the total North Sea area (the seabed of UK, Belgium, The Netherlands, Germany and Denmark) a total potential of more than 1900 TWh/year is estimated, more than three times as much as the total annual electricity consumption in these countries [Greenpeace 2000]. At present a number of offshore wind farms are in operation in the northern part of Europe. To mention some of the larger farms these are [BTM Consult 2001]:

16 Cf. [Action plan for offshore turbines 1997]



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• Middelgrunden (Denmark) east of Copenhagen was put in operation in 2001. At present Middelgrunden is the largest offshore farm in the World, consisting of 20 2 MW turbines

• Ijsselmeer (Netherlands) is the World’s second largest offshore farm equipped with 28 600 kW, a total capacity of 16.8 MW.

• Utgrunden (Sweden) established in 2000 has a total capacity of 10.5 MW and consists of 7 1.5 MW turbines.

• Tunø Knob (Denmark) is located east of Jutland with a total capacity of 5 MW (10 tur-bines of 500 kW each). Tunø Knop was installed in 1995.

• Vindeby (Denmark) is located northwest of the isle of Lolland with a total capacity of 4.95 MW. The wind farm was established in 1991 and consists of 11 450 kW turbines.

Quite a number of offshore wind power projects are in the planning and implementation phase. In Denmark four large offshore farms with a total capacity of more than 600 MW are on the way, as part of the overall Parliament agreement of establishing 750 MW offshore farms before 2008. The Horns Rev project (west of Esbjerg) with a total capacity of 160 MW (2 80 MW machines) is commissioned by now and expected to be finished in 2002. Rødsand (approximately 150 MW) close to Lolland had called for tenders in the summer 2001 and a decision is expected the autumn. Rødsand is expected to be finalized in 2003-2004. In Germany approximately 800 MW is expected to be installed within the next 5 years, in-cluding a large offshore farm with Helgoland with a total capacity of 500 MW to be installed by 2005. Ireland are planning to develop approximately 750 MW before 2005, the Nether-lands 340 MW before 2003 and UK almost 340 MW before 2005 [BTM Consult 2001]. Fundamentally, wind power is a decentralised technology. To a certain extent this is the case for offshore turbines as well. Small-scale offshore wind farms (5 – 50 MW) still maintain some of the same characteristics as on-land turbines. Thus, they will mainly produce to fulfil the power needs of electricity customers living fairly nearby. But the larger the offshore wind farms get the more they come to look like actual electricity producing plants. The large off-shore farms of 150 to 200 MW will deliver directly to the high-voltage grid and cannot in their character be considered decentralised. At the same time these large offshore farms are to have a number of regulatory capabilities, required by the authorities. To illustrate the economics of offshore wind turbines, the Tunø Knob wind farm (located in Denmark) is chosen as an example17. The farm consists of 10 turbines each with a rated ca-pacity of 500 kW (total capacity 5 MW) and it is located 6 kilometres from the coast, at a depth of sea of approx. 3.1-4.7 meters. Each turbine has its own foundation (concrete), which is placed at the sea bottom. Through a transmission cable the turbines are connected to the high voltage grid at the coast. The farm is operated from a power plant nearby, and no staff is

17 Tunø Knop is the most recent Danish offshore wind farm, where it is possible to get actual, reliable data.



27

required at the site. The investment costs related to this farm are shown in Table 4-3 [Fenhann et al. 1997]. Table 4-3: Investment costs related to the Tunø Knob wind farm

Investments Mill. €

Share %

Turbine ex work 4.6 40 Transmission cable (sea) - to the coast - between the turbines

1.4 0.6

12 5

Transmission cable (land) 0.5 4 Electricity systems 0.4 4 Foundations 2.6 22 Operating and control systems 0.2 2 Environmental analysis 1.2 11 Total 11.5 100 Note: 2000 prices, Exchange rate 1 € = 7.45 DKK.

Compared to land-based turbines the main differences in the cost structure are related to 2 issues:

• Foundations are considerably more costly for offshore turbines. The costs depend on both the sea depth, and the chosen principle of construction. For a conventional turbine sited on land, the share of the total cost for the foundation normally is approx. 4-6%. In the Tunø Knob project this percentage is 22% (cf. Table 4-3), and thus considerably more expen-sive than for on-land sitings. It must be mentioned, however, that developing foundations for Tunø Knob was a pilot project, and therefore not optimised.

• Sea transmission cables. Connections between the turbines and from the turbines to the coast generate additional costs compared with on-land sitings. For Tunø Knob wind farm the cost share for sea transmission cables is 17%, (cf. Table 4-3).

Finally, a number of environmental analyses were carried out in relation to the Tunø project. These include investigation of the sea bottom especially concerning materiel left behind from military activities, a project for clarifying the impact of the wind farm on bird life and, finally, one visualizing the wind farm itself. The cost share for environmental analysis at the Tunø Knob farm is 11%, but part of these costs are related to the pilot character of this project and is not expected to be repeated next time an offshore wind farm will be established. The total electricity production from the Tunø Knob wind farm has turned out to be higher than expected, showing a utilisation time of almost 3100 hours. Using this production, the above-mentioned investment costs, a real interest rate of 5% and a lifetime of 20 years, the production costs per kWh amounts to approx. 6.8 €cent (2000 prices) [Fenhann et al. 1997]. Recently, a number of projects have been carried out in Denmark, especially in relation to minimising the cost of foundations for offshore turbines. Based on [Elsamprojekt 1997], the most important findings will be stated briefly in the following:



28

• Using a 1500-kW wind turbine as reference, foundation costs are in general esti-mated to be only slightly higher (approx. 30%) than experienced for the 500 kW turbines at Tunø Knob wind farm. The main reason for this is that the newly de-veloped foundations are made of steel rather than concrete, as used in the Tunø Knob project.

• Although, of course, the foundation cost increases with sea depth, this increase is less than linear. Depending on type of construction and the analysed locality, when the sea depth is increased from 5 to 11 meters the foundation cost goes up only 12 to 34%.

• Three types of foundations are analysed in [Elsamprojekt 1997]: Mono-pile, Grav-ity and Tripod. The cost estimates are found to be remarkably close for all three types, with a maximum variation of approx. 12% at the same location.

0.001.00

2.003.004.00

5.006.007.00

8.009.00

500 kWexisting

600 kW 750 kW 1000kW

1500kW

Rated power of turbine

€cen

t/K

Wh

The cost of electricity produced as a function of the rated power of an offshore wind turbine. (2000- prices, exchange rate 1 € = 7.45 DKK)

Figure 4-4: Off-shore wind energy unit costs I

The consequences for the electricity production costs of moving towards larger turbines in the sea are illustrated in Figure 4-4. As reference is shown the electricity production cost at the Tunø Knob wind farm, which is compared with the production cost for turbines with a higher rated capacity. The turbines are assumed to be located at the same distance from the coast and at a sea depth of approx. 5-6 meters. As shown in Figure 4-4 the cost per kWh produced is expected to decrease from approx. 6.8 €cent (Tunø Knob 500-kW turbine) to approx. 4.6 €cent for a 1500-kW turbine. The closer the wind farm is located to the coast and the higher the energy production from the farm, the lower will be the cost to the sea transmission cable per unit of electricity produced. How these two parameters affect electricity production is illustrated in Figure 4-5. To estab-lish Figure 4-5, data is collected for three sizes of wind farms: a small one of 7.5 MW (com-parable to Tunø Knob), a medium-size farm of approx. 30 MW (comparable to Middelgrun-den offshore wind farm) and a large wind farm of 100-200 MW (comparable to Horns Rev



29

and Rødsand offshore wind farms to be implemented in Denmark). All are equipped with 1.5 MW turbines.

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

10.00

7.5 30 100 200

MW

€cen

t/K

Wh

30 km

15 km

5 km

The cost of electricity production as a function of distance to the coast and the capacity of the wind farm. (2000- prices, exchange rate 1 € = 7.45 DKK)

Figure 4-5: Off-shore wind energy unit costs II

The distance to the coast has a substantial impact for small farms especially on coast. As shown in Figure 4-5 the production cost rises from 4.6 to 6.5 €cent for a 7.5 MW farm, when the distance to the coast goes out from 5 to 30 kilometres. Increasing the capacity of the wind farm lowers the cost per unit of electricity produced significantly. When the distance to the coast increases from 5 to 30 kilometres the electricity production cost for a 200 MW wind farm increases from only 3.9 to 4.2 €cent.



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4.1.3 Hydro power

4.1.3.1 Capacity and potential Hydropower holds presently the largest share of power production from renewable energy, both world-wide an in the EU. Hydropower accounts for about 17 % of global generating ca-pacity, and about 20 % of the electricity produced each year18: With a total global power pro-duction in 1997 of 13,300 TWh the share of hydropower was 2,600 TWh19. However, the share of Hydropower in 1997 EU gross inland electricity consumption was only 1,8%20, only 3% of which was generated in small hydropower plants < 10 MW21:. The amount of electricity produced by hydropower plants is varying significantly throughout weeks, months and years due to varying hydrological conditions. Thanks to the good actual forecasting tools for hydrology resources, long-term planning for hydro energy is possible.

4.1.3.2 Principle The general principle of a hydro power plant is depicted in the following graph:

source: Power Resources Office

Figure 4-6: Hydropower Principle

18 IEA implementing agreement

19 Survey of Energy Resources, World Energy Council Report 1998

20 source: Eurostat

21 TERES II



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The dam creates a head or height from which water flows. A pipe (penstock) carries the water from the reservoir to the turbine. The fast-moving water pushes the turbine blades, thus turn-ing the rotor and generating electricity. Today’s hydropower turbines are capable of convert-ing 90 percent of available energy into electricity—that is more efficient than any other form of generation. Due to the fast start or stop of hydraulic turbines and their large operating range, hydro energy is suitable for load control.

4.1.3.3 Plant classification Hydropower plants are classified by size22: Micro and mini hydropower plants: up to 100 kW Small hydropower plants 100 kW to 10 MW Large hydropower plants > 10MW However, there is no consensus in EU member states on the definition of small hydropower: Some countries like Portugal, Spain, Ireland, and now, Greece and Belgium, accept 10 MW as the upper limit for installed capacity. In Italy the limit is fixed at 3 MW (plants with larger installed power should sell their electricity at lower prices); in France the limit was estab-lished at 8 MW and UK favour 5 MW. On EU level a threshold of 10 MW is widely dis-cussed.

Plant schemes

The large majority of small hydro plants are «run-of-river» schemes, meaning simply that the turbine generates when the water is available and provided by the river. When the river dries up and the flow falls below some predetermined amount, the generation ceases. This means, of course, that small independent schemes may not always be able to supply energy, unless they are sized in a way that there is always enough water. On the contrary, an energy storage in a reservoir can guarantee the energy supply. It permits to store energy during off-peak hours and to release it during peak hours.

4.1.3.4 Costs The costs for hydropower plants are highly site-specific. A typical structure of costs for a new hydro plant is given in the following figure:

22 Kueny



32

Cost structure for a new hydropower plant

electrical engineering

5%

interest10%

indirect costs15%

hydro-steel works

5%mechanical engineering

20%

general construction

45%

source: Giesecke et al., 1998; own presentation Figure 4-7: Cost structure for a new hydropower plant

The available figures on Unit energy costs vary widely: The TERES II study found for the EU the following figures: Table 4-4: Unit costs for hydropower in the EU

Unit costs 1995 Expected unit costs 2020 Large hydro 3-13 € cents/kWh 2.6-11.2 € cents/kWh

Small hydro 4-14 € cents/kWh 3,6-10.1 € cents/kWh Orienting figures from Germany give higher costs especially for micro plants:



33

Table 4-5: Investment and Unit Costs for Small Hydro Plants

New construction Plant re-activation

micro plants small plants micro plants small plants

installed capacity kW 70 1000 70 1000

full load operating hours h/a 4500 5500 4500 5500

electricity production Mio kWh/a 0,32 5,5 0,32 5,5

Investment Mio € 0,6 5,4 0,3 2,6

specific Investment €/kW 8900 5400 4100 2600

Life-time a 30 30 30 30

interest p.a. % 6 6 6 6

capital costs €/(kW/a) 650 390 297 186

operating costs €/(kW/a) 219 134 205 128

electricity unit costs €cents/kWh 19 10 11 6

Source: Staiß: Jahrbuch Erneuerbare Energien 2000

Advances in fully automated hydropower installations and reductions in manufacturing costs have made small scale hydropower increasingly attractive. The upgrading of existing hydro-power installations is by far the lowest cost renewable energy available today. It can some-times provide additional energy at less than one tenth the cost of a new project.

4.1.3.5 Environmental impact and its mitigation Renewable energy can make a significant contribution to CO2 emissions reduction. The Euro-pean Commission, through the ALTENER programme, proposed as indicative objectives by 2005 to increase the contribution of renewable energy sources from its current level of 4% in 1991 to 8% of primary energy consumption and to duplicate the electricity produced by re-newable sources. For small hydropower this objective will require the European Union to increase the average annual renewable electricity production from 30 TWh to 60 TWh., and the development of 9 000 MW in new schemes. The achievement of this objective will imply an annual reduction of 180 million tonnes of CO2 emissions. However presently many authorisation requests are pending approval, the delay being caused mainly by supposed conflict with the environment. Some environmental agencies seem to justify -or at least excuse- this blockade on the grounds of the low capacity of the small plants.23 At the same time it should be accepted that, although through having no emissions of carbon dioxide and other pollutants, electricity production in small hydro plants is environmentally rewarding, the fact is that due to their location in sensitive areas, local impacts are not always negligible. The significant global advantages of small hydropower must not prevent the iden- 23 source: European Commission: Layman’s Guidebook on how to develop a small hydro site



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tification of burdens and impacts at local level nor the taking of necessary mitigation actions. A small hydropower scheme producing impacts that almost always can be mitigated is con-sidered at lower administrative levels, where the influence of pressure groups - angling asso-ciations, ecologists, etc.- is greater. Impacts of hydropower schemes are highly location and technology specific. A high mountain diversion scheme, being situated in a highly sensitive area is more likely to generate impact that an integral low-head scheme in a valley. The upgrading and extension of existing facili-ties, which will be given priority in Europe, generates impacts that are quite different from an entirely new scheme. Diversion projects in mountains use the large change in elevation of a river as it flows downstream. The tail water from the power plant then re-enters the river, and entire areas of the river may be bypassed by a large volume of water, when the plant is in op-eration. A recent study by the German Federal Environmental Agency warns that especially new small scale hydro power plants (< 1 MWe) are not always environmentally friendly. The smaller the installation and the closer to a natural state the water, the lesser will be the CO2- and eco-nomical benefits and the higher the ecological damage for the water.24 Instead of installing new micro-plants the study proposes to concentrate on the optimisation of existing plants and on construction of plants at sites that are being hydromechanically altered for naval reasons anyway. The conflict between nature protection and renewable electricity generation is pro-posed to be mitigated by adequate spatial planning procedures, like the procedures for wind energy in Germany have shown.

24 UBA-TEXTE 1/2001: “Wasserkraft als Erneuerbare Energiequelle”



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4.1.4 Biomass Most biogas installations will be run in CHP mode. A point of distinction might be that for fossil CHP applications the environmental advantage will be based on a very high energy use factor in practice, while for biomass firing, the use of the heat is less crucial for the environ-mental evaluation. Biomass-fuelled CHP is making headway in countries such as Sweden, Finland and Austria, where e.g. use of forestry residues is widespread. Typical fields of appli-cation are wood-processing industries, district heating systems, industries with a high process heat demand, and co-combustion of biomass in existing fossil fuel-fired CHP plants. Biomass use for heating purpose only will not be covered. Biomass fuels used can be spilt in four categories: forestry residues, agricultural residues, agro-processing residues and energy crops. The biomass can remain unaltered and used di-rectly for combustion processes, or it can be converted into liquid or gas. Biomass-fuelled CHP schemes include therefore installations designed to run on solid, liquid and gaseous fu-els. In this chapter there is marginal attention for technologies that produce liquids. The bio-liquids are more suitable to compete with the fossil liquids in the transportation sector. How-ever, stand-alone mobile generators can also run on biofuels. This is however, beyond the scope of this study. For biogas plants a number of waste products from households, industry and agriculture can be used as fuels. These do include manure, organic waste from the food industry and organic municipality waste. Finally, municipality waste is the dominant fuel in incineration plants. But not all municipality waste can be considered as renewable biomass. This is subject to con-troversial political discussion and handled differently in the EU Member States. The Directive on Promotion of RES-E has provided some clarity by defining biomass as the biodegradable fraction of products, waste and residues from agriculture, forestry and related industries, as well as the biodegradable fraction of industrial and municipal waste A small fraction of plastics will normally be included in municipal waste. In Denmark this plastics fraction accounts for approximately 7% of the total volume of municipality waste. Waste from biomass can be used for a number of different applications.

4.1.4.1 Use of Biomass as Solid Fuel Before burning it, the biomass raw material may be chopped up, shredded or otherwise treated mechanically prior to its combustion in a steam cycle CHP plant. This treatment does, how-ever, not modify the material’s chemistry. The two principal combustion technologies are the following.

• Grate Firing Grate firing is adequate for fuel types that are moist, otherwise problematic and/or in lumps and require little in terms of fuel preparation. Grates are still used in many small and medium sized boilers. The fuel is charged on a stationary or slowly moving grate. The combustion temperatures are mainly between 1000 and 1300 °C. Whilst reliable and rela-tively inexpensive, grate firing systems are also somewhat inflexible and are usually de-signed to cope with a limited range of fuels.



36

• Fluidised Bed Combustion Here the fuel burns in a bed of sand or other mineral that is violently agitated by the com-bustion air. The fuel is fed at a controlled rate to keep the temperature of the bed at 800 - 900 °C. This type of boiler is proving very popular for medium-sized and large industrial boilers. A great advantage of the fluidised bed system is its fuel flexibility. Air staging, limestone addition and low combustion temperatures achieve relatively low emissions. For instance, sulphur emission control is not required, and NOx emissions are low. Yet, when recycled fuels are used, halogen, heavy metal, dioxin and furan emissions may need to be controlled. Installation of this system is more expensive and therefore economical only from output capacities above 10 MW. Fluidised bed combustion is ideal for low calorific value fuels.

The prevailing CHP technologies with regard to solid biomass combustion are steam boiler and turbine applications. Combustion of biomass is a proven technology. New developments include integration with fossil-fuel streams in existing power plants, resulting in higher over-all efficiencies compared to stand-alone systems. Combustion of energy crops in dedicated power plants is in development. Some demonstration projects are underway, but are still too early a stage. There is a constant drive to improve the combustion efficiency up to more than 30% and a reduction in emissions. The major development in this area is in large CHP plants. Direct combustion processes for heat production and driving a steam cycle are commercial-ised already. One promising development is co-combustion. New boiler concepts, where bio-mass is combusted together with coal, peat, RDF (refuse-derived-fuel) or other fuels can achieve high efficiencies, due scale factors and reduced risks as more than one fuels can be used, e.g., to compensate seasonal influences in bio-feedstock supply.

The Torbed plant

The Torbed co-firing plant is in its development stage, wood chips are burned in a pulverised coal fired power pant. This option has the advantage that the net generating efficiency of bio-mass conversion into power is higher than in conventional coal fired power plants. Moreover, the investment costs are lower. At present, several research institutes are working on the de-velopment of a stand-alone Torbed reactor. Based on a qualitative comparison with more de-veloped and commercialised incineration techniques, it was concluded that Torbed has enough potential as a competitive incineration technique to current technologies with an in-stallation size of 20-60 MWth. Torbed appears to be best suitable for burning fine material that needs no further pre-treatment. Stand-alone Torbed reactors are already in commercial use, but only in waste recovery processes.

4.1.4.2 Gasification Gasification technology offers the potential for cost-effective and environmentally acceptable reuse of waste, and high-efficiency biomass conversion. Several demonstration plants for the gasification of biomass and/or wastes have already been built. The resultant producer gas can be used in a gas engine, a gas turbine or (co-)combusted in a boiler. To date, the predominant technology used with regard to biogas-fuelled CHP appears to be the reciprocating engine. The challenge remains to use the produced gas in a high-efficiency integrated gasification



37

combined cycle (IGCC) unit. Much effort is currently being put into gas cleaning research to make the gas suitable for such use. In future it should be possible to determine whether this technology can be applied on a large scale. Intermediate scale biomass gasification projects are mostly based on air gasification, unlike oxygen gasification in case of coal fuelled IGCC. The use of air as a gasifying agent requires bulky gas cleaning equipment compared to oxygen gasification. More experience is needed in order to determine the optimum scale of biomass gasification. The same holds for optimal gasification pressure and gasifying agent.

Biomass Gasification Combined Cycle

One of the most promising options for power generation from biomass is Biomass Gasifica-tion Combined Cycle BiG-CC. BiG-CC is limited to larger capacities, >30 MWe and have electrical efficiencies of 32-41% and total efficiencies up to 83%. The efficiency strongly depends on the moisture of the biomass and the corresponding energy needed for pre-drying. It is assumed that clean wood with moisture of 10% by weight is used as fuel.

Biomass Gasification Solid Oxide Fuel Cells

Several systems have been investigated consisting of a pressurised biomass gasifier (BiG) and a solid oxide fuel cell (SOFC) coupled to a combined cycle. This combination offers the per-spective of very high efficiencies. It is also possible to feed biomass to a fuel cell with an in-ternal reforming technique. The highest efficiencies are attainable with a system consisting of a pressurised gasifier, high temperature gas cleaning, high temperature fuel cells and a com-bined cycle. Such a system can be applied to district heating, offering an additional efficiency gain. Although fuel cell capital costs are falling, increasing environmental restrictions are required before fuel cells will begin to replace conventional techniques in either power gen-eration or transportation.

Gibros two-stage gasification

Gibros offer a technology based on a combination of two-stage gasification and pyro-metallurgical smelting. This process converts waste materials into synthesis or fuel gas, met-als, metal mixtures and construction material. First pyrolysis takes place in an externally heated kiln. The tar containing gasses are subsequently gasified at high temperature (1200 - 1300�C) to produce syngas. Gasification takes place in the presence of either air or oxygen. The pyrolysis residue is smelted into synthetic basalt and metallic mixtures, using the remain-ing coal fraction as energy source and producing additional syngas.

4.1.4.3 Pyrolysis Pyrolysis is a thermal conversion process carried out in the absence of oxygen, yielding sol-ids, liquids and gases. The relative proportions depend on the reaction parameters such as temperature, reaction time and rate of reaction. The heat is usually indirectly added employing relatively low temperatures of 400-800°C. Within the context of electric power production, pyrolysis can be used as a pre-treatment step for the (co-)combustion or gasification of bio-mass and/or waste streams. The intermediate product has well-defined characteristics, which offers new opportunities for power production. Much of the present interest in pyrolysis fo-



38

cuses on the liquid products due to their high energy density and potential for premium liquid fuel substitution. The problems relating to pyrolysis are heat transfer into the feedstock, proc-ess control to give the required product mixture and separation of the products. It typically has a lower heating value of 13-17 MJ/kg. The water content is considerable (15-30%), which is important since this influences both chemical and physical stability and could affect the sub-sequent upgrading processes. Since the water is difficult to remove, utilisation on a wet basis is preferred. The quality of the original product is not comparable with gasoline, and cannot be used as a transport fuel. Upgrading is needed but expensive and leads to lower yields. Py-rolysis oil can be catalytically upgraded, which is proven in concept but has not been devel-oped well so far. Most attention has been paid to either hydrotreating or zeolite cracking. Nei-ther technology is yet available commercially, nor have robust mass balance and performance data been produced. As more financial scope for cleaner and/or better systems is expected in the medium- to long-term, the importance of pyrolysis as a pre-treatment step will increase.

Hydropyrolysis

Recently, new interest is coming up for hydropyrolysis. It is a pyrolysis process under a high pressure of hydrogen. Actually the name is erroneous, since it has more in common with gasi-fication in a hydrogen atmosphere. It has been identified as a promising option for converting biomass and hydrogen to synthetic natural gas. The quality of the synthetic natural gas is comparable with that of natural gas.

Waste pyrolysis

Pyrolysis of waste is now mainly carried out as a pre-treatment for high-temperature combus-tion or gasification processes.

Thermoselect

The Thermoselect concept comprises pyrolysis of municipal solid waste, followed by high-temperature gasification with oxygen. The resultant producer gas is burned in a gas engine to generate power and heat. Thermoselect offers processing lines each with capacities of 50 kton/yr. of MSW. The maximum capacity offered is 400 kton/yr. (8 lines).

Flash Pyrolysis

Flash Pyrolysis has a reactor residence time below 1 second. These fast reaction rates also minimise charcoal formation, and can be used to either maximise gaseous or liquid products. Pyrolysis oil is produced at short flash pyrolysis time and at a temperature of 500°C. Liquids are formed trough very high heating rates at moderate temperatures and rapid product quench-ing. Flash Pyrolysis can produce up to 80% mass yields of pyrolysis liquids.

4.1.4.4 Biological/biochemical processes Biological/biochemical processes are anaerobe and aerobe fermentation and distillation. These processes are commercialised for sugar and starch substrates. While sometimes biogas from fermentation processes is considered as a by-product which has a commercial value.



39

Anaerobic digestion

Anaerobic digestion (fermentation) can be an attractive conversion method for certain types of wet waste and biomass. In principle, the biogas can be used after treatment (and eventually upgrading to natural-gas quality) in the same way as natural gas. Production and utilisation of landfill gas based on MSW may also be an option for power production. Many demonstration and commercial plants are in operation around Europe. However, it should be noted that in most cases power generation in digestion processes is a by-product of the process. Like waste incineration, the main purpose of digestion is the processing of waste, not power production. Anaerobic digestion is the digestion of plant and animal material by various types of bacteria in absence of oxygen. Optimal temperatures are around 35-37°C. the main product is biogas, which consists mainly of methane (CH4 50-70%) and has a lower heating value of 19-27 MJ/Nm3. Most of the biogas production comes from the anaerobic digestion of sewage sludge, but the largest potential is in digestion of farmyard manure and agro-industrial wastes. Typically, between 40 and 60% of the organic matter present is converted to biogas. The re-mainder consists of odour free residue with appearance similar to peat that has some value as a soil conditioner and also, a liquid residue, which has potential as a fertiliser.

Landfill gas (LFG)

Landfill gas (LFG) is a mixture of basically CH4 (circa 50%) and CO2, resulting from the an-aerobic degradation of organic waste. The gas is collected and cleaned and then either burned to provide process heat or used for electricity production. Landfill gas can also be used as a chemical feedstock or in fuel cells, but these are still at the research and development stage. Although landfill gas is produced once anaerobic conditions are established within the land-fill, it may take several years before the landfill gas production rate is large enough to sustain a landfill gas use scheme. For a typically well engineered and well operated landfill, the ex-pected period over which gas will be produced may range from 50-100 years, but a useable gas production rate can be expected for only 10-15 years.

4.1.4.5 Hydrothermal Upgrading (HTU) HTU is a high-pressure (120-180 bar) process, which contacts wet biomass with water at tem-peratures of 300-350°C for 5-10 minutes. The oxygen content of the biomass is reduced from 40% on wet basis to about 10-15% on wet basis by the selective formation of CO2. Under these conditions an organic liquid or 'biocrude' is formed that resembles crude oil and which can be transported. The biocrude can be used for direct combustion as a liquid, for co-combustion as a solid fuel or for electrical power generation. Further upgrading of the biocrude is also possible by removal of the remaining oxygen (by catalytic hydrodeoxygena-tion). This has been proven (by laboratory experiments) to produce a good quality gas oil, but requires considerable amounts of hydrogen. However, upgrading costs are compensated by the higher product value. The upgrading product can be used as a fuel, in high-efficiency gas turbines or it can be used as a feedstock for the production of chemicals. The HTU process can use different feedstocks, and can be an attractive option for feedstock with a higher water content such as agricultural and domestic waste or biosludge, since no drying is required. It is further assumed that the residual lignin from ethanol production would be a suitable feedstock



40

for the HTU process, resulting in a "biorefinery' that produces both gasoline substitutes and gasoil substitutes. Little is known about the use of lignin, but the principle itself has been demonstrated. Probably, yields of HTU oil are little lower than those achieved from wood and the product quality might be less.

4.1.4.6 Economics of biomass systems

Cost of biofeedstocks

The costs of biomass depend on the dynamics of local markets, as well as on agreements, such as contracts between biomass users and producers. This cost includes all necessary transportation and handling, as well as pre-treatment (drying, size changes). Exact estimates are very difficult to make, as the markets are "immature" and changes occur rapidly.

Costs of bio-electricity

Many economic evaluations of electricity generation systems utilising biomass as a feedstock have been carried out. In the following Table, a comparison of such calculations for the main technologies available is presented. Table 4-6: Cost of biomass technologies

Generation capacity investment [MWe]

Cost Technology Applied

Efficiency [%]

present future k€/kWe €ct/kWth,e Combustion 15 - 35 1 - 50 100 1.1 - 2.8 2.8 - 6.2 Co-combustion Of existing power station 0.5 3.6 - 10 Gasification 20 - 35 0.1 -

25 ? 1.5 - 2.0 ?

Gasification - combined cycle 30 - 47 < 12 25 - 120 1.3 - 2.4 4.4 - 8.4 Flash pyrolysis - diesel 30 - 35 15 - 15 50 0.8 - 1.8 3.9 - 7.8 Biogas from urban waste 20 - 30 1? < 10 9 - 15 23 - 80 Biogas from landfills 20 - 30 < 1 ? 0.5 - 1.2 2.9 - 5.6

Today the upper limit of plants that are fuelled exclusively with biomass is within a range of 50 to 100 MWth since fuel acquisition, transport and logistics of the supply for higher outputs become too costly. The energy density of fresh biomass is low. This makes it uneconomic to transport it over distances longer than 100 km. Investment costs for smaller plants are signifi-cantly higher than for larger plants. A recent case study from Finland on the economies of biomass fuelled CHP schemes supports arguments that the use of solid biomass in Rankine steam cycle plants imposes lower capital and operation costs compared to engine schemes based on gas from biomass gasification and pyrolysis liquid fuel from biomass (see next chapters). In terms of cost-efficiency, co-firing approaches and the use of biomass in existing CHP plants can become an interesting alternative to the construction of new plants and/or the ex-clusive combustion of biomass. The share of biomass has a bearing on the whole process. If the quantity of biomass is • less than to 5% it can often directly be mixed with the fuel.



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• between 5% and 25%, the biomass must be shredded and burned in suitable burners. This new installation implies an important expenditure.

• more than 25%, the composition has an important impact on the combustion itself. Gasifi-cation of the biomass and combustion in a burner might be necessary. This will considera-bly increase the costs of the overall scheme.

4.1.4.7 Environmental Impact of Biomass-fuelled CHP Schemes Decentralised biomass-fuelled CHP can provide important environmental benefits in terms of reduced greenhouse gas emissions and preservation of the limited global stock of fossil fuel resources. Biomass combustion is CO2-neutral under the condition that the amount of biomass burnt is replaced, thereby keeping the overall stock of biomass constant. For instance, burning a certain amount of wood for CHP production releases CO2 emissions into the atmosphere. Yet, if simultaneously the same amount of wood is grown in forests, the same quantity of CO2 will be bound in the trees, and the overall CO2 balance is zero. In addition, biomass combus-tion produces less toxic gases such as CH4, NOx, or SO2. This is especially true in the case of biomass gasification as this technique avoids the emissions stemming from incomplete com-bustion of solid biomass. The following figures provided by the European Commission’s Di-rectorate General for Transport and Energy allow an estimation of pollutants’ emissions from different biomass fired processes: Table 4-7: Emissions from biomass fired processes

Parameters in kg/TJ

Gasification cycle Steam cycle

Emissions during Operation

CO2 025

NOx 13 23,5

SOx 118 497

Particulates 10 238

VOCS26 3,6 333

Emission during Construction

CO2 722 722

NOx 6 6

SOx 2,3 2,3

4.1.4.8 Long term goals The long-term goal of biomass R&D is to be competitive with fossil fuels without subsidies on a level playing field of full costs. Another goal of biomass R&D is to increase its contribu-tion to the projected primary energy demand of the EU to more than 20% in 2025 and more

25 Only under certain conditions outlined in the text

26 Volatile organic compounds



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than 30% in 2050. In parallel, it is necessary that the gradual increases of biomass energy con-tributions have to be realised in an environmentally sustainable way and accepted by the pub-lic.

4.1.4.9 Present status of technology and costs

• Combustion of biomass and waste is a mature and proven technology. Depending on the size of the plant, all mature combinations of fuel and technology are competitive to fossil-fuelled plants. At present the sizes of the combustion plants are relative small compared to fossil-fired plants. However, for commercial exploration larger plants >20MW are preferred. According to our definition of decentralised power generation future biomass combustion plants are probably considered as central power plants.

• As a pre-treatment technology at mainly coal fired power plants, gasification is a ma-ture technology. However, commercial is it still an unattractive option and the same situation arise for stand-alone installations. Even if gasification becomes a competitive technology, probably the same problem arises as with the combustion technologies. The gasification plants will be too large to be decentralised power plants.

• Pyrolysis is a pre-treatment technology that is in its research and development phase. The cost of pyrolysis is at present to high to be commercial interesting. The same ap-plies for the different upgrading technologies, they are expensive and leads to lower yields. None of the options is yet commercial available or have robust mass balances or perform stable.

• The biological processes are commercial available for sugar and starch containing biomass streams. However, mostly power generation is a by-product of processing waste streams. As stand-alone plant or as pre-treatment these processes are very com-petitive with fossil-fired power plants.

• Hydrothermal Upgrading is a proven technology however the cost of the produced biocrude is still too high to compete with crude oil. Further upgrading of the biocrude by removing the oxygen has been proven at laboratory scale. The extra cost for further upgrading is compensated by the higher value of the end product.

4.1.4.10 Future developments

• The development of combustion technologies focuses on further integration with fossil power plants, like the Torbed plant. At the same time dedicated plants are developed for the combustion of energy crops.

• The main problem with gasification is the contents of tar in synthesis gas. Therefore much effort is put in gas cleaning research. Another problem is the corrosive nature of the synthesis gas. Special gas turbines need to be developed. Further research is done on combinations of a gasification plant with a SOFC or reforming the gas to methanol. Finally, much effort is put in the development of a Biomass Gasification Combined Cycle unit.



43

• Improvement of the pyrolysis product upgrading processes is important for future suc-cess of the pyrolysis process. At the same time the performance of the technology will improve on several aspects.

• In future landfill gas might be used as a chemical feedstock or as fuel for fuel cells. Another promising development is the Simultaneous Sacharification and Fermentation process. This process produces ethanol from cellulose and hemicellulose. At present such systems are tested on semi-industrial scale.

• In the future it might be possible to use the residual lignin from ethanol production as a suitable feedstock for the HTU process, resulting in a "biorefinery' that produces both gasoline substitutes and gasoil substitutes.



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4.2 Combined Heat and Power (CHP) This chapter aims to provide an overview of CHP technologies currently used with regard to decentralised generation, including indications on typical investment costs for the CHP units described. These indications need, however, to be met with caution because the prize can vary greatly as a function of the size of the plant (bigger plants are normally cheaper per kWe in-stalled capacity). More importantly, the investment costs of additional requirements (build-ings, transport infrastructure, connection devices, studies etc.) can make up a considerable part of the final total investment.

4.2.1 Steam Turbines Steam turbines are amongst the CHP technologies most widely used. They can operate across a large range of capacity from 250 kWe to more than 500 MWe. Steam turbines are generally used in larger CHP plants producing more heat than electricity. This explains their popularity in industrial sectors with constant high heat demands. One of their main advantages is that, in theory, they can be run on any kind of fuel. Yet, the fuel most used to date is natural gas. High-pressure steam produced by a boiler is converted into mechanical energy and electricity when it passes through a steam turbine driving an electrical alternator. The mechanical force needed to run the alternator is obtained by the expansion of the steam through the turbine. The outputs of the system are electricity and low-pressure steam. Particular temperature and pressure specifications are set for steam inlet so that the CHP proc-ess is operated correctly. Typical values are 42 bar at 400°C and 63 bar at 480°C. Yet, depending upon the application a much bigger range of steam pressures and temperatures is possible, between a few to 100 bars for pressures, and between a few degrees to more than 500°C for temperatures. Two main turbine types are used in CHP units: Backpressure turbines and condensing tur-bines. Both use different technologies and have different exit pressures.

• Backpressure turbines operate with an exit pressure that must be at least equal to atmos-pheric pressure. Because of the possibility to extract steam from different stages of the turbine this turbine type is particularly suitable for processes that need an intermediate pressure steam load.

• Condensing turbines operate with an exit pressure lower than atmospheric pressure. Ex-cess heat is rejected through a condenser. The main interest for this technology is the ca-pability to change electrical and thermal power independently. Condensing turbines are usually configured as air-cooled condensers (the excess steam is recovered by a condens-ing unit in order to supply a steam load) or as vacuum cooled condenser (more expensive than the first type. This technique increases the global efficiency by raising the amount of electricity produced with the same amount of fuel).



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Table 4-8: Steam turbine characteristics

Efficiencies (%)

Power to Heat Ratio Fuel used

Global Electrical Size range

Steam tur-bine 0.1-0.5 Any fuel 60-80 7-20 0,5 MWe to

>100 MWe

Average cost investment in €/kWe 1000-2000

Operating and maintenance costs in €/kWh 0.003

4.2.2 Reciprocating Engines Reciprocating engines are well known from cars. They can be defined as “machines that ob-tain mechanical power by using the energy produced by the expenditure of a gas burned within a chamber integrated to the engine”: For this reason reciprocating engines are also called internal combustion engines or endothermic engines. If used for CHP generation, the engine drives an electric generator while the heat from the engine exhaust, cooling water and oil generates steam in a boiler. Engines have high efficiencies even in small sizes. They are widely used in small plants because they allow compact modular systems, where several small modules are assembled in on system. This allows to follow the load curves better within the optimum level of the modules. It also eases maintenance. Reciprocating engines are well fitted to processes that need a non-continuous power and low-pressure steam at low or me-dium temperature. They can be spilt into two main categories:

• Diesel engines: They are also called compression-ignition engines. Most Diesel engines running in CHP units are four stroke engines with a cycle consisting of intake, compres-sion, combustion and exhaust. During the first stroke air is drawn into the combustion chamber through an intake valve, then during the second stroke, a little part of the air is compressed bringing its temperature to about 440 °C. At the end of the compression phase vaporised fuel is injected within the chamber. The high temperature provokes the instant combustion of the fuel-air melt. The final stroke consists in the exhaust of the combustion gases. This kind of engine presents a higher heat to power ratio (from 0,5:1 to 3:1) com-pared to spark ignition engines, and operate through a large scale of very small sizes from 75 kWe for small units to a power equivalent of some 10 MWe for large systems.

• Spark ignition engines: This type of engine works similar to the Diesel engine, but the system follows the so-called Otto cycle, and ignition is provoked through an electrical spark at the end of the second stroke. Spark ignition engines range between 3 kWe and 6 MWe capacity. The heat to power ratio (from 1:1 to 3:1) is lower than the one of com-pression engine, yet the overall efficiency of this technology is higher.



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Table 4-9: Reciprocating engine characteristics

Efficiencies (%)

Thermo dy-namical cycle



Diesel engine Diesel cycle 0.8-2.4

Gas Biogas Gasoil HLO LFO

Naphta

65-90 35-45 5 kWe to 20 MWe

Spark ignition engine

Otto cycle 0.5-0.7

Gas Biogas HLO

Naphta

70-92 25-43 3 kWe to >6 MWe

Average cost investment in €/kWe (Diesel engine) 340-1000

Average cost investment in €/kWe (Spark ignition gas engine)

600-1600

Operating and maintenance costs in €/kWh 0.0075-0.015

4.2.3 Gas Turbines This technology is frequently in CHP schemes for industrial use due to its high reliability and large range of power (from 100 kWe to several hundred MWe), although sets smaller than 1 MWe have so far been generally uneconomic due to their comparatively low electrical effi-ciency and consequent high cost per kWe output. Here, the combustion of fuel creates a gas flow used as a medium by which heat is trans-formed into mechanical energy. After being pressurised, hot gas (around 1000°C) is propelled through nozzles against turbine wheel blades which causes their motion. The gas used must be free of any particles that could damage the wheel blades. The wheel is attached to a com-pressor or to an external load as an electrical generator. Exhaust gases generated by the proc-ess are at a pressure and temperature (around 500°C) permitting heat recovery, hot water gen-eration and production of steam. The plant ingests three to four times more air than is required simply to supply oxygen for combustion. The excess air is necessary to ensure correct cooling of the components in the whole gas path. It also means that the final exhaust gases contain large quantities of oxygen that may be used to support the combustion of additional fuel. This technique (supplementary firing) may be used to increase exhaust gas temperatures to 1,000°C or more, raising the overall heat to power ratio to as much as 10:1 (although up to 5:1 is more typical). Supple-mentary firing, also known as boost firing, is highly efficient, as no additional combustion air is required to burn extra fuel. Efficiencies of 95% or more are typical for the fuel burned in supplementary firing systems. Thanks to their high reliability gas turbines are particularly suitable for processes that require a continuous power supply have important needs of high-grade steam or hot water.



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Table 4-10: Gas turbine characteristics

Efficiencies (%)



Gas turbine 0.2-0.8

Gas Biogas Gasoil HLO LFO

Naphta

65-87 25-42 250 kWe to >50 MWe



4.2.4 Combined Cycle Gas Turbines Combined Cycle Gas Turbines (CCGT) are well adapted for medium to large-scale CHP gen-eration from 3 MWe to over 300 MWe and permit the best electrical efficiency compared to the other prime movers. The CCGT system features the combination of two technologies pre-viously presented: gas turbine and steam turbine. Simple gas turbines (also called open cycle gas turbine) use exhaust heat directly to meet the heat demand of the site. In the case of CCGT, the exhaust heat of the gas turbine is used to produce steam to run a steam turbine. The steam turbine is thus used as heat recovery generator. This reduces energy losses and increases the performance of the system. The electrical efficiency of CCGT can be between 35-55%, as compared to 25-42% for a simple gas turbine. CCGT technology is today widely used, particularly in the 50 MWe range. Table 4-11: Combined cycle gas turbine characteristics

Efficiencies (%)

Thermo dy-namical cycle



CCGT Joule-Rankine 0.6-2.0 Mostly natural

gas 65-90 35-55 3 to

>300 MWe



4.2.5 New Small-Scale CHP Technologies The definition of what should be considered small scale CHP varies widely across European countries, depending upon their particular energy culture. A European-wide definition that appears to find wide acceptance considers “small-scale” all CHP units under 1 MWe. Engines are so far the dominant technology used in this area. Yet, some new technologies are already on the market or likely to become widely commer-cialised in the forthcoming years. A number of small sized gas turbines have already been successfully developed and others are field-tested. Also, much research and development ef-



48

forts are dedicated to fuel cells (cf. chapter 4.2.6), making future penetration of this technol-ogy into European CHP markets likely. Finally, increasing interest is shown in the advantages of Sterling engines.

4.2.5.1 Micro Turbines The basic technology of micro turbines is derived from aircraft auxiliary power systems, die-sel engine turbochargers, and automotive designs. Micro turbines stick out for their reliability, small size and low weight. R&D efforts are dedicated to the construction of a micro turbine with a power output of a few kilowatts. Today’s devices have a greater efficiency and lower emissions of greenhouse gases than internal combustion engines. Micro turbines' high outlet temperature (>500°C) is suitable for numerous high-value applications, such as direct drying or heating processes. Micro turbines function similar to their large-scale counterparts, but their electrical efficiency is only about 15%. This figure can be improved with the installation of a recuperator that pre-heats air used during the combustion process by reusing exhausting gas heat. This device also allows varying the power to heat ratio. Micro turbines are still more expensive than internal combustion engines, but the few moving parts of the device lower their operation and maintenance costs. The life expectancy of micro turbines is 40000 hours. Table 4-12: Micro Turbine characteristics

Efficiencies (%) Power to Heat Ratio Fuel used


Micro turbine

1.2-1.7

Natural gas Gasoil Diesel

Propane Kerosene

Biogas

60-85 15-30 15 kWe to 300 kWe


4.2.5.2 Stirling Engines Stirling engines promise advantages with a particular view to small-scale CHP in units as small as 0,2 kWe: High efficiency, good performance at partial load, fuel flexibility, and low noise and air emission levels. Compared to internal combustion engines, the Stirling engine is an external combustion device where the cycle medium is not exchanged during each cycle, but remains within the cycle whilst the energy driving the cycle is applied externally. The burner supplying heat to the process can operate on different fuels (gasoline, alcohol, natural gas or butane). The external combustion facilitates the control of the combustion process and supports a cleaner and more efficient process. The so-called Stirling cycle consists of the expansion and compression of a working gas, gen-erally helium or hydrogen, inside a chamber featuring a system of pistons and crank/-shaft



49

mechanisms to move the gas around. The pistons can be arranged in different ways, e.g. two pistons in one cylinder, two pistons and two cylinders per cycle, or four cylinders with four double acting pistons leading to four separated cycles. The Stirling engine technology is still in its development. No statistical data on reliability, availability or price are therefore available. Stirling engine developments in the car industry during the 70s could not beat the conventional diesel and Otto engines. Yet, the promising prospects in terms of emission, noise, vibration and efficiency stimulate the further research into this device for CHP applications. Table 4-13: Stirling engine characteristics

Efficiencies (%) Thermo dynamical

cycle



Stirling engine

Stirling cy-cle 1.2-1.7

Natural gas Gasoil Alcohol Butane

65-85 ~ 40 3 kWe to 1.5 MWe

Average cost investment in €/kWe Still to be determined

4.2.6 Fuel Cell Technology The principle of using a chemical reaction to produce electrical energy has been with us for more than 150 years. However, there are still technical barriers to overcome, like fuel toxicity, storage, electrolyte poisoning and fuel infrastructure. Not to mention that whatever the appli-cation, the incumbent technology is significantly cheaper than the fuel cell (FC) alternative. Fuel cell technology can be divided in automotive and stationary applications. However, fuel cells are unlikely to make a significant impact in the automobile sector until 2004 - 2005. Fuel cells as a stationary energy generating option might benefit from the growth in the digital economy. The digital economy requires high reliability power, which can be provided by fuel cells. Another development that might be profitable is the ongoing liberalisation. In a liberal-ised market small generation plants require less investment capital per plant. New technolo-gies such as micro turbines and fuel cells are likely to be serious contenders for this market as compared to the reciprocal gensets. There are currently 5 or 6 competing technologies, all of which have specific pros and cons. Each one is likely to find use for specific applications but at present no clear choice is made for a specific technology or stationary or mobile applica-tions.

4.2.6.1 Polymer Electrolyte Membrane (PEM) The PEM fuel cell consists of two electrodes, the anode and the cathode, separated by a polymer membrane electrolyte. Normal electrolytes are substances that dissociate into ions that conduct electricity when dissolved in water. The unusual property of the PEM, as its name suggests is that the electrolyte is a conducting polymer. Each of the electrodes is coated on one side with a thin layer of platinum catalyst. The cell itself is usually housed between



50

two conducting graphite capture plates and are combined into a fuel cell stack to provide the amount of electrical power required. Table 4-14: Key properties of a PEM fuel cell

Fuel cell part Property Anode Cathode Electrolyte Conducting ion Operating temperature Efficiency Catalyst Operation Stage of development

Hydrogen enters the cell Oxygen enters the cell Polymer membrane H+ 50-100°C 35-50% Platinum Instant start up, only exhaust is steam. Prototype available for automotive use.

Chemistry

Polymer membranes are unusual in that they absorb water, which allows the negative ions to be held in place and the positive ions, to pass through. The fact that charge flows in one direc-tion only is key to the operation of the fuel cell producing electricity. The reaction that takes place in a PEM fuel cell is as follows:

Anode: Cathode: Overall:

2H2 4e- + 4H+ + O2

2H2 + O2

= = =

4H+ + 4e- 2H2O 2H2O

The electrode itself has an additional property, which is key to effective operation. The mem-brane is gas impermeable and keeps the hydrogen gas separate from air, which improves both efficiency and operating life.

Fuel input

The ultimate fuel for a PEM electrode is hydrogen. Hydrogen can be used directly by pump-ing the gas into the fuel cell or it can be produced in-situ from various source gases using a hydrogen reformer. Direct hydrogen is difficult to store, hydrogen generated from the refor-mation process is susceptible to impurities as unreformed source gas can enter the fuel cell and pollute the catalyst. This means that it is yet unclear whether direct hydrogen, direct methanol or reformed hydrogen will be the preferred fuel in final commercial applications. The first impression is that the cost of installing infrastructure to distribute pure hydrogen is prohibitively high so ultimately, the choice will be between direct methanol and reformed hydrogen. However, it essentially depends on the application of the fuel cell as to which method is used both methods are currently less than ideal for many of the proposed applica-tions.

Advantages

• Quick start up - load following • Solid electrolyte reduces corrosion • Simple and can be made small



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Disadvantages

• Expensive catalyst required because of low temperature operation • Highly sensitive to fuel impurities • No infrastructure for hydrogen storage and delivery

• Reforming technology has yet to evolve

Applications

The PEM is probably the most versatile FC because of its ability to vary its output to meet shifts in demand. It can be used for both mobile and stationary applications including power generation at relatively low power levels. The PEM appears to be the FC of choice for auto-motive applications. The mobile power generation market is also likely to be captured by PEM technology. The advantage of being small allows the PEM to be used to power laptop PCs, mobile phones and other portable appliances. It is unlikely that PEM technology will be widely used for high voltage stationary power gen-eration. For cells larger than 1 kW, hydrogen gas must be pressurised to increase the chemical reaction rate. However, this has the effect of complicating the construction and reducing the efficiency. Also MOFC and SOFC, that operate at high temperatures work on much higher efficiency levels and do not require external reforming.

4.2.6.2 Direct Methanol Fuel Cell (DMFC) The construction of the cell is similar to the PEM since the direct methanol fuel cell is a vari-ant of the PEM fuel cell. Rather than either hydrogen being pumped directly into the cell or being generated by a reforming unit, liquid methanol is introduced to the anode at relatively low temperatures (<50°C). Traditionally, direct methanol fuel cells have only been partly as efficient as their direct hydrogen counterparts but over the past five years, tremendous pro-gress has been made and efficiencies are now in the order of 40%. Table 4-15: Key proportion of a DMFC fuel cell


Methanol introduced Oxygen introduced Conducting polymer H+ <50°C (room temperature) 20% Platinum Plagued by low efficiency Pre prototype



52

Chemistry

The electrochemistry is completely different from a traditional PEM fuel cell. Rather than H2 dissociating into ions and forming the conduction medium, methanol itself is converted to CO2 and H2 ions, O2 is introduced into the reaction to produce water. The overall cell reaction is shown below. Anode: Cathode: Overall:

CH3OH + H2O 6H+ + 1½O2 + 6e-

CH3OH + O2

= = =

CO2 + 6H+ +6e- 3H2O CO2 +2H2O

There is however a competing reaction which produces CO and water. The water is not a problem but the CO poisons the catalyst and makes the process more complex and more ex-pensive.

Fuel input

The obvious advantage is that methanol is a liquid, can be easily transported and can be easily integrated into the existing infrastructure. In addition current methanol specification is suit-able for use in fuel cells since it can be purified relatively easily. A safety concern is the flammability, not only is methanol highly flammable but it burns with a colourless flame.

Advantages

• Readily available fuel. • No need for hydrogen reformer.

• Liquid handling infrastructure already. • Start up at very low temperature of 20°C.

Disadvantages

• Methanol toxicity - causes blindness and possibly death.

• Burns with a clear flame so additives would have to be introduced which could potentially poison the catalyst.

• Platinum catalyst susceptible to poisoning. Methanol must be pure and more Platinum is required than in the hydrogen fuelled PEM.

• Fuel leakage from anode to cathode reduces performance.

Applications

Like hydrogen PEMs direct methanol fuel cells are eventually likely to have multiple applica-tions. Given the low operating temperature, direct methanol fuel cells are the ideal choice for small portable applications like laptop computers and mobile phones. In addition, the liquid nature of the fuel means that direct methanol appears to be a more natural solution for auto-mobile applications.

4.2.6.3 Solid Oxide Fuel Cell (SOFC) As the name suggests SOFCs have a solid metal oxide usually zirconium with a small amount of Yttrium electrolyte. The solid state avoids problems of electrolyte circulation and evapora-



53

tion associated with liquid electrolytes. In order to produce significant amounts of power, SOFC elements are assembled into a stack. Table 4-16: Key properties of a SOFC fuel cell


Hydrogen, carbon monoxide, methane Oxygen, Mr Yttria stabilised Zirconia 02 650-1000°C 50-60% Parasites Flexible in fuel (even CO), resistant to impurities, very slow start up time Close to commercialisation

Chemistry

Again, the fuel itself dictates the specifics of the chemical reaction. The conduction medium in this case is an oxygen ion rather than hydrogen. The basic chemical reaction using hydro-gen as the fuel is similar to any other. The electrochemical reaction occurring in SOFC is. Anode: Cathode: Overall:

½O2 + 2e-

H2 + ½O2

H2 + O2-

= = =

O2 H2O H2O + 2e-

Fuel input

One of the key differences between the SOFC and the PEMs is the transportation ion. SOFC use O2 as the conducting ion and as such the fuel does not have to be or produce hydrogen. A variety of hydrocarbon fuels can be used such as gasoline, methanol and even CO which al-lows flexibility. SOFC can reform natural gas internally and have significant advantages in efficiency and simplicity when using natural gas because they do not need an external re-former.

Advantages

• SOFCs are the most efficient (fuel input to electricity output) fuel cell electricity generator currently being developed world-wide for carbon based fuels, e.g., natural gas

• The high operating temperature of SOFCs produces manageable quantities of high grade waste heat suited well to co-generation applications

• SOFCs do not contain noble metals which could constitute a resource availability and price issue in high volume manufacture; and

• SOFCs do not utilise liquid electrolytes, which can be problematic and expensive.

Disadvantages

• High operating temperatures require specialised and exotic materials for interconnect and other stack components, which leads to high material and production costs. These high



54

temperatures also present a problem for long-term operation and reliability due to material oxidation and integrating the required balance of plant.

• High temperatures enhance corrosion and breakdown of components. This increases the capital cost of the fuel cell stack.

• Fuel burning is required to reach operating temperature hence start-up time is very slow. • High temperatures mean it may not be appropriate for applications much below 1 kW. • Has to be used as a base load rather than a back up because of the start-up time required.

Applications

Since the SOFC does not produce any power below 650°C, a few minutes of fuel burning is required to reach operating temperature. This time delay is considered to be a disadvantage for automotive applications. A conventional battery could be used to supplement the fuel cell in the first few minutes of operation but this adds to the weight and would reduce perform-ance of the fuel cell vehicle. However commercial auto applications where vehicles run al-most continuously could utilise this technology. Start-up time is less of an issue for stationary and continuous applications. Due to the size and temperatures needed, SOFC lend themselves to being used for power generation. They are generally efficient with around 65% efficiency being achieved in an average 5 MW plant compared to around 30% for a traditional gas turbine.

4.2.6.4 Phosphoric Acid Fuel Cell (PAFC) The PAFC uses liquid phosphoric acid as the electrolyte. The phosphoric acid is contained in a Teflon bonded silicone carbide matrix. The small pore structure of this matrix preferentially keeps the acid in place through capillary action. Some acid may be entrained in the fuel or oxidant streams and addition of acid may be required after many hours of operation. Platinum catalysed, porous carbon electrodes are used on both the fuel (anode) and oxidant (cathode) sides of the electrolyte. Table 4-17: Key properties of a PAFC fuel cell


Hydrogen Oxygen, Air Phosphoric acid (liquid) H+ 100-200°C 40-55% Platinum n/a/ Commercially available

Chemistry

The chemistry is very similar to that of the PEM fuel cell with reformed hydrogen being used as the fuel and H+ the charge carrying ion. The reaction that takes place is as follows:



55

Anode: Cathode: Overall:

2H2

4e- + 4H+ + O2

2H2 + O2

= = =

4H+ + 4e- 2H2O 2H2O

Fuel input

Again, hydrogen is the ultimate fuel for the reaction in the phosphoric acid fuel cell but vari-ous fuels including natural gas, LPG and methanol can be used as a raw input and converted to hydrogen using a reformer.

Advantages

• Resistant to impurities • Multiple fuel options

• Option to use a less expensive catalyst

Disadvantages

• Low current due to cathode kinetics and power output. • Tends to have a lower efficiency than other technologies.

• Large size and weight • Corrosive liquid electrolyte leads to limitation in applications.

Applications

The PAFC is the most mature of the technologies and has been under development for 15 years. It is only a realistic option for stationary power applications due to system complexity, higher capital costs and lower efficiencies than the MCFC and the SOFC. The lower operat-ing temperatures make the PAFC ideal for small and mid size power plants replacing large electrical generators. Hospitals, hotels and airports, where constant and uninterrupted supply is important are where the phosphoric acid niche exists.

4.2.6.5 Molten Carbonate Fuel Cell (MCFC) The MCFC uses a molten carbonate salt mixture as its electrolyte. The composition of the electrolyte varies, but usually consists of lithium carbonate and potassium carbonate. At the operating temperature of about 650°C, the salt mixture is liquid and a good ionic conductor. The electrolyte is suspended in a porous, insulating and chemically inert ceramic matrix.



56

Table 4-18: Key properties of a MCFC fuel cell


Hydrogen, carbon monoxide Oxygen, Mr Phosphoric acid (Immobilised liquid) CO3

2- 600-660°C 55-57% Nickel Instant start up Commercially available

Chemistry

The anode process involves a reaction between hydrogen and carbonate ions (CO32-) from the

electrolyte, which produces water and CO2 while releasing electrons to the anode. The cath-ode process combines O2 and CO2 from the oxidant stream with electrons from the cathode to produce CO3

2-, which enter the electrolyte. The need for CO2 in the oxidant stream requires a system for collecting CO2 from the anode exhaust and mixing it with the cathode feed stream Anode: Cathode: Overall:

H2 + CO32-

O2 + 2CO2 + 4e-

CO + CO32-

= = =

H2O + CO2 + 2e- 2CO3

2- 2CO2 + 2e-

Fuel input

The MCFC uses a molten carbonate salt mixture as its electrolyte. The composition of the electrolyte varies, but usually consists of lithium carbonate and potassium carbonate.

Advantages

• High operating temperature allows for combined heat and power generation and high fuel to electricity efficiencies.

• Operating temperature not so high as to require expensive components. • Reforming inside the stack and tolerates impurities therefore may use a variety of fuels.

Disadvantages

• Molten carbonate electrolyte is highly corrosive and limits stability and life of cell com-ponents.

Applications

The MCFC has also been under development for 15 years as large, high powered applications such as heavy industry and even for supplying national electrical grid networks. Like SOFCs, molten carbonates offer higher efficiency than PEMs but poorer flexibility in terms of start up time and output. This makes them ideally suited to base load power generation where con-tinuous operation is a must. However, corrosiveness of the molten carbonate electrolyte limits



57

the life of the cell components and adds to the capital cost making MCFC more expensive than both SOFC and PEM in terms of their capital cost.

4.2.6.6 Alkaline Fuel Cell The Alkaline fuel cell requires two porous electrodes, which are separated by an alkaline elec-trolyte, in this case potassium hydroxide. By making the electro chemical reaction as efficient as possible and by simplifying the collection of electricity produced, this fuel cell principle is commercial viability. Table 4-19: Key properties of an Alkaline fuel cell

Fuel cell part Property Anode Cathode Electrolyte Conducting Ion Operating temperature Efficiency Catalyst Operation Stage of development

Hydrogen Oxygen Aqueous potassium hydroxide soaked in a matrix OH- 60-70°C 55-70% Platinum Instant start up Commercially available

Chemistry

The chemistry is the simplest of all the fuel cells. A basic alkaline electrolyte, oxygen and hydrogen as fuel, makes the process just the reverse electrolysis of water. Anode: Cathode: Overall:

2H2 + 4OH-

O2 + 2H2O + 4e-

2H2 + O2

= = =

4H2O + 4e- 4OH- 2H2O

Fuel input

Due to the basic nature of the alkaline fuel cell, hydrogen is the only fuel that can be used. Applications are limited because of the need for pure hydrogen and oxygen. The smallest amount of carbon dioxide in the air is harmful

Advantages

• Low operating temperature • Rapid start up time • Readily available electrolyte hence cheap to manufacture. • High efficiencies of up to 70% with low system losses

Disadvantages

• Highly sensitive to CO2 pollution • Expensive to remove the CO2 from fuel and oxygen streams.

• Applications limited to those where pure hydrogen and oxygen are available.



58

Applications

The alkaline fuel cell was one of the firsts to have a commercial application. This technology was used in the manned space flights in the 60s to produce clean water. They use alkaline potassium hydroxide as the electrolyte and can achieve efficiencies of up to 70%. Recent de-velopers believe that this fuel cell can be used for many applications, like stationary power generation but also mobile applications including both marine and road vehicles.

4.2.6.7 Present Status of Technology and Costs Despite niche markets for each fuel cell type, the incumbent technology is significant cheaper, nevertheless 4 out of 6 are commercial available. Although the efficiencies vary from 20 to 70% on average a fuel cell performs better than a gas engine or turbine. In general there is a relation between operating temperature of the fuel cell and its start-up time. The lower the operating temperature the shorter the start-up time. At present there is no best fuel cell tech-nology, which is caused by the differences in application and the fuel used. As long as it is difficult to store or transport hydrogen, produce methanol on a large scale or purifies the tradi-tional fossil fuels all the FC concepts have their pros and cons.

4.2.6.8 Future Developments Future developments will concentrate on 2 lines, one is improving the performance of the cells itself the other focuses on fuel storage and transportation systems. Fuel cell improve-ments will come from reducing cells sensitivity to fuel impurities and electrolyte poisoning. Besides the fuel side of the FC the corrosiveness of the Alkaline and the Solid Oxide Fuel Cell will reduce as a result of using improved materials. Finally coat reduction will occur through reduced use of platinum or replacing other expensive materials. Through improved hydrogen storage methods and reforming technologies a separate hydro-gen distribution network will not enter the market. Although hydrogen storage and reforming is difficult, it is probably cheaper than a separate hydrogen network. Before methanol will be used on a large scale as the fuel for FCs the toxicity and colourless of methanol have to be solved. This can relatively easily achieved with some additives however, it is unknown if those additives will poison the fuel cells.



59

4.3 Future Decentralised Energy Systems 2020

4.3.1 Introduction In this chapter the results from the DECENT futures study on decentralised energy generation are presented. It starts with some general remarks on how and when the survey was con-ducted, and who responded to the questionnaire. The results from the survey firstly highlight the general framework topics important for the future decentralised energy generation. Secondly, rather technology oriented statements are analysed, starting with the ranking of statements. The top ten topics, which are selected on the combined index of environmental impact and production cost impact, are presented and de-scribed. Furthermore, a short description is made regarding the remaining topics. For all top-ics as well as for single decentralised energy types, the time of occurrence and barriers/ con-straints for realising the statement are described. Finally, concluding comments from the re-spondents are summarised.

4.3.2 General Remarks The DECENT futures study is basically designed as an adapted Delphi investigation. It is de-signed by an initial round of DECENT expert discussion on central statements about the fu-ture development of decentralised energy generation. The second round consists of a larger anonymous survey among external experts about the future development of decentralised en-ergy generation. The third round was the building of scenarios by a team of DECENT re-searchers, which (in a fourth round) were subject to an external expert review (the scenarios are presented in chapter 6). The survey was conducted as a one round exercise in the period November 5 – November 16, 2001. A reminder was sent out on November 12. The initial population of the survey was 329 experts, which were identified by the DECENT team and DG TREN. Furthermore, experts were invited to forward the invitation to other relevant experts. We do not know the number of this nominated population. All respondents received an e-mail invitation to participate in the survey. 32 out of the 329 were returned due to unknown or unidentified addresses, making a population of 297. A total number of 66 experts filled out the questionnaire. This makes a response rate of 22%. Compared to other international technology foresight exercises, the response rate is less than the British Delphi in 1995 with approximately 31% response rate, but more than the Danish sensor technology foresight in 2001 made by Risoe National Labo-ratory, making a response rate of 16%. The following outlines the profile of the responding population, as captured by background information: • Respondents work primarily in Denmark (29%), 14% work in Spain, 11% work in the

Netherlands, and 8% in the United Kingdom. The remaining respondents work in Italy, Germany, Portugal, Finland, France, Luxembourg, Slovenia, Switzerland, and the USA. Approximately 20% have not specified in which country they primarily work.

• The majority of the respondents work first and foremost in academic research (27%), and in corporate strategy for research and technology (20%). Some work in public administra-tion and planning (14%), and marketing/business management (11%). Only 5% work in



60

production/operations. Respondents also work in consultancy, trade union, business asso-ciation, and promotion of renewable energy sources among the general public. 14% have not answered the question.

Generally, respondents are expert or knowledgeable about the technological topics high-lighted in the questionnaire as it appears from the figure below.

0

10

20

30

40

50

60

Expert Knowledgeable Unfamiliar

Per

cent

Figure 4-8: Level of expertise of survey participants

In particular, respondents consider themselves expert or knowledgeable within wind energy (76%) and photovoltaics (70%), and to a lesser degree within biomass (58%), CHP (56%), fuel cells (55%), and small hydro plants (49%). For details see the figure below.

0

10

20

30

40

50

60

Expert Knowledgeable Unfamiliar

Pe

rce

nt

GeneralWind powerPhotovoltaicsBiomassSmall hydroCHPFuel cells

Figure 4-9: Expertise of survey participants according to energy type

General remarks from individual respondents emphasise that the questions are designed to get the political right answer and that the questions on the beneficial impact of the topic on envi-ronment and cost of energy is difficult to understand. One respondent, moreover, points to the error in statement No. 18 (20-400 MW instead of 20-400 kW).



61

4.3.3 General Framework Topics Important for Decentralised Energy Generation in the EU up to 2020

Respondents were asked to assess a number of framework topics and their impact on the fu-ture decentralised energy generation in the EU up to 2020. In the table below, the results are shown. Highly beneficial and beneficial impact is in particular expected from global environmental concern (82%), easy and transparent grid access for DGs (77%), and renewables prioritised in power dispatch (71%), but also from EU support mechanisms (67%), local/regional environ-mental concern (65%), regional development concern (59%), clear spatial planning provision and procedures (58%), and national security of supply (55%). The highly beneficial and bene-ficial impact is less from topics such as robust energy systems (47%), full EU liberalisation of the energy market (39%), and large European market players in electricity industry (20%). Table 4-20: Impact of topics on decentralised energy generation in the EU.

Figures as percentages

H

ighl

y be

nefic

ial

Ben

efic

ial

Neu

tral

Adv

erse

Hig

hly

adve

rse

N.A

.

Global environmental concern (green house gases) 44 38 5 14 Local/regional environmental concern 21 44 15 6 14

Easy and transparent grid access for DGs 41 36 9 14 Renewables prioritised in power dispatch 39 32 12 3 14 Robust energy system 20 27 26 9 18 National security of supply 21 33 20 11 15 Clear spatial planning provision and procedures 11 47 23 5 15 Regional development concern 8 52 24 17 Full EU liberalisation of the energy market 9 30 15 27 3 15 Large European market players in electricity industry

6 14 26 27 12 15

EU support mechanisms for DGs 32 35 15 3 15 Neutral impact is largest from topics such as robust energy systems (26%), large European market players in electricity industry (26%), regional development concern (24%), and clear spatial planning provision and procedures (23%). Adverse or highly adverse impact is outspoken from topics such as large European market players in electricity industry (39%) and full EU liberalisation of the energy market (30%). Some adverse impact is also expected by the topic of national security of supply (11%) and robust energy system (9%). Summing up, respondents tend to disagree on topics such as full EU liberalisation of the en-ergy market, large European market players in the electricity industry, national security of supply, and robust energy systems. On the contrary, they tend to agree on global environ-mental concern, easy and transparent grid access, and regional development concern.



62

4.3.4 Ranking of Topics The ranking of the 27 statements on the future development of decentralised energy genera-tion is based on the combined index of impact on global environment (CO2) and impact on cost of energy production. Based on expert and knowledgeable responses to each topic, calcu-lations have been based on total numbers of respondents and weighted values of 100 (high), 0 (medium), and –100 (Low), respectively). The combined index of global environmental impact and cost production impact is illustrated in the figure below.

-100

0

100

-100 0 100

Impact on global environment

Imp

ac

t o

n c

os

t o

f e

ne

rgy

Figure 4-10: Combined index of global environmental impact and cost production

impact

While the top topics are located in Quadrant I (upper right), attention should also be given to topics in Quadrant II (upper left) as these represent high expectations to cost production, but with large unsolved environmental challenges. Topics in Quadrant IV (lower right) are also interesting as they represent an environmental push looking for cost production reductions. Quadrant III (lower left) is not interesting having low expectations to beneficial impact on both global environmental and cost production. The top ten topics selected by the combined index are presented below. Table 4-21 outlines the beneficial impact on global environment, cost production, as well as the combined index together with time of occurrence. The top ten topics have a combined index higher than or equal to 10. The top ten topics include all decentralised energy forms, except for CHP and small hydro plants. Eight out of ten topics are expected to be realised in the period 2011-2020 while the remaining two are expected to be realised after 2020. Some topics may be expected to have beneficial impact on the global environment, but are not expected to have a beneficial impact on cost of energy (No. 26, No. 2, and No. 1). A more balanced view may be observed on top-ics on photovoltaics (No. 9 and No. 8).



63

Table 4-21: Characteristics of top ten topics R

ank

No.

Statement

E in

dex

C in

dex

E&C

inde

x

Tim

e of

oc

curr

ence

1 3 50% cost reduction of wind produced electricity relative to 2001

40 12 26 2011-2020 (50%)

2 7 5% of Europe’s electricity comes from photovoltaics

10 33 22 After 2020 (56%)

3 26 30% of fuel cell fuels in EU are derived from renewable sources

45 -5 20 After 2020 (63%)

4 2 10% of Europe’s electricity comes from wind power

52 -16 18 2011-2020 (44%)

5 9 Widespread use of photovoltaics inte-grated into roof tiles

15 15 15 2011-2020 (39%)

6 8 50% cost reduction of electricity from photovoltaics relative to 2001

10 18 14 2011-2020 (50%)

7 1 10% of EU’s power demand is covered by energy from renewable sources

40 -15 13 2011-2020 (43%)

8 25 75% cost reduction produced by station-ary fuel cells relative to 2001

5 18 12 2011-2020 (42%)

9 5 More than one-third of wind turbine capacity in EU comes from offshore sites

27 -4 11 2011-2020 (58%)

10 10 20% of EU’s electricity is based on bio-mass

18 2 10 2011-2020 (35%)

When looking at the top ten and barriers for their realisation in the table below, it is observed that lack of R&D resources is ranked as the highest barrier for half of the topics (No. 3, No. 32, No. 26, No. 8, and No. 25). Spatial planning is the most important barrier for topics on wind energy (No. 2 and No. 5), while lack of support mechanisms is highlighted for divergent topics (No. 9, No. 1, and No. 10).



64

Table 4-22: Barriers to the Top Ten Topics (in percentage)

Ran

k

No.

Statement

Spat

ial

plan

ning

Inad

equa

te

stan

dard

s

Lac

k of

R

&D

fund

.

Insu

ffic

ient

ed

u./s

kills

Lac

k of

su

pp. m

ech.

Lac

k of

pu

blic

info

.

Oth

er

1 3 50% cost reduction of wind produced electricity relative to 2001

18 12 27 7 24 4 8

2 7 5% of Europe’s electricity comes from photovoltaics

8 11 32 4 29 11 6

3 26 30% of fuel cell fuels in EU are derived from renewable sources

10 12 36 7 27 5 2

4 2 10% of Europe’s electricity comes from wind power

37 4 12 4 26 13 4

5 9 Widespread use of photovoltaics inte-grated into roof tiles

14 18 16 9 25 15 3

6 8 50% cost reduction of electricity from photovoltaics relative to 2001

3 14 40 3 27 5 7

7 1 10% of EU’s power demand is covered by energy from renewable sources

16 16 13 9 27 12 7

8 25 75% cost reduction produced by station-ary fuel cells relative to 2001

8 11 42 7 23 4 4

9 5 More than one-third of wind turbine capacity in EU comes from offshore sites

28 11 18 5 4 4 9

10 10 20% of EU’s electricity is based on bio-mass

20 8 21 10 24 8 8

The higher middle list comprises topics, following the top ten topics. The topics have an index lower than 10 and higher than or equal to zero. Table 4-23: Higher middle list

Ran

k

No.

Statement

E in

dex

C in

dex

E&C

inde

x

11 6 Development of a new revolutionary and competitive wind tur-bine concept

10 5 7

12 22 Widespread use of domestic and commercial fuel cell units 22 -13 4 13 23 CHP fuel cell units will reach an expected life time of more than

40,000 working hours 0 8 4

14 24 10% of Europe’s domestic power demand is covered by fuel cells located in domestic houses

15 -7 4



65

The lower middle list contains topics with an index lower than zero and higher than or equal to –10. Table 4-24: Lower middle list

Ran

k

No.

Statement

E in

dex

C in

dex

E&C

inde

x

15 17 10% of private households in EU have micro CHP units installed -4 0 -2

16 4 Practical use of wind turbines at a rated capacity of 10 MW 4 -8 -2 17 27 The share of fuel cells used only for power generation exceeds

20% in EU 8 -14 -3

18 11 50% cost reduction of electricity from biomass relative to 2001 -2 -4 -3 19 18 Micro and mini CHP (20-400 kW) accounts for 10% of EU’s

total electricity production from CHP schemes 10 -17 -3

20 13 Widespread use of biomass gasification technologies in EU 2 -12 -5 21 21 The average energy efficiency of micro and mini CHP schemes

will be greater than 80%. 5 -22 -8

The bottom list contains topics with an index lower than –10. Table 4-25: Bottom list

Ran

k

No.

Statement

E in

dex

C in

dex

E&C

inde

x

22 12 Energy crops cover more than half of the total biomass use in EU -14 -14 -14 23 15 The capacity of small hydro power generation (<10MW) will be

increased by 10% (compared to 2001) -2 -27 -15

24 14 Environmental concern about energy crop growth limits the use of biomass

-17 -19 -18

25 20 The number of new installations of micro and mini turbine will peak.

-11 -27 -19

26 16 Growing environmental concern stops the installation of small hydro power generators

-36 -38 -37

27 19 The capacity of new installed micro turbines for CHP applica-tions below 100 kW will exceed the capacity of new installed recuperating engines below 100 kW.

-41 -49 -45

4.3.5 Environment and Cost of Energy

4.3.5.1 Beneficial impact on global environment In Figure 4-11 the topics are presented according to the average index of beneficial impact on global environment. It is calculated based on the total numbers of respondents and weighted values of 100 (High), 0 (Medium), and –100 (Low), respectively.



66

-60

-40

-20

0

20

40

60

1 3 5 7 9 11 13 15 17 19 21 23 25 27

Statement number

Glo

ba

l e

nv

iro

nm

en

t in

de

x

Figure 4-11: Index of beneficial impact on global environment

The top ten of beneficial impact on global environment is presented in the table below. From the list it may be observed that all decentralised energy generation technologies are in-cluded in the top ten list except for CHP and small hydropower generation. Wind power top-ics are at the very top, focusing on the energy coverage of EU’s electricity (No. 2), cost reduc-tion of wind produced electricity (No. 3), and offshore wind farms (No. 27). The second high-est topic regards renewable sources for fuel cells (No. 26), and the third topic regards EU’s power demand covered by renewable sources (No.1). The widespread use of domestic and commercial fuel cells (N0. 22) as well as domestic demand covered by fuel cells in domestic house (No. 24) are ranked number six and eight, respectively. Electricity based on biomass (No. 10) is ranked number seven, and photovoltaics (No. 9 and No. 8) number nine and ten. Table 4-26: Top ten of beneficial impact on global environment

Ran

k

No.

Statement E

inde

x

1 2 10% of Europe’s electricity comes from wind power 52 2 26 30% of fuel cell fuels in EU are derived from renewable sources 45 3 1 10% of Europe’s power demand is covered by energy from renewable

sources 40

4 3 50% cost reduction of wind produced electricity relative to 2001 40 5 5 More than one-third of wind turbine capacity in Europe comes from

offshore sites 27

6 22 Widespread use of domestic and commercial fuel cell units 22 7 10 20% of EU’s electricity is based on biomass 18 8 24 10% of Europe’s domestic power demand is covered by fuel cells lo-

cated in domestic houses 15

9 9 Widespread use of photovoltaics integrated into roof tiles 15 10 8 50% cost reduction of electricity from photovoltaics relative to 2001 10



67

The bottom list comprises topics with an average index below zero. Table 4-27: Bottom list of beneficial impact on global environment

Ran

k

No.

Statement

E in

dex

20 11 50% cost reduction of electricity from biomass relative to 2001 -2 21 15 The capacity of small hydro power generation (<10MW) will be in-

creased by 10% (compared to 2001) -2

22 17 10% of private households in EU have micro CHP units installed -4 23 20 The number of new installations of micro and mini turbine will peak -11 24 12 Energy crops cover more than half of the total biomass use in EU -14 25 14 Environmental concern about energy crop growth limits the use of bio-

mass -17

26 16 Growing environmental concern stops the installation of small hydro power generators

-36

27 19 The capacity of new installed micro turbines for CHP applications be-low 100 kW will exceed the capacity of new installed recuperating en-gines below 100 kW

-41

4.3.5.2 The beneficial impact on cost of energy production In the figure below, the topics are presented according to the average index of beneficial im-pact on cost of energy production. It is calculated based on the total numbers of respondents and weighted values of 100 (High), 0 (Medium), and –100 (Low), respectively.

-60

-40

-20

0

20

40

1 3 5 7 9 11 13 15 17 19 21 23 25 27

Statement number

Co

st

of

en

erg

y i

nd

ex

Figure 4-12: Index of beneficial impact on cost of energy production

The top ten [nine] list comprises the three topics on cost reduction, though differing on the total cost reduction. Topics on photovoltaics (no. 7 and No. 9) have high rankings, not surprisingly due to the implicit economy of scale. In the same field are topics such as fuel cells units with a 40,000 working hour (N0. 23), 20% electricity based on biomass (No. 10), and 10% private micro CHP (No. 10). The new wind turbine concept is also expected to have



68

10% private micro CHP (No. 10). The new wind turbine concept is also expected to have beneficial impact on cost of energy. Table 4-28: Top ten [nine] list of beneficial impact on cost of energy

Ran

k

No.

Statement

C in

dex

1 7 5% of Europe’s electricity comes from photovoltaics 33 2 8 50% cost reduction of electricity from photovoltaics relative to 2001 18 3 25 75% cost reduction produced by stationary fuel cells relative to 2001 18 4 9 Widespread use of photovoltaics integrated into roof tiles 15 5 3 50% cost reduction of wind produced electricity relative to 2001 12 6 23 CHP fuel cell units will reach an expected life time of more than 40,000

working hours 8

7 6 Development of a new revolutionary and competitive wind turbine con-cept

5

8 10 20% of EU’s electricity is based on biomass 2 9 17 10% of private households in EU have micro CHP units installed. 0 As the remaining topics all have an index lower than zero, only the last five topics are in-cluded in the bottom list. Surface to say that the very bottom topic is No. 19 regarding CHP applications below 100 kW, just like the bottom list of the beneficial impact on global envi-ronment. Table 4-29: Bottom list of beneficial impact on cost of energy

Ran

k

No.

Statement

C in

dex

23 21 The average energy efficiency of micro and mini CHP schemes will be greater than 80%.

-22

24 15 The capacity of small hydropower generation (<10MW) will be in-creased by 10% (compared to 2001).

-27

25 20 The number of new installations of micro and mini turbine will peak. -27 26 16 Growing environmental concern stops the installation of small hydro

power generators -38

27 19 The capacity of new installed micro turbines for CHP applications be-low 100 kW will exceed the capacity of new installed recuperating en-gines below 100 kW

-49



69

4.3.6 Period of Occurrence The topics are expected to be realised mainly in the period 2011-2020. The figure below shows that 39% of the topics are expected to be realised in this period, 25% of the topics after 2020, 19% in the period 2006-2010, and 12% are expected never to be realised. Only 4% are expected to be realised before 2005.

05

1015

20

253035

40

45

2001-2005 2006-2010 2011-2020 After 2020 Never

Per

cent

Figure 4-13: Time of occurrence for all decentralised energy topics

The analysis of the responses indicating that the topic will “Never” occur has been conducted on the basis that if the “Never” exceeds 15% of total responses, it is classified as significant. Table 4-30: ”Never” responses

No. Statement Never 12 Energy crops cover more than half of the total biomass use in EU 34% 10 20% of EU’s electricity is based on biomass 30% 11 50% cost reduction of electricity from biomass relative to 2001 23% 14 Environmental concern about energy crop growth limits the use of bio-

mass 23%

16 Growing environmental concern stops the installation of small hydro power generators

23%

6 Development of a new revolutionary and competitive wind turbine con-cept

19%

27 The share of fuel cells used only for power generation exceeds 20% in EU

18%

25 75% cost reduction produced by stationary fuel cells relative to 2001 16% The time of occurrence for each decentralised energy type is shown in the figure below. The majority of energy production types peak in the period 2011-2020, including wind power (45%), CHP (41%), photovoltaics (40%), and biomass (39%). Fuel cells peak after 2020 (42%), while small hydro plants already peak in the period 2006-2010.



70

0

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25

30

35

40

45

50

2001-2005 2006-2010 2011-2020 After 2020 Never

Pe

rce

nt

GeneralWind powerPhotovoltaicsBiomassSmall hydroCHPFuel cells

Figure 4-14: Time of occurrence by energy types

In the following, type occurrence by energy production type is further analysed. Within each energy production type, the time of occurrence is shown for single statements. From the figure below, it can be seen that the majority of experts expect off shore wind tur-bines to peak in the period 2011-2020 (No. 5). More disagreement among experts is related to the development of a new revolutionary wind turbine concept (No. 6), as app. 30% expect it to be realised after 2020 and 1/5 do not expect it to be realised ever.

Wind power

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70

2001-2005

2006-2010

2011-2020

After2020

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Year

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rce

nt

2. 10% of Europe’selectricity comes from windpower

3. 50% cost reduction ofwind produced electricityrelative to 2001

4. Practical use of windturbines at a rated capacityof 10 MW

5. More than one-third ofwind turbine capacity inEurope comes from offshoresites

6. Development of a newrevolutionary andcompetitive wind turbineconcept

Figure 4-15: Time of occurrence for wind power topics

For photovoltaic the time of occurrence is shown in Figure 4-16. The majority of experts do not expect photovoltaics to play a larger role in the production of electricity before 2020 (No. 7). This is interesting as app. 40% of experts expect 50% cost reduction of electricity to come from photovoltaics in 2011-2020 (No. 8).



71

Photovoltaics

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60

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2006-2010

2011-2020

After2020

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t

7. 5% of Europe’selectricity comes fromphotovoltaics

8. 50% cost reduction ofelectricity fromphotovoltaics relative to2001

9. Wide spread use ofphotovoltaics integratedinto roof tiles

Figure 4-16: Time of occurrence for PV topics

Time of occurrence for biomass shows a relatively uniform picture across statements with disagreement among expert regarding time of occurrence. Between 35-40% of experts expect the statement to be realised in the period 2011-2020, while app. 40-50% of expert expect the statements to be realised after 2020 or never.

Biomass

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2011-2020

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e

10. 20% of EU’selectricity is based onbiomass

11. 50% cost reductionof electricity frombiomass relative to 2001

12. Energy crops covermore than half of thetotal biomass use in EU

13. Widespread use ofbiomass gasificationtechnologies in EU

14. Environmentalconcern about energycrop growth limits theuse of biomass

Figure 4-17: Time of occurrence for biomass topics

For small hydro plants, the expectation among experts is in particular high regarding a rela-tively rapid 10% increase in capacity of small hydro power generation (No. 15).



72

Small hydro

05

1015

202530

3540

4550

2001-2005

2006-2010

2011-2020

After2020

Never

Year

Per

cen

tag

e

15. The capacity ofsmall hydro powergeneration (<10MW) willbe increased by 10%(compared to 2001).

16. Growingenvironmental concernstops the installation ofsmall hydro powergenerators

Figure 4-18: Time of occurrence for small hydro topics

The expected time of occurrence for CHP rather uniform across the different statements ex-cept for one, with app. half of experts expecting them to be realised in the period 2011-2020. The outsider is No. 21 regarding an average energy efficiency of >80%. Here 2/3 of experts expect it to be realised in 2001-2010 (No. 21).

CHP

0

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60

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2006-2010

2011-2020

After2020

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Per

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e

17. 10% of private households inEU have micro CHP unitsinstalled.

18. Micro and mini CHP (20-400kW) accounts for 10% of EU’stotal electricity production fromCHP schemes.

19. The capacity of new installedmicro turbines for CHPapplications below 100 kW willexceed the capacity of newinstalled recuperating enginesbelow 100 kW.

20. The number of newinstallations of micro and miniturbine will peak.

21. The average energy efficiencyof micro and mini CHP schemeswill be greater than 80%.

Figure 4-19: Time of occurrence for CHP topics

Time expectations regarding fuel cells are shown below. Expectations are relatively uniform in terms of long term, i.e. after 2011. App. half of experts expect three statements to be real-ised mainly in the period 2011-2020 (No. 22, 23, 25) whereas up to 60% of experts expect another three statements to be realised mainly after 2020 (No. 26, 27, 28).



73

Fuel cells

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60

70

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2006-2010

2011-2020

After2020

Never

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rce

nta

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22. Widespread use ofdomestic and commercial fuelcell units.

23. CHP fuel cell units willreach an expected life time ofmore than 40,000 workinghours.

24. 10% of Europe’s domesticpower demand is covered byfuel cells located in domestichouses

25. 75% cost reductionproduced by stationary fuelcells relative to 2001

26. 30% of fuel cell fuels in EUare derived from renewablesources.

27. The share of fuel cells usedonly for power generationexceeds 20% in EU

Figure 4-20: Time of occurrence for fuel cell topics

4.3.7 Constraints for Realising the Topic The realisation of the topics may be constrained by a number of framework conditions that are central to the development of the topic. Barriers are first and foremost limited to lack of R&D resources (28%), lack of support mechanisms (23%), and spatial planning provision and procedures (16%). Important are also standardisation (10%) and lack of public information (10%), whereas insufficient educa-tion/training skills are perceived as a barrier by only 5%.

0

5

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15

20

25

30

Sp

atia

l p

lan

nin

g

Sta

nd

ard

isa

tio

n

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ck o

f R

&D

Ed

uca

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n/s

kills

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me

ch

an

ism

s

Pu

blic i

nfo

rma

tio

n

Oth

er

Ind

ex -

pe

rce

nt

Figure 4-21: Barriers for realising the topics

Other framework barriers are for example ”No common EU policy” or ”Lack of political commitment” (No. 1, No. 5, No. 10). ”Lack of favourable sites” is mentioned for wind energy



74

(No. 2, No. 3, No. 4) and small hydro plants (No. 15, No. 16). ”Lack of subsidies and imple-mentation programmes” or ”Development of trans-sectoral and co-ordinated supply schemes” are also highlighted (No. 8, No. 11, No. 15). ”Existing national subsidies for nuclear and coal” is highlighted for topic No. 18 on micro and mini CHP percentage of EU’s CHP pro-duced energy. ”Lack of distribution infrastructure” is highlighted for topic No. 26 on fuel cells fuel. Figure 15 shows which barriers matter for each energy type. Lack of R&D resources is per-ceived as a barrier for fuel cells (37%), CHP (29%), wind (28%), photovoltaics (29%), and biomass (26%). Lack of support mechanisms is highlighted as a barrier by photovoltaics (27%), fuel cells (24%), CHP (23%), and small hydro plants (20%). Spatial planning provi-sion and procedures is regarded a barrier for small hydro plants (36%) and wind (23%), whereas lack of public information is highlighted as a barrier for small hydro plants (20%).

0,00

5,00

10,00

15,00

20,00

25,00

30,00

35,00

40,00 GeneralWind powerPhotovoltaicsBiomassSmall hydroCHPFuel cells

Figure 4-22: Barriers for realising the topic by energy type

Taking a closer look on barriers in relation to expert judgements within different energy types, the following can be observed. Within wind energy, the expectation among experts varies in particular regarding the lack of R&D, with 51% of experts regarding it a barrier for the development of a revolutionary new wind turbine concept (No. 6) while only 12% find it a barrier to 10% of Europe’s energy com-ing from wind power (No. 2). Also spatial planning seems to be subject to some varying expectations as app. 1/3 find it a barrier to 10% of Europe’s electricity coming from wind power (No. 2), but only 10% expect it to be a barrier to the revolutionary wind turbine (No. 6).



75

Wind Power

0,0

10,0

20,0

30,0

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50,0

60,0

Spatia

l plan

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Standa

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Per

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2. 10% of Europe’selectricity comes fromwind power

3. 50% cost reduction ofwind producedelectricity relative to2001

4. Practical use of windturbines at a ratedcapacity of 10 MW

5. More than one-third ofwind turbine capacity inEurope comes fromoffshore sites

6. Development of a newrevolutionary andcompetitive wind turbineconcept

Figure 4-23: Barrier for wind power topics

Photovoltaics is subject to some disagreements among experts when it comes to lack of R&D as 40% of experts find it a barrier for realising a 50% cost reduction (No. (8), but only 16% find it a barrier for realising widespread use of photovoltaics integrated into roof tiles (No. 9). On the contrary, app. 25-30% of experts agree that lack of support mechanisms is a major barrier.

Photovoltaics

0,0

5,0

10,0

15,0

20,0

25,0

30,0

35,0

40,0

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en

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e

7. 5% of Europe’selectricity comes fromphotovoltaics

8. 50% cost reduction ofelectricity fromphotovoltaics relative to2001

9. Wide spread use ofphotovoltaics integratedinto roof tiles

Figure 4-24: Barriers for PV topics

For biomass, the situation is that experts disagree largely on lack of R&D where app. 40% expect it to be a major constrain regarding 50% cost reduction (No. 11) and widespread use of biomass gasification (No. 13) while not more than 14% expect it to be a constraint for topics such as energy crops (No. 12 and 14). Likewise there is different expectation to spatial plan-ning. 32% of experts expect it to be a barrier to environmental concern about energy crops (No. 14), but only 9% as a barrier to cost reduction (No. 11). In particular, the topic of envi-



76

ronmental concern about energy crops (No. 14) differs from that of the other topics: it is rated relatively low by experts re. lack of support mechanisms , but high regarding lack of infor-mation.

Biomass

0,0

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ther

Perc

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tag

e

10. 20% of EU’s electricityis based on biomass

11. 50% cost reduction ofelectricity from biomassrelative to 2001

12. Energy crops covermore than half of the totalbiomass use in EU

13. Widespread use ofbiomass gasificationtechnologies in EU

14. Environmental concernabout energy crop growthlimits the use of biomass

Figure 4-25: Barriers for biomass topics

Barriers for the realisation of small hydropower are mainly related to spatial planning ac-cording to app. 1/3 of experts No. 15 & 16). Regarding lack of support mechanisms this is primarily the case for the increase of capacity (No. 15), whereas lack of information is re-lated to environmental concern (No. 16).

Small Hydro

0,0

5,0

10,0

15,0

20,0

25,0

30,0

35,0

40,0

45,0

Spatia

l plan

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15. The capacity of smallhydro power generation(<10MW) will be increasedby 10% (compared to2001).

16. Growingenvironmental concernstops the installation ofsmall hydro powergenerators

Figure 4-26: Barriers to small hydro power topics

The expected barriers regarding CHP are lack of R&D though with a gap between 46% of experts rating a topic such energy efficiency larger than 80% (No. 21) and only 20% of ex-perts rating micro/mini CHP accounting for 10% of EU’s CHP produced electricity (No. 18).



77

CHP

0,0

5,0

10,0

15,0

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25,0

30,0

35,0

40,0

45,0

50,0

Spatia

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f R&D

Educa

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Suppo

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Other

Pe

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17. 10% of private households inEU have micro CHP unitsinstalled

18. Micro and mini CHP (20-400kW) accounts for 10% of EU’stotal electricity production fromCHP schemes

19. The capacity of new installedmicro turbines for CHPapplications below 100 kW willexceed the capacity of newinstalled recuperating enginesbelow 100 kW

20. The number of newinstallations of micro and miniturbine will peak

21. The average energyefficiency of micro and miniCHP schemes will be greaterthan 80%

Figure 4-27: Barriers to CHP topics

When it comes to fuel cells the barriers are mainly considered to be lack of R&D, but again with some difference between topics: 57% point to this barrier in relation to CHP fuel cell units with long life time (No. 23) but no more than 26% point to the barrier when it comes to 10% of domestic power covered by domestic fuel cells (No. 24). A more uniform expectation is made regarding the lack of support mechanisms (between 20-27% of all experts covering all CHP topics).

Fuel cells

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22. Widespread use ofdomestic and commercialfuel cell units.

23. CHP fuel cell units willreach an expected lifetime of more than 40,000working hours.

24. 10% of Europe’sdomestic power demandis covered by fuel cellslocated in domestichouses

25. 75% cost reductionproduced by stationaryfuel cells relative to 2001

26. 30% of fuel cell fuelsin EU are derived fromrenewable sources.

27. The share of fuel cellsused only for powergeneration exceeds 20%in EU

Figure 4-28: Barriers to Fuel Cell topics



78

4.3.8 Other Comments of Survey Respondents Other comments made by respondents are: • Determining factors to increase the DGs are: the energy price level, and the liberalisation

of the energy market. • The current trend to liberalisation of energy markets will promote the use of cheapest

means of generating electricity and heat. This hinders the development and widespread in-troduction of new technologies such as fuel cells and micro turbines. Active R&D and implementation support (subsidies, tax rebates etc.) are necessary to overcome this cost hurdle, in order to benefit from the inherent advantages: CO2, NOx, SO2, particulate mat-ter, VOC, -emission reduction potentials.

• DG is the model permitting all consumers to produce electricity with the technology or energy resource they can afford or prefer for social or environmental reasons. What is missing is the legislative frame, standardisation, no discrimination from the grid monopo-lies or the utilities. In other words, the ideology of a different electric system, decentral-ised.

• The electricity grid in Europe is in general not designed to handle the new demands on integrating large numbers of small generation. New planning tools for network integration have to be developed.

• When implementing micro and mini CHP in households and industries, it is crucial to focus on energy savings as well.

• Offshore wind should concentrate on new development (e.g. floating turbines) rather than using adapted land-turbines.

DECENT Final Report Liberalisation and Decentralised Generation in the EU Member States


79

5 Liberalisation and Decentralised Generation in the EU Mem-ber States

5.1 Status of Electricity Market Liberalisation in the EU Member States

5.1.1 The Directive on Liberalisation of the Electricity Market On 19 February 1997, the Directive 96/92/EC on the Internal Market in Electricity entered into force. Each Member State had 2 years to adapt it into national legislation. After the Di-rective on price transparency (90/377/EG) from 29.6.1990 (for electricity and gas) and the one on electricity transit (90/547/EG) from 20.10.1990, this Directive marks a further step to the liberalisation of the electricity sector in the European Union. However, the Electricity Directive is (as well as the Gas Directive) subject to an amendment that has been discussed for several years: • In March 2001, the Commission has worked out a set of proposals of new instruments for

a completion of the internal energy market27. • The European Parliament has adopted a large number of amendments to the COM pro-

posal in March 200228. • As a reaction to the EP’s wishes for amendments, the Commission has issued and

amended proposal in June 200229. As the Electricity Directive and its transposition into national law is a moving target to any comprehensive study, in the following the liberalisation status of 2000 is depicted: The (unamended) Directive in force establishes common rules for the generation, transmis-sion and distribution of electricity. It lays down the rules relating to the organisation and func-tioning of the electricity sector, notably :

• access to the market,

27 Proposal COM(2001) 125 final of 13 March 2001 for a Directive of the European Parliament and of the

Council amending Directives 96/92/EC and 98/30/EC concerning common rules for the internal market in electricity and natural gas and Proposal COM(2001) 125 final of 13 March 2001 for a Regulation of the European Parliament and of the Council on conditions for access to the network for cross-border exchanges in electricity

28 P5_TAPROV(2002)0106, adopted at the EP Sitting of 13 March 2002

29 Amended proposal for a DIRECTIVE OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL amending Directives 96/92/EC and 98/30/EC concerning rules for the internal markets in electricity and natu-ral gas and Amended proposal for a REGULATION OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL on conditions for access to the network for cross-border exchanges in electricity COM(2002) 304 final of 7 June 2002



80

• the criteria and procedures applicable to calls for tender and the granting of authorisations • the operation of systems. The Directive indicates the minimum goals to be achieved : • In February 1999, the national market share that should have been opened to competition

was to be calculated on the basis of the Community share of electricity consumed by final customers consuming more than 40 GWh per year. The resulting average Community mar-ket opening was 23%.

• The share of the national market is increased over time. In 2000 the Community consump-tion threshold was reduced from 40 GWh to 20 GWh annual electricity consumption and in 2003 it will be further reduced to 9 GWh.

Member States specify those customers inside their territory which have the legal capacity to contract electricity, given as minimum that all final consumers consuming more than 100 GWh per year must be included in the above category. These customers are called "eligi-ble customers". Distribution companies, if not already specified as eligible customers, shall have the legal capacity to contract for the volume of electricity being consumed by their customers desig-nated as eligible within their distribution system, in order to supply those customers. In March 2000, four European Member States had their electricity market fully open: Sweden, Finland, Germany and United Kingdom. Denmark has almost opened it entirely (90%). Belgium, Greece and Ireland have had, due to the specific technical characteristics of their electricity systems, an additional period of respectively 1, 2 and 1 year to apply the obliga-tions ensuing from the Directive. Greece still has a closed electricity market, and Belgium and Ireland started to open up their market on 19th February 2000 by 33 and 30% respectively. France has chosen for a minimal liberalisation, with almost a year of delay. It opened its mar-ket as late as in January 2000, to a rate of 30%. The other Member States have different market opening levels ranging from 30 to 45%. (Aus-tria : 30%, Italy 35%, Portugal 30%, The Netherlands 32%, Spain 42%). Access to the network For the organisation of the network access, Member States can choose between three proce-dures :

• the negotiated access (nTPA), • the regulated access (rTPA) • the Single buyer procedure (SB). In the case of negotiated access to the network, Member States take the necessary measures to ensure that electricity producers and, where Member States authorise their existence, electric-ity suppliers, together with eligible customers either inside or outside the territory covered by the system, are able to negotiate access to the system so as to conclude supply contracts with each other on the basis of voluntary commercial agreements. In order to promote transparency and facilitate negotiations for access to the network, system operators must publish an indicative range of prices for use of the transmission and distribu-



81

tion systems. As far as possible, the indicative prices published for subsequent years should be based on the average price agreed in negotiations in the previous 12-month period. In the case of regulated access systems, Member States give eligible customers a right of ac-cess, on the basis of published tariffs for the use of transmission and distribution systems. A negotiated third party network access only exists in Germany, where the grid access was structured along a series of Associations Agreements . All other member States have chosen the regulated third party access system. Unbundling The Directive requires that, unless the transmission system is already independent from gen-eration and distribution activities, the system operator has to be independent at least in management terms from other activities not relating to the transmission system. If the company is vertically integrated, Member States must insure that the transmission net-work managers do not transmit confidential information to the other sectors of the company. Most of the Member States have a transmission network that is a separate legal entity : Spain, United-Kingdom (England and Wales), Sweden, Finland, Denmark (peninsula Jutland), Aus-tria (Eastern Austria), The Netherlands, Portugal, Ireland, Greece, Italy. Only a minority of Countries have a transmission network that is part of vertically integrated companies : Denmark (other than Jutland), Germany, France, United Kingdom (Scotland, Northern Ireland), Austria (Western Austria). In their internal accounting, integrated electricity undertakings have to keep separate accounts for their generation, transmission and distribution activities. This is required with a view to avoid discrimination, cross-subsidisation and distortion of competition. They have to include a balance sheet and a profit and loss account for each activity in notes to their accounts. Public service obligations Member States may impose on undertakings operating in the electricity sector, in the general economic interest, public service obligations which may relate to security, including security of supply, regularity, quality and price of supplies and to environmental protection. Such ob-ligations must be clearly defined, transparent, non-discriminatory and verifiable. Independent regulatory authority Except in Germany, in Austria and in Ireland, the regulation functions are – or will be in short term – delegated to an independent body. Opening of the Market Most Member States are opening their electricity market broader and faster than what is re-quired by the Directive. In average the market opening rate was already 60% at the "start-day" of the liberalisation, the 19th of February 1999.



82

Reciprocity According to Article 19.5, reciprocity may be a reason for refusal of network access, but only during a transitional period of 9 years. The case can apply when different levels of market opening are implemented by some Mem-ber States and an eligible customers that wants to contract electricity from a supplier from another Member State, would not have the status of an eligible customer in that other Member State. The following states have overtaken in their national law a reciprocity clause: Austria, Bel-gium, Germany, the Netherlands, Portugal, Spain and The United Kingdom.



83

5.1.2 Overview on Member States The following tables give an overview on the liberalisation of the electricity markets in the EU Member States (as of 2001). Table 5-1: Overview on Liberalisation Status of EU Member States (I)

Country Dispatch Priority Market Opening 2001

Threshold Third Party Access

Austria - RES 32% 20 GWh/year, in Feb 2000

rTPA

Belgium - RES - CHP - Auto-producers

33% 100 GWh/year - nTPA international - rTPA for domestic transit

Denmark - RES - CHP - Waste

90% 10 GWh/year from Apr 2000

- nTPA international - rTPA for domestic transit

Finland None Full None rTPA France - RES 30% 20 GWh/year rTPA

Germany - CHP - RES

Full None - nTPA

Greece - CHP - RES - Lignite

30% 1.5 GWh/year in 2001

- rTPA - Single buyer for islands

Ireland - RES 30% 4 GWh/year - rTPA Italy - CHP

- RES 35% 20 GWh/year - SB for franchised market

- rTPA f. open market Luxem-bourg

- CHP - RES

40% 100 GWh/year rTPA

Nether-lands

- RES( = 8MW) - CHP + Small installa-tions ( = 2MW)

32% 2 MW rTPA

Portugal - CHP - RES

30% 30 GWh/year - SB: REN for franchised market

- nTPA when grid rein-forcements

- rTPA: other cases Spain - CHP

- RES 53% July 2000: 1

kV rTPA

Sweden None Full None rTPA UK None Full None rTPA

Sources: Eurelectric, European Commission, own information



84

Table 5-2: Overview on Liberalisation Status of EU Member States (II)

Country TSO Transmission Charges

Unbundling of TSO

Supply Unbun-dling

Austria Concession - Management Belgium Subsidiary of existing

companies (ELIA) - legal

Denmark West: Eltra East: Elkraft

Postage stamp - ownership

Finland Fingrid Postage stamp - ownership - Accounts France An independent part

of EDF. State owned Postage stamp - management

Germany Several Postage stamp - management - Full Greece Independent Body.

51% State owned - ownership - Accounts

Ireland New state owned company

- legal

Italy Independent Body Postage stamp with distance correction

- ownership

Luxem-bourg

- legal

Nether-lands

TenneT Postage stamp and point tariff

- ownership

Portugal REN Postage stamp - legal Spain REE Postage stamp - ownership - Full Sweden Svenska Kraftnät:

100% state owned Nodal tariff with geographical dif-ference

- ownership - Full

UK National Grid Com-pany; Scottish Power; Scottish & Southern Energy; Northern Ire-land Electricity

Connection charges and zonal use-of-system charges

- ownership - Full

Sources: Eurelectric, European Commission, own information



85

5.2 Use of Renewables According to the Kyoto protocol the European Union has agreed on a common greenhouse gas (GHG) reduction of 8% by the years 2008-12 compared with 1990. It is reflected in the EU policies as well that the development of renewable energy resources is expected to play an important role in the implementation of these GHG-targets. In its White Paper on a strategy for the development of renewable energy the EU-Commission has launched a goal of cover-ing 12% of the European Union’s gross inland energy consumption by the year 2010 by re-newable sources, that is mainly by biomass, hydro power, wind energy and solar energy. Next to biomass wind energy is foreseen to be the main contributor with regard to future impor-tance30. Recently the European Commission has agreed on a directive on the promotion of renewable energy technologies31, including a proposal on the share of renewables in the indi-vidual member states in 2010, based on the percentage of each country’s consumption of elec-tricity. Although not binding it seems that these targets by now are accepted by the EU mem-ber states. Thus the directive signals the need to include renewable energy technologies as one of the serious options in achieving the targets for GHG-reductions. At present most renewable energy technologies are not economic competitive to conventional power producing plants. Thus it can be expected that if renewables must compete on pure market conditions this will halt the development of new renewable capacity. One model of generating additional payments to renewable technologies is to develop a separate green mar-ket. This model will facilitate the integration of renewables into the liberalised market and at the same time making it possible for these technologies partly to be economically compen-sated for the environmental benefits, that they generate compared to conventional power pro-duction. The Netherlands were the first country to explore the possibilities of the green market. A vol-untary green certificate market, called the Green Label, was started in January 1998 with the main objective of increasing the penetration of renewable electricity production into the elec-tricity market by stimulating demand32. In Denmark a green market to a certain extent compa-rable to the Dutch is on the way. As part of a comprehensive electricity reform the Danish Parliament has decided on the development of a separate green certificate market for renew-able generated electricity33. A number of other EU member states are moving in the same directions, including Italy, England and Belgium. However, there is no agreement within the EU area of developing a common green market for renewables. Germany has chosen to con-

30 European Commission: Energy for the future: Renewable sources of energy. (White Paper, 26/11/97).

31 European Commission, December 2000: Proposal for a directive of the European parliament and of the coun-cil on the promotion of electricity from renewable energy sources in the internal electricity market.

32 The Dutch system is in more detail described in: Voogt, M.; Boots, M.; Schaeffer, G.J.; Martens, J.W.: Re-newable electricity in a liberalised Dutch electricity market – the concept of green certificates. In: Design of Energy markets and Environment, Conference papers, Copenhagen 20-21 May, 1999, Nordic Energy Research Program.

33 The Danish system is described in: Morthorst, P.E.: The development of a green certificate market. Energy Policy, November 2000, vol. 28/15, p. 1085-1094.



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tinue with the well proven feed-in tariff system and after the Commission has finally accepted the support scheme as not constituting a state aid, France chose to move in the same direction.

5.2.1 Motivations for RES-support The main objective of an energy policy favouring renewable energies is to move towards a sustainable, environmentally sound energy supply. Indeed, renewable energy sources (RES) emit no, or reduce drastically, gaseous emissions such as CO2, NOx and SOx. The Kyoto protocol obliges the European Union Member States to reduce greenhouse gas emissions by 8% of their 1990 levels in the commitment period 2008 to 2012. RES constitutes an important element of the package of measures needed if the European Union is to reach this target. Supporting the RES will give an impetus to the European RES-industry. Export of European renewable energy technologies will contribute positively to the European Union’s trade bal-ance. Social and economic cohesion also play a role. RES have considerable advantages for isolated regions which are not sufficiently or are not at all connected to the grid. Some RES are a labour intensive form of industry and create jobs, especially at location sites in rural ar-eas. This is especially the case for biomass.

5.2.2 Type of Support There is a high diversity regarding strategies and tools for RES promotion. However, a gen-eral trend may be identified34: The first stage of RES promotion was generally characterised by support for Research, Development and Demonstration, which continues to play an impor-tant role, now focusing on key technologies, e.g. photovoltaics. In a second stage, it was com-plemented by promotional activities aiming at creating a "critical mass" for a dynamic market development. Stable, favourable framework conditions, reflecting the environmental and so-cial benefits of RES are characteristic for this stage. Most recently, promotional systems (al-ready applied or under discussion) emphasise market elements (competition, fiscal incentives) and indicate a third promotional stage. "Indirect" support measures, mainly favourable electricity feed-in tariffs and low-interest loans have risen considerably in recent years, becoming considerably more important than "direct" support tools (grants, subsidies..). As the most recent, and more market oriented measure, green certificate/quota systems have been introduced (Netherlands), which oblige distributors (or customers) to guarantee a minimum quota of RES-E certificates for their port-folio (or consumption) and thus create an market for an additional income to RES-E produc-ers. There is a wide range of renewable energy technologies : some provide electricity, others heat; some are small scaled and decentralised, other are in the multi-MW-range; some are economically competitive, other still need additional support; some are "classical", others are

34 Cf. APERe: “Analysis of the Support Policy in European Union Member States for Renewable Energy”,

EU-Japan Centre for Industrial Cooperation, 2000



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in an experimental stage. This diversity needs flexible, "tailor-made" promotional instru-ments. To do so, different forms of support are possible. The main support schemes are35: • Subsidies for research and development • Capital investment or loans to investments • Guaranteed prices coupled with a purchase obligation by the utilities : The level of the

guaranteed prices vary considerably from country to country with, on average, regulation in Germany, Denmark, Spain and Italy offering the highest prices to RES-E producers

• Tendering system : Under this approach, the State decides on the desired level of RES, according to the source mix (wind, biomass, solar, waste, etc.) that public policy dictates. It then places a series of tenders for the supply of the electricity, which would thereafter be supplied on a contract basis. The electricity is then sold by the authority responsible for or-ganising price through a non-discriminatory levy on all domestic electricity consumption.

• quota/green certificate system: As in the tendering system, the State decides on the desired share of RES-E. The quota can be imposed to electricity distributors or consumers. While the trading of physical power is carried traditionally, the power distributor/consumer will need to buy green certificates according to their power consumption and the quota. The green certificates are handed out to producers of RES-E according to their production, and thus create an additional income stream to the producers, while the physical power is traded at market conditions.

• Voluntary green pricing schemes : Consumers can voluntary opt to pay a premium for re-newable electricity. The consumers pay part or full extra costs that the generation of RES-E entails.

• Standard/consent procedures and regulation in building codes and design guidelines : ob-jective reducing or streamlining planning barriers. The obligatory designation by local au-thorities of eligible zones for RES-development, for example, (as in Denmark) also facili-tates renewable growth.

• Support via the tax system : • exemption forms or refunds of energy taxes where they exist (Finland where the

electricity tax is reimbursed, Denmark where the CO2-tax is reimbursed, Sweden where an environmental bonus is given to wind power producers)

• lower VAT rates on some RES-systems, like solar energy system in Portugal • tax exemptions for investments in small scale RES-E

• introduction of SO2 and NOx taxes as in Denmark and Sweden which especially fa-vours the development of wind and hydro power.

An overview on mainly used support mechanisms is given in the following table which sum-marised the situation in 2000/2001. However, the situation concerning renewables support systems is changing rapidly throughout Europe.

35 cf. Cf. APERe: “Analysis of the Support Policy in European Union Member States for Renewable En-

ergy”, EU-Japan Centre for Industrial Cooperation, 2000



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Table 5-3: Support systems for electricity from renewable energy sources in the EU

Country RES support

Austria Small hydro: quota/certificate (8% quota) other renewables: feed-in tariffs varying between federal states; in addition, direct investment subsidies are possible

Belgium Feed-in tariffs, tax incentives, investment subsidies in Flanders green certificates are planned

Denmark Feed-in tariffs / switch to green certificates

Finland Investment subsidies

France Feed-in tariffs, tax incentives

Germany Fixed feed-in tariffs guaranteed for 20 years lifetime In addition favourable loans from public banks

Greece Feed-in tariffs for 10 years, subsidies

Ireland Competitive tender/quota

Italy Feed-in tariffs, investment subsidies, quota/certificate planned

Luxembourg Feed-in tariffs, production subsidies, investment subsidies

Netherlands Green Certificate (2001), feed-in tariffs, investment subsidies

Portugal Feed-in tariffs, investment subsidies

Spain Feed-in tariffs, investment subsidies

Sweden Feed-in tariffs (<1,5 MW), certificate/quota planned for 2003

UK Competitive tender/quota, certificate/quota planned for 2003

Sources: DG Bank, 2000; European Commission, 2001

The actual use renewable energy sources for electricity production varies highly between EU Member states. By far the largest share is generally generated by the use of hydro-power. Thus the share of renewable energies mainly depends on the natural hydro-resources. In some countries biomass (e.g. Austria, Scandinavia) and wind power (Denmark) already play a sig-nificant role.



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Table 5-4: Share of Renewable Energy Sources in Gross Inland Energy Consumption

Country 1990 1995 1995 excluding hydro >10 MW

Austria 22.1 % 24.3 % 8,7% Belgium 1.0 % 1.0 % 0,9% Denmark 6.3 % 7.3 % 6,3% Finland 18.9 % 21.3 % 9,2% France 6.4 % 7.1 % 2,2% Germany 1.7 % 1.8 % 2,3% Greece 7.1 % 7.3 % 0,4% Ireland 1.6 % 2.0 % 1,1% Italy 5.3 % 5.5 % 4,7% Luxembourg 1.3 % 1.4 % 1,6% Netherlands 1.3 % 1.4 % 2,7% Portugal 17.6 % 15.7 % 4,7% Spain 6.7 % 5.7 % 4,0% Sweden 24.7 % 25.4 % 5,3% United Kingdom 0.5 % 0.7 % 0,7% European Union 5.0 % 5.3 % 3,0% Source: Eurostat

The distribution between the different renewable energy sources is depicted in the following graph:

Source: DG Energy / EEA “Environmental signals 2000 — Environmental assessment report No 6”

Figure 5-1: Renewables' share of electricity generation in EU Member States, 1996



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5.3 Use of CHP The CHP share of total electricity production varies greatly between European Union Member States. Very low shares of less than 5% can be found in Ireland, France and Belgium, whilst in countries such as Denmark, the Netherlands, Finland or Austria significant CHP segments covering up to half (in Denmark) of the total electricity production could develop. A number of reasons can explain this diversity in CHP penetration, e.g. varying heat load re-quirements of the specific national mix of industries, housing and settlement infrastructures such as existing district heating systems, the structure of the electricity and gas markets, or variations in climate conditions. In addition, policy choices in different member states have been largely instrumental in creating favourable political, administrative, financial and regula-tory conditions for CHP in some countries, whilst important barriers have formed in others.

5.3.1 CHP Policies In 1997, the European Commission published its Communication on a Community strategy to promote CHP and to dismantle barriers to its development36. This document called for a dou-bling of the EU-wide share of CHP between 1994 and 2010 in the 15 EU existing countries, i.e. from 9% to 18% of total EU electricity generation. However, this is a non-binding target without any obligation for Member States. At the same time, the communication refers to studies suggesting the maximum technical electricity production CHP potential in the EU could even reach up to 40 % of total generation in 1994. It also argues that CHP could save on average 500 kg CO2 per MWh when compared with the separate production of electricity and heat. Full use of the technical CHP potential might thus save up to 9% of the EU-total CO2 production in 2010. This is especially interesting in the light of the Kyoto Protocol and its CO2 reduction commitments of EU Member States. There is an ongoing trend towards natural gas as principal fuel for CHP installations due to its increasing availability, environmental benefits, and market penetration of gas turbines, gas engines, and in the forthcoming years probably gas-fuelled micro turbines and fuel cells. A key factor with regard to the current situation and further development of CHP in EU Member States is the liberalisation of the electricity and gas markets. Whilst in the long run liberalised energy markets are expected to help CHP realise its full potential, the transition period is often bad. Partial and imperfect market opening has put the CHP market on ice, led to a downturn in sales of CHP equipment, and predatory pricing policies caused even the clo-sure of units in some cases, e.g. in Germany. Mounting gas prices and dropping electricity prices in the period between 1999 and 2000 weakened CHP economies in most Member States. In addition, ongoing legislative reforms and restructuring of the electricity and gas markets are causing uncertainty about the future prospects for CHP, leading to a “wait and see” attitude of potential investors and CHP producers. These and other obstacles to positive development in the CHP sector have been classified as follows: • Economic barriers

36 European Commission (1997) A Community strategy to promote combined heat and power (CHP) and to

dismantle barriers to its development. Communication from the Commission to the Council and the European Parliament. COM(97)514 final



91

These include unreasonably low rates at which CHP generators can sell electricity to the grid, high back-up tariffs, high fuel prices, unpredictability of price developments, a num-ber of obstacles in financing CHP plants, prices which do not reflect the environmental benefits of CHP etc.

• Regulatory barriers These include licensing procedures, planning regulations, unsuitable emission control schemes for small-scale CHP etc.

• Institutional barriers These include attitudes of grid operators to the connection of the CHP unit etc.

On the other hand, ongoing regulatory changes in the context of EU electricity market liber-alisation, combined with increasing pressure to reduce CO2 emissions, have also been used to establish support mechanisms for CHP. Most countries also used this opportunity to introduce some kind legal definition of CHP, e.g. on the grounds of efficiency criteria. More planning security and assistance for CHP are therefore likely in the future.

Source: Combined Heat and Power production (CHP) in the EU. Summary of statistics 1994 – 1998, Eurostat Figure 5-2: Approximate CHP share of total electricity production in EU Member States

in 1998

5.3.2 CHP Support Schemes in the EU Member States The following paragraphs describe in a nutshell the current use of CHP and national support mechanisms in all EU countries except Luxembourg37. These indications have to be inter-preted with caution, as different data and statistical methods are used in different countries, and because the regulatory situation is developing rapidly.

37 In Luxembourg CHP amounts to 58% of domestic electricity production. Yet, 95% of electricity is imported

and thus generated under different conditions.

0

10

20

30

40

50

60

70

Denmar

k

Nether

lands

Finlan

d

Austri

aIta

ly

Portug

al

Spain

German

y

Sweden

United

King

dom

Irelan

d

Belgium

Greec

e

Franc

e



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Table 5-5: CHP Support Systems in the EU Member States C

ount

ry

CHP Statistics Support mechanisms & further information

Aus

tria

26,5 % of the total and 77% of the thermal electricity produc-tion38 is based on CHP, mainly in the district heating and in-dustrial CHP sector.

Purchase obligation of CHP electricity if heat is used for pub-lic heat supply (= no industrial and small-scale CHP), and if certain efficiency and environmental criteria are met; possibil-ity to prioritise authorisation of new CHP plants; network ac-cess can be refused if the new capacity would replace CHP electricity; subsidies for construction of CHP plants according to their fuel (biomass 30%, gas 10%) and for the connection to district heating systems; creation of a renewable energy market under consideration.

Bel

gium

CHP electricity production corresponded to 3.5% of the total electricity generation; approximately 80% of this capacity is installed in the Flemish region, where horti-culture and industry were the sectors accounting for the big-gest share of; residential use is insignificant.

Promotional policies normally limited to “quality CHP" (de-fined differently in different regions); immediate market open-ing for quality CHP producers and buyers; current Electricity Act allows to set minimum feed-in tariffs for electricity gener-ated by CHP; subsidies to investment in CHP units which are fiscally deductible; subsidies for feasibility studies; “green electricity” subject to promotional measures, notably a trading scheme based on green certificates; yet, quality CHP consid-ered green electricity only in part of the country; direct subsi-dies per kWh CHP electricity possible as an alternatively to green certificates.

Den

mar

k

Approximately 50% of the electricity production is cov-ered by CHP; existing CHP units include large scale and small-scale CHP with district heating, and industrial CHP.

Whole range of policy tools and mechanisms to promote CHP in Denmark, including: • legislation enacts purchase obligations of both distributors

and final consumers of CHP electricity at fair prices; price guarantee for sales of CHP electricity;

• voluntary agreements between the government and the energy sector;

• local energy planning according to the Heat Supply Act; the Act allows the imposition of, and mandatory connec-tion to, district heating systems;

• economic instruments such as carbon tax; CO2 quota and a green certificates trading system; complex eco-tax system which aims to encourage CHP and renewables; direct tax subsidies on CHP electricity; aid packages for troubled small-scale CHP producers.

Fin

land

CHP provides about 32% of total national electricity de-mand and 75% of heat de-mand, primarily used for dis-trict heating and industrial applications.

No explicit supportive policies, rather absence of barriers, high demand for heat, and possibly higher acceptance towards long payback times; electricity market is completely liberalised; subsidies for new technologies and biomass power plants up to 30% of the investment; however, current tax policies discour-age CHP heat generation.

38 66% of total electricity production in Austria is hydropower



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Cou

ntry


Fra

nce

CHP supplies less than 3% of electricity in France, mainly in large-scale industries, plus some district heating. There is much over-capacity in the electricity sector and an ex-tremely high share of nuclear power.

Market liberalisation lagging behind other EU Member States; since 1997 purchasing obligation of CHP electricity and fiscal incentives such as tax relief on gas, lower business rates, ac-celerated depreciation and subsidies for studies; in 2000, rising gas prices and blockages in the legislative reform process of the electricity sector leading to a stalemate in the CHP sector; pricing conditions for CHP electricity were unfavourable.

Ger

man

y

CHP covers approximately 10-12% of total electrical capac-ity, evenly divided between the industrial use and district heat-ing; mainly gas- or coal-fuelled; severe pressure from existing overcapacities in 2000/2001 and closure of many plants.

CHP protection law from 2000 introduced purchase obligation of CHP electricity at fixed prices, however, only in relation to municipal district heating schemes; eco-tax law includes elec-tricity tax exemption of CHP producers <2 MWe and mineral oil tax exemption for gas-fuelled plants under 700 kWe; fixed favourable feed-in tariffs for electricity from small CHP units using renewable energy sources; probably new CHP law in 2002 introducing mandatory connection of CHP plants to the grid, payment of a supplementary fee on top of the normal feed-back tariff; mandatory purchase of CHP electricity by grid operators.

Gre

ece

CHP supplies about 2.5% of electricity, mainly in the indus-trial sector. But also some district heating is present in the north of the country. A gas network is under development.

Grants for investments in CHP installations through national and European programmes, normally covering 35% (gas) or 45% (biomass) of the total investment; special gas prices for industrial CHP producers announced; arduous authorisation and licensing procedures and technical interconnection prob-lems, particularly in remote regions.

Irel

and

By the end of 1999 CHP de-livered approximately 3% of the total electrical production. Industrial applications domi-nate the picture, but there is also some commercial and public sector CHP. Natural gas, LPG, peat and hard coal are used as fuels.

The government set out definite CO2 reduction targets attribut-able to CHP.

Ital

y

Annual electricity demand covered by CHP is about 13 – 15 %. CHP is mainly natural gas fired. Industrial sector applications are more impor-tant than district heating or smaller public or private schemes.

low tax rates on gas used for district heating; tax reductions on gas for industrial CHP schemes proportionally to their electric efficiency; carbon tax exemption for CHP; dispatch priority for CHP in the transmission network; ongoing reforms and liberalisation had negative consequences for the CHP market so far.



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Cou

ntry


Net

herl

ands

CHP accounts for about 40% of annual electricity capacity, mostly in the industrial sector. Also, district heating and small-scale CHP have consid-erable shares. 99% of CHP is natural gas fired, 1% biomass or oil. The situation of CHP has deteriorated drastically in 1999/2000 in the wake of en-ergy market liberalisation.

Unofficial national long-term target on CHP capacity of 15,000 MWe by 2010; fuel (gas) tax exemption for fuel used to generate CHP electricity; investment into highly-efficient CHP units partly fiscally deductible; eco-tax exemption for heat supplied by CHP; low interest rates for green investment, e.g. district heating networks; unlike in many other countries, dis-tribution companies have been involved in CHP development and were instrumental in promoting it. CHP development is stopped now due to liberalisation process and very low im-ported electricity prices.

Por

tuga

l

CHP has a share of approxi-mately 12-14% of the national electricity production. CHP is mostly present in the industrial sector, and mostly oil-fuelled. Further growth in gas-fuelled applications is expected as the national gas grid is under de-velopment.

A specific Decree Law on CHP approved in late 1999 sets out a very comprehensive, all-inclusive framework for CHP. It includes: environmental benefits into the feed-in tariffs for CHP electricity; enhanced possibilities for CHP producers to supply third parties with electricity; and more transparency and equal treatment with regard to grid connections. Govern-ment grants and favourable loan rates for installation of CHP units available.

Spai

n

Approximately 12% of elec-tricity production is CHP, mostly generated in the indus-trial sector. Only 4.7% corre-sponds to the service sector, and there is no district heating. Natural gas fuels half of the installations, followed by fuel oil. Electricity output from CHP probably dropped during the second half of 2000.

Special regime for new CHP units meeting certain criteria introduced in 1998 containing mutual obligations of CHP pro-ducers and distribution companies; some IDAE (Institute for Energy Saving and Diversification) funding for small-scale CHP installations available; plants above 50MWe not eligible for any support.

Sw

eden

CHP represents about 6% of total electricity production, mostly district heating and industrial. White liqueur, coal and wood are the key fuels, whilst natural gas is only available in some parts of the country.

Low CHP share is not the result of regulatory obstacles but rather of abundance of low-priced electricity; few existing CHP plants actually sell electricity to the grid; more than 90% of electricity is hydro or nuclear power; small producers up to 1,5 MWe have to be connected to the grid and a network credit has to be paid; investment into biomass CHP installations eli-gible for grants.

UK

CHP accounts for about 5% of total electricity production. Large-scale industrial installa-tions dominate in respect of capacity but not of numbers. Natural gas is now the domi-nant fuel, accounting for 55% of fuel consumed in CHP plants.

Completely liberalised markets in the UK have provided a major market opportunity for the development of CHP; capital grants under the Small Scale CHP Programme (< 1MW); CHP Feasibility Programme grants cover up to 75% of the cost of a detailed feasibility study for projects of 1-20 MWe in size for urban community heating and industry; CHP eligible for sup-port under the Energy Efficiency Standards of Performance (EESOP); Climate Change Levy (CCL) rates and conditions favour CHP, e.g. all CHP will be exempt from levy payments on input fuels and heat outputs; exemption for CHP from busi-ness ratings.

Source: COGEN Europe, Eurostat

DECENT Final Report Scenarios: Europe’s DG Power Generation in the Year 2020


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6 Scenarios: Europe’s DG Power Generation in the Year 2020 As a part of the DECENT futures study, scenarios for Europe’s DG power generation were developed based both on a survey (cf. chapter 4.3) and the additional experience gained in the DECENT project. First, draft scenarios were developed by the DECENT team. These were submitted to a review by five European energy experts and subsequently revised to their final version. In the following, four scenarios will be given to illustrate possible futures of DG within the EU’s electricity supply in the year 2020. In addition, the scenarios serve as a basis for a ro-bustness check of the policy recommendations derived in the DECENT project (cf. chapter 9.8). It is not the aim of the scenarios to describe desirable futures nor will it be analysed which steps have to be taken in order to reach any of the scenarios. The time horizon for the scenarios is 2020. The technical input for the scenarios was drawn from the future survey. The scenarios were developed along two key drivers – environmental concern and technological development - which have substantial impact on Europe’s future power market. The scenarios have an illustrative nature in order to portray the findings of the future survey and to sketch possible future trends in the electricity business:

Scenario I – Green Power and Nuclear Ecology

Scenario II – Huge Fossils

Scenario III – Widespread Economic Niches

Scenario IV – Hip Ecology

Development of scenarios

The major impact factors upon the development of the electricity market and decentralised generation which have been identified in the DECENT project were structured and evaluated in a workshop by the DECENT research team. Two drivers:

1. Extent of greenhouse effect on the agenda

2. Degree of technological development of decentralised generation technologies

were selected to form the orthogonal axes of a matrix with four quadrants – the later scenarios (see Figure 6-1). The chosen set of drivers was preferred against other discussed sets since they are not under direct control of EU-policy in contrast to e.g. the liberalisation of the energy market. Although measures taken up by the Commission do have an impact on the drivers their relation is un-certain. Furthermore the drivers are to a great extent logically independent from each other and both of them are independent from policy strategies concerning the liberalisation process. Therefore they were considered to be especially suitable for a “robustness check” of the pol-icy implications derived in the DECENT project. In this respect it has to be mentioned that policy regulations at EU and at Member State level concerning the regulation and liberalisa-tion of the energy market may have a stronger impact on the future of electricity generation in Europe than the selected drivers.



96

The drivers are specified as follows: 1. Greenhouse effect on the agenda

The driver measures general public opinion on how harmful the greenhouse effect is to mankind and the importance this issue has upon political and economic decisions. However, the reason why the greenhouse effect is high or low on the agenda may be vari-ous:

greenhouse effect highon the agenda

greenhouse effect lowon the agenda

hightechnological

innovation

lowtechnological

innovation

I

II III

IV

Figure 6-1 : Four scenarios characterised by 2 drivers

The impact of CO2 emissions on climate change are not as drastic as anticipated today. The impacts are very drastic and first effects become visual. Other issues (economic or social crises) push environmental concerns off the agenda. However those possible rea-sons for a change in environmental concern will not be analysed further. The “zero” level would be today’s awareness of public opinion and the willingness of de-cision makers to take them into account. It is assumed that the development of the envi-ronmental concern from today up to the year 2020 has been rather linear – either towards a stronger or a lesser concern.

2. Technological innovation This driver measures the technological innovation that DG technologies have undergone. The focus lies less on the “in principle feasible” but rather on the “in practice applied” technologies. Thus the level of technological innovation corresponds directly to the initial costs of electricity from renewables and CHP in the various scenarios. Influential factors for this driver may be progress in basic research as well as economies of scale (in unit production). The different public opinion on how important it is to achieve CO2 emission reductions (represented by driver 1) may have an impact on the efforts undertaken to fos-ter the development of certain technologies. It is assumed however that the resulting initial costs are on the same (high) level in scenarios I and II. Respectively, they are equally low in scenarios IV and III. Today’s state of the art would represent the lowest level on the axis of this driver. Draw-



97

backs beneath this level seem only to be realistic when industrial branches collapse. For the scenarios minor drawbacks due to reduced production rates are included. However, “wild cards” like catastrophes are not considered.

The four scenarios were built to illustrate a set of possible futures. They were developed by combining the two drivers as indicated in Figure 6-1. As a first scheme the “facts” of the state of the various decentralised generation technologies (efficiency of technologies, achieved cost reductions, share of technology in EU’s gross power generation, etc.) were derived from the results of the future survey. It was assumed that the relation between drivers and the con-straints (used as variables for the questionnaire statements) is as follows: The higher the greenhouse effect is on the agenda the less crucial is the constraint by:

• Lack of support mechanisms

• Lack of public information • Spatial planning provision and procedures

Analogous, if technological innovation is high the following constraints lose impact: • Lack of R&D funding • Insufficient education / skill base

• Inadequate standardisation For each statement a mean time of occurrence was calculated from the expert responses. The time of occurrence was altered in the four scenarios according to the influence of the drivers upon the constraints which were rated as important by the experts for the occurrence of the statement. Example: Statement 2: “10% of Europe’s electricity comes from wind power” depends mainly on spa-tial planning procedures (76% of experts), support mechanisms (54%) and public information (28%). The need for R&D was rated very low (24%) and so was the need for standardisation (9%) and education / skills (7%). The expected time of occurrence was 2017. So in scenario IV this share of wind power should well be reached. If you compare scenario I and III, the share of wind power should be higher in scenario I, being close to the 10% landmark. It has little importance in scenario II. Based upon those “facts”, a general vision of the social, political and market situation of elec-tricity related issues was sketched. Major actors were identified. The most significant actor was picked to describe the situation from their perspective. However it has to be stressed that “most significant” does not mean highest market penetration. The described actors are signifi-cant in terms of being unique for the particular scenario.



98

6.1 Scenario I – Green Power and Nuclear Ecology There has been no substantial progress in the technological development of renewable energy technologies or combined heat and power production. The achieved cost reductions are mini-mal. On the other hand, the greenhouse effect is considered to be a very urgent issue. There-fore enhanced support schemes to promote CO2 emission reductions are in place. Private companies promote and use renewables for image reasons. The willingness of consumers to pay more for ecology is quite high. Green power is an established product. However, since most renewable energy sources are still quite expensive, there is a shift towards promoting energy saving and higher energy efficiency. In some countries nuclear power is becoming more important again. The electricity business is split between the mainstream, which is dominated by big utilities and the green power market with a large share of small idealistic companies trying to push renewable generation technologies. On March 9th 2020, euroNews, Europe’s leading virtual magazine published an interview with Mr. Alfred Pfeiffer (54), technical manager of Unit[e], one of the leading green power com-panies in the EU: euroNews: Mr. Pfeiffer, Unit[e] has just had its twenty fifth company anniversary. You are

one of the first generation power companies specialised in green power. After some ups and downs your company has established itself as one of the major players in the European green power market. Are you content with where you are now?

Pfeiffer: Sure we are! Unit[e]’s Eco-Power© has a market share of more than 20% of the national green power (see inbox) mar-ket in Germany and that accounts for less than one half of our turnover. We are ac-tive throughout all of Europe doing both production, trade and retail of electricity from renewable sources. Today there is – finally – some continuity in the power business again: The claims have been marked out - and we turned out to be one of the bigger ones of Europe’s green power retailers. However green power is still just the smaller fraction in the electricity mar-ket. The big shares are still held by the big players and now with the re-strengthening of nuclear power in some countries the former monopoly companies will still gain ground. So we can be content of where we are today.

euroNews: Looking back, to when it all started in 1998. What about your visions? Did things turn out like you expected after the liberalization of the power markets?

Green power basically comprises electricity generated with low or no CO2 emissions. In most cases one refers to electricity which has been labelled by the CO2CUT initiative. The label was invented in 2007 and is the only green power label acknowl-edged Europe-wide. Electricity from large hydro power plants does gener-ally not account to the share of green power although it causes no CO2 emissions. It has not been labelled by CO2CUT since a further support of large hydro power plants has not been considered to be necessary.



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Pfeiffer: As I said, we started as a small independent power company specialised on green power. Looking at our ideals, I guess the spirit hasn’t changed much. We want to push renewables because it is an ecological necessity. But we want to do it on a sound economic basis. Even if you look at the technical part of it, things haven’t changed that much. To be honest the technological development of renewable energy technologies has not turned out to be what people ex-pected it to at the turn of the millennium.

euroNews: In which respect? Pfeiffer: Well, look at wind power for instance. There have been plans to build vast off-

shore wind parks. Few of them have been realised. Most of them were down-sized and in terms of rentability most of them failed…

euroNews: …. why that? Pfeiffer: Offshore wind farms have huge maintenance costs. There were – and still are –

corrosion problems with some vital parts, the erection of the towers is quite troublesome and costly. There are quite a few technical problems, all of which can be solved but they drive up the costs. Still wind power – onshore and off-shore – accounts for 7% of the total electricity production in the EU and one fourth of it comes from medium sized offshore parks. (…) Onshore we have reached a limit I believe. Even I as an ecologist who takes the greenhouse ef-fect very serious wouldn’t want to push it any further. Offshore Unit[e] is de-veloping its fifth wind farm, despite all difficulties.

euroNews: And what about other renewable energy resources? When are we going to enter the solar age?

Pfeiffer: Haven’t we yet? (laughs) No, seriously, in the photovoltaic market we seem not to have moved too much. Technologically speaking, most so called “new materials” have not proven to be successful. Our company also lost quite a bit of money which we had put into PV technologies where a “major breakthrough is just ahead”. Basically today it comes down to various well established sili-con cells. The cost reductions have not been what you would have anticipated 20 years ago, but I personally believe there still is a big future in photovoltaics. We just put the one hundred thousandth PV plant under contract. A 3.5 kWp system on a small patio near Siena, Italy. I saw pictures of it – they used PV roof tiles with five different shades of red – it looks fantastic. It’s a pity that the company producing them never really reached what you could really call mass production. The owner of the house, by the way, is a German woman, who is in fact one of our first contractors. She owns another system in Freiburg, Ger-many, which was put up some 20 years ago.

euroNews: Is that a typical scheme: a small PV system owned by… Pfeiffer: … someone who is environmentally engaged? Yes! You see, quite a few effec-

tive support mechanisms have been implemented to push renewables. However we are still lagging behind in what should be done to counter the greenhouse effect. Most people think so and many of them are willing to pay their share in order to protect the environment. The producers which we have under contract



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– private companies and individuals – do not look so much to the interest they earn with their system, as long as they break even. And our customers are will-ing to pay more, because they can see what it is for.

euroNews: Do you also have combined heat and power plants under contract? Pfeiffer: Yes, we do, but just a minor share. CHP is well supported by all kinds of pro-

grammes. For an environmentally aware home owner CHP is a must anyhow. And with the established support schemes they are cost effective. But Unit[e] has been trying to get biomass plants under contract and we have managed to accompany some very interesting projects. Most of them are indi-vidually tailored though. Biomass fuel is still expensive compared to natural gas or oil. Collection and distribution of residues demand high logistics. And since the growth of most energy crops is highly energy consuming itself you are limited to very few crops which can be grown ecologically with a sophisti-cated output. I guess that’s what hinders biomass from becoming the major fuel for power production. Basically, new plants are put up wherever there is some support scheme for regional development. Especially in structurally weak re-gions, many farmers supplement their income with green power production.

euroNews: Looking into the future, what do think are the greatest problems in reaching further CO2 reductions?

Pfeiffer: Well speaking for the electricity sector, I think power management still is a big problem. There are attempts to put up load management systems and some of the consumers would be willing to accept quite some inconveniences. If you even want to call that inconvenience – I personally don’t care when my refrig-erator works, as long as my food is cooled. But we are still lacking smart sys-tems which control household appliances depending on high or low electricity prices. That would give us great opportunities to enlarge the share of renewable energy in Europe’s power generation. But in contrast to that, new nuclear power plants are set up with the good intentions of cutting CO2 down … well I don’t want to open that discussion up again, but the point is, if you don’t have the right framework – economically and technically – you are giving renew-ables a hard time.



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6.2 Scenario II – Huge Fossils There has been no substantial progress in the technological development of renewable energy technologies or combined heat and power production. The achieved cost reductions are mini-mal. The greenhouse effect is not very present in the general discussion. Most decision mak-ers do not consider it to be an urgent issue.

The European power market is dominated by several transnational power companies holding a market share of more than 90%. Large power plants using fossil fuels and nuclear power are predominant in the electricity production. Public funding and support schemes for renewable energy technologies and small CHP applications have gradually been brought down. Decen-tralised generation consequently plays a minor part in the electricity supply. Further develop-ments are only carried out under the aspects security of supply and regional development.

On March 9th 2020, euroNews, Europe’s leading virtual magazine published an interview with Ms. Françoise Lacroix (45), public relations manager at EEE Power Inc.: euroNews: Madame Lacroix, EEE is the largest European Power Company today. Does in

consequence EEE have a special responsibility to promote a sustainable devel-opment in the electricity business?

Lacroix: Most definitely! Sustainable development is one of our main targets and our economic success is based on it. For the economy of Europe the security of the energy supply is absolutely vital and a reliable electricity supply is the heart of it. In producing electricity EEE is very prudent concerning the demands of fu-ture generations – we are using the existing resources with maximum effi-ciency. The improvements in energy efficiency we have achieved within the last thirty years have been tremendous. Large scale plants provide both heat and power at low costs using minimal resources.

euroNews: Nevertheless you are relying upon fossil fuels for more than 60% of your power production. The majority of those fuels, namely natural gas and oil, are imported. Is that not something that endangers security of supply in the long run?

Lacroix: Well, you see, we are living in a globalised world and imports are not bad in-trinsically. So far no political crisis has been severe enough to really endanger Europe’s energy supply. But you are right it would be false to rely on only one source of energy. EEE has taken all efforts to diversify its power production as much as possible. We use a sound mix of gas, oil, coal, hydro and nuclear power.

euroNews: Concerning hydro power – being the only sustainable energy source you have named – what have been the achievements to build up a higher capacity?

Lacroix: Hydro power is the only renewable energy source that is available 24 hours a day. It is highly reliable and well suited to satisfy the demands. Therefore the potential of hydro power has been exploited wherever it was economically fea-sible. With large hydro power plants the potential has been tapped for many



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years. The major growth has been in small power plants. Here the capacity in Europe has risen by 20% compared to the year 2000.

euroNews: How about wind energy? That seemed to be a big issue?

Lacroix: We don’t own any wind farms ourselves, but we are buying electricity pro-duced by wind turbines. Most of them were erected about 10 years ago. I don’t know if you have followed the trends in the wind business. After the high pro-duction rates at the beginning of the millennium, there was almost a collapse in the turbine manufacturing business in recent years. Onshore the expansion of sites is limited due to protest from neighbours of wind farms. Offshore applica-tions are just not feasible. Some very rural areas still profit from the erection of wind farms. They became power producers, thus drawing a little money into the region. I believe that’s a good thing as long as the prices are reasonable.

euroNews: Do you see a prospective for solar energy?

Lacroix: If you look at photovoltaics, the cost reduction in the last thirty years has been so small, that I don’t see a breakthrough in the near future. There are special-ised applications, especially in third world countries, where there is no existing grid. In Europe, it’s not only the cells, it’s also the power management. The wind turbines are giving us enough trouble as it is. Sure there is a technical so-lution for everything, but why increase the prices for no reason?

euroNews: And what do you think the future will bring?

Lacroix: Well, in the long run, say over a period of fifty years or more, fossil fuels will diminish and other sources of energy supply will gain importance. May that be nuclear fusion or large thermal solar or geothermal, may be tidal and wave power plants or any other - I don’t know. New energy sources are an issue we will have to be thinking about in the far future. But in the meantime, we at EEE make sure to use fossil fuels as efficiently as possible so that there won’t be anything to worry about today.



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6.3 Scenario III – Widespread Economic Niches There has been an innovative push on renewable energy technologies. Great cost reductions have been achieved for both renewables and combined heat and power production. The greenhouse effect is not very present in the general discussion. Most decision makers do not consider it to be an urgent issue. Public support schemes for CO2 emission reductions have gradually been brought down. De-centralised generation is used wherever economically lucrative. Least cost management ap-proaches are applied frequently. Due to computer aided power management systems it is easy to integrate decentralised power generation technologies into the existing supply concepts. Actors in the electricity business are mainly big utilities offering multi-utility services to-gether with highly specialised, profit oriented service companies. Small businesses (green power producers, manufacturers of generation technologies, service companies) have grown or have been bought up. On March 9th 2020, euroNews, Europe’s leading virtual magazine published an interview with Ms. Mette Grønberg (37), key account manager at Northstar, one of the biggest European utilities. euroNews: Ms. Grønberg, Northstar is the biggest power company in the Nordic countries

but electricity is not all you are offering. Grønberg: That’s true. I mean, it used to be easy at those times when you just sold elec-

tricity or gas or … whatever. But to me it seems that most of our customers buy energy solutions. Sure, Northstar owns the biggest share of generation ca-pacity in the Nordic countries, but what is it that our costumers get to see from us? Look at alwaysenergetic a 100% daughter of Northstar. It is a highly spe-cialised, relatively small company. Its target is to provide highly reliable en-ergy schemes for customers who have extraordinary demands on security of supply, for example hospitals, IT companies and the like. A power loss for them is not tolerable. They have demanding needs concerning temperature and purity standards of the air. For them quality matters the most. Still they want to cut down their costs – that’s why they give our experts the job: alwaysener-getic.

euroNews: What would you supply to a medium sized Internet provider who starts a new office with a fairly big server?

Grønberg: First we would develop an energy concept together with the client. That may include a CHP scheme both for heating and cooling. This might e.g. be a Stir-ling engine or a micro turbine. However, we now mostly apply fuel cells pow-ered by natural gas. When we have all the parts together we arrange the techni-cal set up. We also offer to manage the maintenance, the sales of excess elec-tricity production, literally everything. The customer can choose from different financing schemes according to their needs.

euroNews: Is that typical? Don’t most of your customers buy the cheapest standard solu-tion?



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Grønberg: Yes, in a way you are right. But standard solutions only match standard cus-tomers. I guess it started with the introduction of the new price schemes for electricity. Formerly we used to have high peak loads and at other times didn’t know where to go with all the power we had at hand. Real-time metering opened the way to share this burden with the customer. Those who were a little bit flexible in their electricity demand dashed for the cheaper real-time tariffs. A whole market of demand side management tools emerged. Appliances are doing what you want from them, according to your individual needs, but they try to pick the cheapest tariff whenever possible.

Or look at single houses in remote areas. We have quite a few of them outside the urban clusters. For Northstar the maintenance of the electricity grid or even grid extensions are expensive. Least cost planning management schemes have been applied to all of our working fields. So for those customers far off we of-fer special energy saving contracts and financing schemes for individual power supply. You know, tremendous technical achievements have been made with fuel cells and new storage concepts. The costs for stand alone solutions are go-ing down. We even have started some pilot projects where we took some areas off the grid again.

euroNews: Do you also use photovoltaics in such cases? Grønberg: Scarcely! Solar cells were promoted due to environmental concerns at the be-

ginning of the millennium. The former support schemes for most renewable energies have either been reduced drastically or done away with completely within the last decade. Due to technological improvements costs for PV were cut down to one half over the last 20 years. Still PV power is expensive. De-pending on the circumstances solar cells are an economic alternative to supply standalone appliances in a power range of say up to some 100 Watts. With im-proved storage that might grow even further, but I guess we never reach the point where a significant number of households in Europe relies on PV. Most of the PV production is exported to southern countries.

euroNews: And wind energy? Grønberg: Literally speaking, wind energy has become a big business. Most lucrative are

the large offshore wind parks. Technically they have proven to be feasible and the large units help cutting the costs. But to compete with other means of power production you are limited to regions with high and reliable wind speeds.

euroNews: What will be the greatest challenges Northstar faces in the future? Grønberg: I believe the greatest challenge will be to keep up the pace of innovation in

which we were striving forward in the past. Technologically, but also in terms of coming up with solutions that fit our costumers and which stand on a sound economic basis.



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6.4 Scenario IV – Hip Ecology There has been a strong development in the fields of renewable energy technologies, fuel cells and other CHP technologies. Great cost reductions have been achieved for decentralised gen-eration technologies. The greenhouse effect is considered to be an urgent issue. Consequently support scheme to reduce CO2 emissions are in place. Their focus is on renewable energies, CHP and energy saving.

Due to innovative technological developments and a strong environmental awareness in the public certain renewable energy technologies have gained an importance as status symbols for customers. They are used by private companies for image reasons. Their “necessity”, whether for fashion or design is not questioned.

The profile of actors in the energy business has broadened. Although a large share of electric-ity is produced, distributed and sold by big transnational companies a wide variety of small and medium sized companies have entered the market.

On March 9th 2020, euroNews, Europe’s leading virtual magazine published an interview with Mr. Massimo Prato (47), Prato Energy Investments. euroNews: Mr. Prato, your company is the major investor in the newly build eco-village of

Montepulciano, the biggest energy independent settlement in northern Italy… Prato: … yes! Have you been there? It is a beautiful place! And no electricity wire around it

for more than three miles. I personally think the archi-tecture fits in splendid with the landscape! And yet eve-rything is very functional. (…)

euroNews: Who are the people who will be living there? The rich who do not care about the costs or hardcore ecologists who want to prove that they can live without being hook up to the electricity grid?

Prato: Neither one! Remember the leaps technology has made lately! The cost for solar power dropped to one fourth compared to the year 2000. In Montepul-ciano we used standard PV roof tiles as an economic solution and still they have a really great design. We also applied a totally new integrated demand side management system. With that we were able to push the need for energy storage to a minimum. And still it is not that the inhabitants have to suffer ma-jor inconveniences. The few limitations you have with regards to the maximum power available are totally bearable. I believe, the people who will be living in Montepulciano are people who are very aware of the ecological situation in the world. They know that a lot is done by the government to counter the greenhouse effect, but they also know, that this is by far not enough. They want to demonstrate that more can be done.

euroNews: Which is the main energy source you use in Montepulciano? Prato: Well, basically in this case we used a biogas CHP plant as the main source of

power. We thought about fuel cells. The developments made for fuel cells in cars really gave stationary applications a push lately. Now you see hydrogen supply networks emerging everywhere. But in the case of Montepulciano we



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sought a solution together with the local farmers. Most of them complement their income with energy crops anyhow.

euroNews: If you look back, say over the last two decades. What has been the major de-velopment in the energy business from your point of view?

Prato: To me, most significant and most fascinating to watch was the upcoming of all those “plug and generate” components. In solar and CHP, it became so easy for the consumers to become power producers. Just like that. Buy it, sign a con-tract, plug it in and some smart chip is concerned with power management and billing – you yourself don’t have to worry. That opened up the way for quite a few newcomers in the energy market who “run” virtual power plants without having to come up with the investment themselves.

euroNews: Is Prato Energy Investments also engaged in wind farms? Prato: We used to, when we started the business 20 years ago. But wind energy has

become the business of the big investors, like the big power companies. The wind industry really has boomed. The standard turbine size has passed the 10 MW line a couple of years ago already. Shortly 15% of Europe’s electricity demand will be covered by wind energy. The onshore sites are all exhausted by now, even taken into account that most people are very tolerant towards wind turbines – well they just see the necessity. And to build large offshore wind farms, as I said, you really need a lot of money. But it still is an interesting business. And with the growing hydrogen market I believe that wind driven offshore hydrogen production plants have a great future. It used to be natural gas we were drilling for in the North Sea now we are going to produce hydro-gen – with no CO2 emissions at all!

euroNews: One final question Mr. Prato – what is the secret of your success? Prato: If it was a secret we wouldn’t be successful!

In the energy business, trust is the most important thing! Of course, everybody loves solar cells: the architects play around with fancy colours, every new company building has integrated PV-facades for image reasons, there is no portable home appliance you wouldn’t also get with flexible power cells and so on. But in the end most people do buy electricity from the grid. And if you care about CO2 emissions you want to make sure the green power you buy is really green! Technically there are no problems with virtual power plants – you can integrate which ever mix of renewables you want, or if you come the other way: select the right sources so that you hit a certain price level. It has to work, sure, if you are not reliable it becomes expensive. But the most important thing for me is the customer. If someone wants green investments they know Prato is green not grey!

DECENT Final Report Case Study Analysis


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7 Case Study Analysis

7.1 Expert Interviews As depicted in the conceptual framework, as a first step in DECENT “relevant issues” for DG are identified, in order to identify potential policy action fields. In an extensive literature re-search and a extended number of expert interviews a broad view on status and chances of de-centralised generators within the different European power markets was gained. A number of 26 interviews were conducted covering a broad range of Member States, profes-sional backgrounds and technology, market and policy expertise. A complete list of interview partners is given in Table 7-1. The distribution of the interview partners’ expertise on the EU Member States and Technologies are depicted in the following figures.

Expert Interviews per EU Member State

0

1

2

3

4

5

6

7

8

A DK F D I NL P E S UK

Figure 7-1: Expert Interviews per EU Member State

Expert Interviews per Technology Focus

0

2

4

6

8

10

12

14

Policy Wind PV Hydro Biomass CHP Fuel Cells

Figure 7-2: Expert Interviews per Technology Focus



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Table 7-1: Expert Interview Partners in DECENT

Name Organisation

Cou

ntry

Gen

erat

ion

Tec

hnol

ogy

Fo

cus

Mar

ket o

r T

echn

olog

y or

ient

ed

Angulo IDAE (Spanish Institute for Diversification and Energy Saving) E CHP T

Bestebroer Agency for Research in Sustainable Energy NL Policy T

Bot Nuon (energy distribution company) NL CHP T

Capra ENEA (Italian national Agency for New Technologies, Energy and the Environment)

I CHP M, T

Dias ECOGEN, a company trying to develop micro-cogeneration (acting as an ESCO) in Portugal.

P CHP T

Graf ARGE Biogas, Austrian association of operators of agricultural biogas installations

A Biogas M, T

Hinnells ETSU, manages energy efficiency programmes in industry on behalf of the UK government

UK CHP M

Harrison EA Technology (international energy research and consultancy company)

UK CHP T

Kip Netherlands Federation of Energy companies (EnergieNed) NL Policy M

Krohn Danish Wind Turbine Manufacturers' Association DK Wind M, T

Laroche Club Cogénération (Association grouping all major actors in-volved in cogeneration in France)

F CHP M, T

Larsen Copenhagen Environmental and Energy Office DK Wind T

Malmrup Turbec (Swedish manufacturer of micro-turbines) S CHP T

Mez FFU (Environmental Policy Research Unit (FFU) of the Free University Berlin)

D, DK Policy M

Nissen R&D section of the power company of ELSAM DK Biomass, CHP, fuel cells

M, T

Petersen Vice director, Danish Energy Agency DK Policy M

Prochaska MENAG Energie GmbH (CHP and PV engineering company) D PV, CHP M, T

Reitter German association of Small Hydro-Plants (DGW) D Hydro M, T

Rettich Stadtwerke Rottweil (local electricity utility) D CHP M

Rijkers ECN, Netherlands Energy Research Foundation NL CHP M

Schnurnberger DLR/TT (Institute of thermo -dynamics of the German aerospace Centre)

D Fuel cells

T

Schönharting Unit Energy Portugal (wind park operator in Portugal) P, E Wind, hydro, biomass

M, T

Schuijt Vereiniging Wind-exploitanten Noord-Holland NL Wind M, T

Tafdrup Danish Energy Agency DK Biomass M, T

van Wunnik PDE (Project Agency for Renewable Energy) NL Policy M

Windelev Danish Energy Agency DK PV M, T



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Within the interviews the experts were asked for their experience and opinions regarding framework conditions for decentralised generation. The leading questions are given in the following table:

Table 7-2: Leading questions of expert interviews

1) What are the recent national trends and developments in policy and power market that you regard as important for DG projects?

2) What are, according to your experience, the main motivation issues of a potential investor/operator to consider a DG project?

3) What do you see as the main FINANCIAL issues to be overcome in a DG project ? What cost or revenue components are subject to an optimisation potential?

4) What do you regard as the main NON-FINANCIAL issues to be overcome in a DG project? 5) Which non-energetical (side) effects of DG projects do you regard as important? 6) Do DG projects you know show the theoretically expected performance in operation and environ-

mental benefits? If not, why? 7) Do you know DG projects that failed to be implemented or to survive? What were the issues? 8) What are the topics where you see the need for (further) regulation of the power market/ of frame-

work conditions for DG projects? Who do you regard as the adequate regulating actors?

While the detailed interview reports are given in Annex C to this report, the following table presents on overview on the experts’ key statements, clustered along the four analytical di-mensions of DECENT.



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Table 7-3: Key results from expert interviews

Social and environmental dimension Policy and institutional dimension Market and financial dimension Technological dimension

Ty

pe

of D

G

Co

un

try

Inte

rvie

w

partn

er

Environment is still not a hot issue in Spain (especially compared to northern European countries). It is certainly never high in the political agenda. However, security of supply is an issue right now. This year there will be difficulties to cover the electrical demand. This combined with the fact that the Spanish grid is not strong enough and requires a large investment if it is to cope with all the projected new capacity, may in the long term favour distributed generation. There are social problems to construct new power plants, as well as to construct new high voltage lines. Recently there have been two important demonstrations in two differ-ent regions against the construction of new large combined cycles. This may also favourdistributed generation in the long term.

There exist a legal framework and this is positive, although this legal framework is far from perfect. The attitude of the current government was very negative when it came into power, but there are signs that there might be a change of direction.

The market has been very dynamic in the last five years, despite the existence of a number of barriers. The situation has be-come more difficult with the increase of the gas prices combined with the decrease of the electricity prices.

CHP is well known in Spain, especially in the industrial sector. There is far less develop-ment in the service sector, but this is proba-bly more due to market conditions than to lack to awareness.

CH

P

Spain

Angulo, ID

EA

(Spanish Institute for D

iversification and

Energy S

aving)

Social and environmental aspects do not play a significant role. However, it is possible that in the near future the public opinion changes drastically in favour of emission reduction targets. In such a situation a green and social image could be important to gain a certain market share.

Because liberalisation has just started it is very difficult to say if there is a lack or an overflow of policy. Also is it difficult to judge about the quality of existing policy. It is probably better to wait and see what hap-pens on the market. Maybe will the market regulate itself or needs the government to intervene liberalisation has unwanted side effects, like not fulfilling CO2 emission reduction targets.

There is a small market for most of the DG technologies in the Netherlands. The situa-tion will improve coming years because of financial support mechanisms and techno-logical improvements. The only exceptions are small CHP and biomass installations. The ongoing liberalisation makes commer-cialisation of these technologies more and more unattractive Small CHP due the lower revenues for the produced electricity and higher cost for natural gas. Biomass installa-tions have problems in satisfying emission demands.

All the possible DG technologies can be considered as mature technologies. This is proven by the fact that these technologies are implemented on a commercial basis. If the technologies where not mature, meaning reliable and fulfilling what it promises, no market exists and demonstration projects would be the only projects that where carried out. However, this does not mean that im-provements are not possible any more. This applies especially for PV, fuel cells and storage technologies.

all

NL

Be

stebroer, Agency for R

esearch in S

ustainable Energy



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For enterprises in greenhouse horticulture, CHP is a ‘cheap’ way of satisfying environ-mental restrictions

The governmental support package currently under discussion is not sufficient. There is a large amount of money available for invest-ment aids. However, this does not solve the problems of existing installations (for which other measures are also proposed). CHP is not valued at the moment in the way renew -able energy is valued (energy tax exemp-tions). Mr. Bot argues that all electricity production methods should be compared to central production based on coal, and should receive ‘credits’ (be it in the form of certif i-cates, energy tax exemptions or other) for their environmental benefits.

Liberalisation in The Netherlands has lead to a difficult situation for CHP, because the commodity price of electricity has de-creased. CHP (gas engines) cannot com-pete with coal and nuclear power due to the high price of natural gas. Customers are not willing to pay extra for environmental bene-fits.

At the moment, small installations with a high kW price are too expensive compared to the revenues. New installations below 1000 kW are not worth considering anymore. In the experience of NUON, the performance of many CHP projects is less than expected. Reasons:· Quality of maintenance is not optimal, due to a lack of qualified personnel combined with the large number of installa-tions. · Less heat sales than expected. Mr. Bot gives a number of examples of CHP projects that failed to be implemented or to survive. A common background is that in the nineties, utilities were very eager to install CHP for environmental and financial rea-sons. Looking back it appears that contracts concluded in that period were often on too flexible terms.

CH

P

NL

Bot, N

uon (energy distribution

company)

Grid failures are a topic in southern Italy. Grants (up to 50%) and tax exemptions are presently obtainable in Southern Italy in order to stimulate investments and employ-ment

Until 1999, new high-efficiency CHP units were treated similar to renewables and received a fixed feed-in tariff. This decree is presently under revision for CHP. Renew -ables continue to receive a fixed feed-in tariff. In Italy the authorisations laws and procedures are very long and complex; sometimes it requires 2-3 years to start the works

Market development of power generation in Italy has not been completely implemented yet; the Power Exchange has been estab-lished only on January 1st, 2001 and there also many uncertainties on its effects. Pr o-ject f inancing is still less developed in Italy and financing costs can be significant espe-cially in Southern Italy where the capital market is not so efficient as in Northern Italy.

Combined cycles have reached a significant market availability in Italy and investment costs are rather optimised

CH

P

Italy

Capra, E

NE

A



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Portugal lacks natural resources (except hydro) concerning fossil fuels, but it has good potential biomass and good conditions for other type of renewables. The worry to decrease dependence from external re-sources is an issue favouring a positive framework for CHP and renew ables.

The legal framework is very good. For CHP is one of the few Laws integrating all its advantages (avoided network losses, envi-ronmental advantages). The draw back is that the tariff structure is too complicated.

There is still a large potential to be devel-oped and the conditions are good. The main obstacles are the current high gas prices (although the legal framework takes this into account satisfactorily) and the difficulties to connect imposed by Electricidade de Portu-gal (EDP).

CHP is well-known in Portugal, especially in the industrial sector. As in France, the small-est range has difficulties to develop due to the impossibility of connecting low voltage.

CH

P (m

icro)

Portugal

Dias, E

CO

GE

N

Biogas production / the use of manure in biogas plants and farming of energy crops have to be seen in the framework of agricul-tural structures, EU agricultural policies, water and soil protection and local accep-tance of agriculture and its odours.

Diverse regimes on feed-in tariffs in different federal states of Austria lead to accordingly diverse opportunities for biogas installations. Investment aids do not support development of more installations, but can be misused by faked investment figures.

The income is to a very high extent based on electricity sales, much less on heat sales.

Biogas-specific parts of technology (fer-menters, gas tanks) are overpriced in Austria (50% higher than Germany)

biogas

Austria

Graf, A

RG

E

Biogas

The social acceptance is still OK, but it will decrease if the power quality falls.

A main problem is the network tariff system, which is based on a point tariff system. For CHP the electricity produced for own use is exempt from the Climate Change Levy (CCL). Efforts to make micro-cogeneration eligible for certificate trading. EU is too slow and MS cheat often in order to protect their interest. MS are too much linked to commer-cial interest. Local Authorities have a too small vision

Market participation costs are for small scale projects a killer, because most of the market will be bilateral contracts (necessary to hire a trader) Capital costs for building are 100% tax allow able on the first year.

DG hasn’t had a bad effect on Power Quality so far, but it could become a problem later with nuisance dripping. CHP sometimes is run in such a way so as not to disturb the network. So it is run to maintain load at the expense of efficiency.

all

UK

Harrison, E

A T

echnology



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Climate Change is high in the political agenda in the UK and this has positive effects for CHP and renew ables.

The current policy dimension for CHP is one of the best in the EU. The UK government has explicitly recognised the need to con-tinue promoting CHP under a liberalised market and new initiatives have been issued. The most significant is the Climate Change Levy and the exemption for CHP (which complies with certain conditions of minimum quality). For the moment the effects of this have been very much minimised by the increase of the gas price. The exemption from the CCL just compensates this raise.

The main issues affecting the market are the high gas prices and the uncertainty about how the New Electricity Trading Arrange-ments (NETA) will affect small consumers.

CHP is a well-known technology in all appli-cations in the UK (industry, district heating and service sector). Renewables are less developed, although they have been pro-moted through the Non Fossil Fuel Obliga-tion. This type of incentive scheme has how ever been less effective that the feed-in tariff system used in Germany, Denmark or Spain. For example concerning wind energy, the UK is the country with most potential in Europe, however the current installed amount is far less than in the above men-tioned countries.

CH

P

UK

Hinnells, E

TS

U

The public and politics generally looks fa-vourably on DG/RES projects, but there is always the NIMBY effect that works in the opposite direction.

The policy environment, particularly subsidy schemes and facilitating mechanisms such as green certificates are important for the success of DG.

The image of projects is and important commercial consideration with regard to RES projects. High gas prices dictate the economics of CHP in the Netherlands.

Technical issues are not considered the main barriers to the implementation of DG projects.

all

NL

Kip, (E

ner-gieN

ed)

Public accept and participatory democracy in for example wind mills co-operatives; Local ownership has mobilised people in energy policy.

Crucial to the mounting of windmills is the availability of grid facilities on reasonable conditions. Here Denmark is a model as the grid enforcement is considered a public service good and hence paid collectively by the electricity consumers. Denmark has realised a long-term sustainable energy policy, which is also favourable to decentral-ised energy production plants and grid en-forcement. The planning process is in gen-eral a public transparent process. The off shore wind farms are located in the sea, which is public territory. Contrarily to French and British tenders, future Danish tenders are expected to oblige bidders to fulfil the contract.

The future market for on-land wind turbines is small in Denmark. Older and smaller turbines will be substituted, but hereafter on-land sitings will be limited. Off shore wind farms will be implemented – 750 MW is planned by now, but the potentials are much larger. Danish manufacturers of wind tur-bines cover a significant part of the world market and considerable expansions are foreseen in the future.

Future windmill technology will be framed by stepwise development and a focus on in-cremental innovations. No technological jumps are foreseen.

win

d

DK

, EU

Krohn, D

anish Wind T

urbine M

anufactu

rers'

Asso

ciation



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Given the situation described in the points above, these factors do not currently play a significant role. The fact that most of the electricity in France is from nuclear makes many say that the increase of CHP will in fact increase greenhouse gas emissions. Therefore the inclusion of CHP in the Cli-mate Change Programme in France is a more controversial issue than in other coun-tries.

At the moment there is a lack of legislation and this is having very negative effects, although there is a lot of discussion.

The market for CHP in France has been very good between 1997 and 1999, when almost 2,000 MWe were installed. This was due to the possibility of obtaining a 12 year purchase contract with EdF at favourable conditions (and providing for very good visibility). The conditions have changed since the Act implemented the Electricity Directive was issued. This Act says that it will be possible to set the obligation to buy electricity from CHP and renewables up to 12 MWe. The obligation has been confirmed by a recent Decree, but there is still no Decree regulating the conditions. This situa-tion is going on for about two years and is provoking a large degree of uncertainty that has paralysed the market. The situation became more difficult during the second half of 2000, when the gas prices raised.

CHP is a well-known technology in France. The share of electricity production from CHP is about 3%, but in fact there are more than 4,000 MWe installed already. This is due to the large amount of nuclear energy pro-duced in the country (it make about 80% of the total electricity production). CHP schemes exist in both industrial and service sector (and some district heating). One difficulty for the smallest range is that it is not possible to connect to low voltage network when electricity is fed into the network. The need of a transformer increases the price considerably.

all

Fran

ce

Laroche, Club C

ogénération (Association grouping all m

a-jor actors involved in cogeneration in F

rance)

The popular mobilisation in a co-operative has been important not only for the realisa-tion of the project but also for the environ-mental concern in general. Important side effects have thus been: - democracy and popular influence - local economy - environmental concern

The initiative is actively supported by the Municipality of Copenhagen. The municipal council has approved the project and also approved that the municipal energy unit co-operates with the project. Off shore wind farms are not part of the legislation on con-nection for land based wind turbines. It took more than 3 years to get the final permis-sion, and in each single step there were obstacles due to lack of legislative frame-work.

The liberalisation of the energy market is important to the development of wind farms or single wind turbines, but most important is the tariff/price for the power produced by wind turbines. The tariff is 0.60 DKK for the first 6 years, thereafter approximately 0.43 DKK (0.33 + at least 0.10 DKK for a green certificate) for 4 years. Following the first ten years of operation the tariff will be the price of power at the spot market plus the price of a green certif icate (at least 0.10 DKK). Feed-in tariffs like the German system would be much more appropriate. There is a high business interest in off-shore wind farms.

Wind turbine technology is a well known technology now adays.

off-sh

ore

win

d

DK

Larsen, Copenhagen Environm

ental and Ene

rgy O

ffice



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Because most of the electricity comes from hydro and nuclear, CHP from fossil fuels does not have significant effects lowering CO2 emissions. The government has com-mitted itself to phase out nuclear, but there are many political problems to put this into practice, although one reactor has been closed. Natural gas is not available in many areas.

There is no especial policy favouring CHP development, except for biomass CHP. The Swedish government is very active in pro-moting biomass.

The market is very difficult at the moment because of the very low electricity prices.

CHP is well known in Sweden, although not largely used, since there is a high share of nuclear and hydro electricity.

CH

P (m

icro turbines)

Sw

eden

Malm

rup, Turbec

Environmental motives do hardly play a role for developing DG projects. Biomass/waste disposal may be a strong incentive for DG projects. Biomass use can prove to be very important for regional develop-ment/agriculture.

Grid access is not regulated, which sets barriers to DG projects, large integrated utilities have the possibility to cross-subsidy, and use their market power. Integration of environmental policy into energy policy is still missing on EU level.

The possibilities for accelerated depreciationplay a very important role in DG economics (along with feed-in tariffs). The success of RECS (voluntary renewables certificate trading system) will have to be evaluated.

For CHP in industry, a proper integration in the energy system is crucial. PV has its niche mainly in off-grid applications

all types

Germ

any

Mez, F

FU

(Free

University B

erlin)

Consumers are willing to pay extra for envi-ronmentally benign energy as a community, not as an individual consumer.

Crucial to the development of decentralised energy systems is the combination of a guaranteed market and a fixed price system. The only feasible way to integrate wind turbines in the energy system has been the 20 year agreement between the wind turbine owners and Elsam. The 3-time tariff for decentralised CHP has been crucial for the development of these plants as well.

It is extremely difficult to manage the liberal-ised energy market. Therefore it is neces-sary with some sort of market place, either with futures or some sort of price guaranty from the very beginning. The challenge is to create a market for competing expectations. Quotas will influence the spot market price, but FN doubts that it will influence the in-vestments. FN prefers tenders where the risk is located at the political decision level and not at the market level. There are no large financial barriers to overcome.

The wild card in the future development is the technology. Is it for example plausible to buy a fuel cell in the super market and pluck it into the grid and produce one’s own en-ergy or is it not? This challenge is reflected in the protection strategy where locally integrated solutions for energy, water, waste etc. are developed in order to optimise decentralised utilities.

all

DK

Nissen, R

&D

section of the power

company of E

LSA

M



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Environmental consciousness is important when investing in decentralised energy forms. But decentralised energy forms are not per definition environmentally positive as we see with the emissions of gas installa-tions. Large plants can also be environmen-tally friendly.

The role of planning is important as it out-lines the framework conditions and guide-lines for the overall infrastructure, within which the large number of decentralised energy producers operate. Before 1995, planning was the foundation for investment decisions concerning single plants. As there now is a division between power producers and the power infrastructure, planning pro-vides the necessary framework conditions to make decisions. Decisions are now the product of a dialogue between the system operators and the Energy Agency. The development of the EU energy policy is expected to undergo the same development as in Denmark with green market and sus-tainable energy certificates. But the imple-mentation in each single member state will be much more differentiated than expected as it will be co-ordinated with national tax and regulation policies.

The energy reform has introduced the en-ergy sector into the internal market: - Infrastructure is considered a public good.- Requirement that consumer interests dominate the grid management (democratic ownership of infrastructure) – fulfilled by all Danish power plants due to their historical organisation as co-operatives. - The gradual separation between grid and production so that the power companies have the opportunity to make commercial activities on the free market and in open competition with other international compa-nies. Today economy of scale is considered less important than before. This has probably to do with the change of the organisational set-up of the power plants, which have changed from large co-operative monopolies to pri-vate co-operative companies operating on a free energy market.

The most important technology within decen-tralised energy projects is gas, CHP and renewable energy, of which wind is the most important. The Danish implementation of the gas and CHP projects was founded on a strategic choice following the oil crisis. The technology as such is well known and Dan-ish competence has developed in the appli-cation and organisation of the gas and CHP distribution systems. The development of the CHP has been successful. How ever, some plants have not been economically well founded, especially the 70-72 plants in the country side, the so-called open-field pro-jects

all

DK

Petersen, D

anish Energy Agency

PV: PV installations can be economical, if image/PR factors are internalised into the calculations. CHP and PV should be seen as beneficial to regional development/ job creation etc.

PV: German feed-in law provides for 0,50€/kWh which makes still not totally commercial to operate grid-connected PV installation. CHP: In Germany a CHP quota/certificate system is being discussed, which would probably support CHP consid-erably. However, care should be taken, that such a system does not get too complicated for operators of small installations, here a feed-in tariff might be easier to handle.

CHP: Presently the large power producers sell electricity partly below production costs in order to drive out competitors. This results in “too” low market prices for electricity in comparison to natural gas prices. Biogas (waste water treatment facilities) is still viable in Germany since gas comes “for free”. Utilities sometimes bureaucratically hinder interconnection they see as un-wanted competition

Grid: more grid failures are to be expected due to reduced maintenance/investment, which will make self-generation more attrac-tive

CH

P, P

V

Germ

any

Prochaska, (ME

NA

G Ener-

gie Gm

bH)



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Efforts for on-site environmental protection are steadily rising.

German fixed feed-in tariffs (Renewable Energies Act) provides for 7,67 Euro-cent/kWh, which adequate for the operation of existing installations. Permitting process is a major barrier, very time-consuming, due to not sufficiently standardised procedures and ecological restrictions.

Financing new installations is very difficult, since banks want personal liability of opera-tor. For new installations, return-on-investment timespans can exceed 20 years without subsidies.

Hydro-power technology is mature in terms of efficiency, prices for technology are falling slowly.

hydro

Germ

any

Reitter (hydro plants operator)

Customers are often reluctant to change their power supplier, but are willing to be supplied with heat. Environmental considera-tions play hardly a role in decisions.

CHP-quota as discussed in Germany would help considerably. Local actors (municipal utilities) should produce inventories for potential of heat islands / PV, wind, hydro, biomass potentials in order to optimise energy supply.

Contracting CHP is viable with cheap, stan-dardized units (1-5 MWe) if carried out in co-operation with utilities, and powerful finan-cial background.

Standardized units (including building, stack, heat storage , peak boiler) reduce costs.

CH

P

Germ

any

Rettich, S

tadt-w

erke Rottw

eil

It takes at least a year before permits are obtained. Municipalities have considerable freedom in setting requirements for permits. The lead time for acquiring licences may play a role in the choice of technology by a company that quickly needs heat. In case licensing for CHP takes longer than other technologies this could limit CHP develop-ment. Long term sectoral agreements with the government could/should aim at reduc-ing this barrier. Grid stabilisation is not an issue in The Netherlands

In the nineties, CHP has been an important option to satisfy the requirements of Long Term Agreements in industrial sectors. Since 2000, the same holds for the Benchmarking covenant that has been concluded with energy intensive industrial sector. Joint ventures of utilities and industrial companies were set up because utilities were not al-lowed to expand centralised utility owned capacity. The power output from decentral-ised JV projects could be contracted by the utility, thus providing a means to expand capacity. Recently, several government measures have been proposed to support the difficult position of CHP in the liberalising market.

At the moment we see some stagnation in CHP investments; banks are very reluctant to provide financing for CHP projects. This is partly due to the small project size, partly due to the uncertainty resulting from gas and electricity market liberalisation. Also, due to the changed tariff structures for natural gas (fuel costs, in particular for greenhouse horticulture) and electricity (backup service charges), some existing CHP installations are no longer cost-effective. Subsidies are regarded as a short term extra, that is not expected to last very long. Economic appraisal of the project is therefore based on other factors than subsi-dies.

The main motivation for the installation of CHP would normally be the demand for steam. However, with the new electricity tariffs dimensioning on electricity has be-come more attractive f inancially, although this is not the most energy efficient way.

CH

P

NL

Rijkers, E

CN



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Fuel cell projects have presently a strong image aspect (latest technology + environmentally friendly).

Political support is needed both in re-search/technology development and for f inancing of demonstration projects

Stationary fuel cells are competitors to established cogeneration technologies as internal combustion gas engines. In order to enter this market, the potential advantages have to be focussed on for niche markets: (very low emissions of air pollutants, and tendentially higher electrical efficiencies, esp. in partial load). Presently fuel cells only emerge as demonstration projects, and in niches.

While low temperature fuel cells (PEMFC, PAFC, AFC) offer higher flexibility and smaller sizes, high temperature fuel cells (SOFC, MOFC) are bound to reach higher electrical efficiencies. Technological pro-gress in the last years has been focussed on the fuel cell stack while much optimisation potential is still left in the peripherals (re-former, pumps, ventilators..)

fuel cells

Germ

any, EU

Schnurnberger (Institute of

thermo

-dynamics of the G

erman

aerospace Ce

ntre)

Regional development is highly focussed on in the context of renewable energies in Spain: There are provisions to guarantee the regions’ shares of value-added and income. In Portugal, municipalities often wish to receive benefits from DG projects.

Portugal has a complicated feed-in tariff system. The major barrier, however, are to get access to (former) monopolist EDP’s grid (EDP often claims that there are no free capacities), and to get a permission for siting (60% of sites attractive (under present feed-in conditions) for wind power are situated in protected areas).

PT, wind: presently ~ 100 MW installed wind capacity. The feed-in tariffs in the order of 0,05-0,06 €/kWh require wind speeds of ~7.5 m/s Portugal started a large Investment Aid programme for renewables (40% In-vestment aid) (500 Mio € earmarked for wind)

win

d

Portugal, Spain

Schönharting, U

nit En-ergy P

ortugal

VWNH acknowledges that the integrity of the landscape may be a reason to impede siting of a wind turbine. On the other hand it thinks that many of the problems can be resolved through participation of the people in the surroundings of a wind project. This is con-tradictory to the approach of many electricity supply companies.

The central government should take more action to allow easier siting of wind turbines by either directly appointing locations or municipalities, or by issuing guidelines to provinces and municipalities. Currently the regulating energy tax stimu-lates demand for RES-E. In the longer run it would be better if the polluter pays principle would be applied more strictly, so that wind could directly compete with other sources of energy. The route from the RES producer to the final customer should be made easier. In particu-lar the issue of imbalances should be re-solved.

For enterprises in greenhouse horticulture, CHP is a ‘cheap’ way of satisfying environ-mental restrictions

Technically Schuijt regards the wind industry as mature. This is not to say that no im-provements are possible. It means that technical standards are high and that the technical risk of a project is minimal.

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d

NL

Schuijt, V

ereiniging Wind-exploitanten

Noord-H

olland



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Farmers are investing in biomass installa-tions as a means for overcoming smell, to improve organic manure and economy. Still the biomass installation does not solve the problem with evaporation of ammonia.

The government has introduced incentives for developing biomass. In the period 1995-1999 a total of 25 mill. DKK has been granted to biomass projects with a total investment of 381 mill. DKK. There is in particular an interest in farm installations which may receive financial support of 30% of total investment, though max. 1 mill. DKK. Still, biomass does not receive the same political attention as wind energy. Counties have a tendency to look on the negative effects of biomass installations.

The liberalisation of the energy market is no good for biomass as it will be too risky for investors. Therefore it is preferable with a fixed price.

5-10 years ago there was a selection proc-ess where good and bad projects were separated. Too many projects have suffered from bad advisory from consultancy firms, which has induced operators to adjust and partly rebuild the system of operation. This should not have been the case as biomass is an old well known technology.

biomass

DK

Tafdrup, D

anish Energy A

gency

This is so far no issue. How ever, When more artificial intelligence enters the built environ-ment reliable pow er supply and power qual-ity becomes more important.

The politics need to develop a coherent long-term energy policy with a foresight. The recent European liberalisation process lacks a reliable set of rules, the politics must finish the job they started. It is important to inte-grate supply security and environmental aspects in a balanced set of measurements. Because of a lack of thought-out policy there is a risk that small-scale CHP dies in the Netherlands. Liberalisation makes small-scale CHP economically unattractive while for long time sustainable solutions small-scale CHP might play a crucial role.

Although the investment costs for renewable DG technologies are high the decision is made on the basis of commercial considera-tions. This can be done because the market is large and adult enough to choose the best or most wanted technologies and customers can and are capable of paying certain prices for the produced power. However, support mechanisms are still needed for renewable DG technologies. Generic mechanisms are preferred above technology specific meas-urements. Supply security and power quality might become to such an extent important for the ICT sector that they decide to invest in self supporting DG.

Distributed Generation becomes more im-portant as power source in the coming dec-ades. How ever, a lot of research must be done because certain technologies require breakthroughs or research must lift certain technologies from their present juvenile to an adult status. Therefore it is important to maintain support structures and funds for frontrunners, because new ideas are needed. Recent grid capacity and structure is unsuitable for a domination of DG in total power generation. How future grids should be outlined is unknown research on this topic is necessary. An increased participa-tion of DG makes storage a very important issue.

all types except fuel cells

NL

van Wunnik, P

DE

(Project A

gency for Renew

-able E

nergy)



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The carriers of the success of solar energy were and are the political interest and sup-port for sustainable energy combined with sufficient financial support/incentives. With the programme Sol 1000 (1999-2003) a compensation arrangement has been agreed where the meter measuring in- and outgoing power within the limits of zero consumption. This arrangement is expected to be prolonged.

Large companies as for example Shell and Siemens got interested and prices lowered. The technological trends and market oppor-tunities are promising within photovoltaics. The main barrier is the economy compared to the w ind energy. The energy reform and the free market may induce producers to combine photovoltaics and wind as the energy forms produce at different time of the day.

Today, PV is a highly reliable technology where manufacturers offer a guarantee of 20-25 years. Mono and poly crystallite cells produced by the remaining products from the semiconductor industry are threatened by optimisation of materials within this industry itself. More expectation is oriented towards non-crystallite cells as thin layer and polymer which is flexible and cheaper. However, this production is very pollutant and the durability is not 25 years but rather 10.

PV

DK

Windelev, D

anish Energy A

gency



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The expert interviews, along with the literature review, set the basis for a preliminary formu-lation of relevant issues (formulated as hypotheses) concerning the development and opera-tion of decentralised generators. This set of hypotheses39 was to be validated and augmented in the case studies that were conducted in the framework of DECENT. In the subsequent step of analysis a final set of barriers and success factors for DG was identified (cf. chapter 8).

39 The internal working paper on hypotheses is given in Annex D.



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7.2 Choice of Case Studies The case studies in DECENT were chosen in order to facilitate a detailed research of the DG project’s framework in relation to the hypotheses. Furthermore, a good representation of the different Member States had to be ensured, in order to be able to get case study information on possible effects of different settings of the power markets. As relevant indicators the level of liberalisation and market conditions, and the type of RES-E/CHP support scheme were chosen. In addition, a fair mix of the generation technologies covered in DECENT had to be maintained. It is obvious that a complete coverage of each technology type in each institutional setting in each Member State would have far beyond the scope of DECENT. However, by focussing on the pre-identified issues, it is possible to use the respective institutional settings found and analysed in a case study as an example for a given issue. In the following table an overview on the case studies is given: Table 7-4: Overview on Case Studies

Number Technology comments Member State C1 PV Building integrated, high support D C2 PV Good solar conditions E C3 Hydro Run-of-river, new micro plant D C4 Hydro Irrigation channel, existing micro plant I C5 Hydro Run-of-river, existing medium-size plant F C6 Wind On-shore wind park, good wind conditions F C7 Wind On-shore wind park, good wind conditions NL C8 Wind On-shore wind park, good wind conditions,

regional benefit system E

C9 Wind On-shore wind park, medium wind conditions D C10 Wind On-shore single turbine DK C11 Wind Off-shore single turbine SF C12 Wind Large Off-shore wind park DK C13 Biomass Wood gasification DK C14 Biomass Wood gasification D C15 Biomass Solid biomass incineration, Failure P C16 Biomass Solid biomass NL C17 Biomass Biogas A C18 Biomass Landfill gas A C19 Natural gas CHP Integration in a hospital NL C20 Natural gas CHP Integration in industry E C21 Natural gas CHP Integration in a hospital B C22 Natural gas CHP Integration in an housing project UK C23 Natural gas CHP Micro-CHP (household) D C24 Fuel cell Integration in a hospital, PAFC D The distribution of the case studies on generation technologies and EU Member States are shown in the following figures:



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Distribution of Case Studies on Generation Technologies

012345678

PV Hydro Wind Biomass Natural gasCHP

Fuel cell

Figure 7-3: Distribution of Case Studies Generation Technologies

Distribution of Case Studies on EU Member States

0

1

2

3

4

5

6

7

A B DK SF F D I NL P E UK

Figure 7-4: Distribution of Case Studies on EU Member States

The wide distribution between Member States entails as well that the different approaches and stages of liberalisation as well as the different support schemes for RES and CHP are met. Fully liberalised Member States like Finland, UK or Germany are covered as well as Coun-tries that have opened their markets close to the minimal extend like France or Portugal.

7.3 Short Presentation of Case Studies In the following, a short presentation of the conducted case studies is given. The detailed documentation of the case study reports is given in Annex E to this report.

Case Study 1 - PV plant WISTA Business Centre, Berlin, Germany

The installation is a new 46 kWp PV plant, commissioned in 2000, erected on top of the WISTA Business Centre in Berlin, Germany, featuring different types of solar panels and inverters in parallel operation (as a demonstration aspect). The project was initiated by a Solar initiative of the WISTA science and business park, the development and operation was taken over by a PV engineering company. The project was supported by a 40% investment subsidy



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from a regional environmental programme in order to award the demonstration character. Fur-thermore, the project was rendered feasible by the 50.6 €ct/kWh feed-in tariff which is guar-anteed for 20 years by German law.

Case Study 2 – PV plant “Pergola Fotovoltaica de la Moncloa”, Madrid, Spain

The installation is a new 41.4 kWp PV plant, commissioned in 2000, erected on top of a per-gola used for press briefings in the Presidential Gardens of La Moncloa. The project benefits both, the investment subsidies (46%) and the 21.6 €c/kWh feed-in tariff provided by Spanish law. The investment was made by the Energy Saving Agency IDEA in order to demonstrate innovative third party financing.

Case Study 3 - Hydropower plant Tzschelln, Germany

A new 220 kWe hydropower plant (run-of-river scheme) built on top of an existing weir, commissioned in 2001. Developed and operated by a private individual with a high degree of personal involvement. The project is supported by the 7.7 €ct/kWh feed-in tariff which is guaranteed without a time limitation by German law. Problems in the development arose mainly from disputes with the authorities on the type of permit and from complicated negotia-tions for investment loans.

Case Study 4 - Hydropower Plant Magliano, Italy

An existing 870 kWe plant, built in 1948, integrated into a system of irrigation channels, 1997 bought by an internationally active developer and operator of renewable energy-based power plants. The economics are based on feed-in tariffs (5.7- 8.1 €ct/kWh) which are paid by the Italian national grid operator.

Case Study 5 - Hydropower plant Port Mort, France

An existing 6 MWe plant (run-of-river scheme) integrated in a lock & weir systems that regu-lates the river Seine for naval purposes. 2000 bought by an internationally active developer and operator of renewable energy-based power plants. The economics are based on feed-in tariffs paid by French quasi-monopolist EDF: 2,7 €ct/kWh (summer tariff) and 6,7 €ct/kWh (winter tariff).

Case Study 6 - Wind Park Lastour, France

New wind park in southern France, 3 x 600 kW = 1.8 MWe, at a site with 8.0 m/s at hub height (40 m), commissioned in 2000. 5th wind park ever interconnected in France. The de-velopment was prepared while the tariff situation was still unclear. The project is supported in the French EOLE 2005 programme with a fixed feed-in tariff of 6.5 €ct/kWh (annually ad-justed to inflation).

Case Study 7 - Wind park Zwaagdijk, Netherlands

The wind park Zwaagdijk (6 x 850 kW = 5.1 MWe) is a project in development in the prov-ince of North Holland in the Netherlands. The main barriers in the projects were to get plan-ning consent. Acquiring planning consent means going through lengthy public procedures -



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during which the project encountered public opposition and suffered from competing wind initiatives in the municipality. In this particular case the local government therefore attempted to optimise wind development by appointing designated wind development sites within its jurisdiction. All wind projects that were proposed were aggregated into this one wind devel-opment site or turned down. The whole procedure took about 6 years and is now about to close. The project should be able to go ahead in 2002.

Case Study 8 - Wind park El Perdon, Spain

The wind farm “El Perdon” is located in the region of Navarra in the Northern part of Spain, close to the regional capital of Pamplona. It was the first wind farm set up in 1994 by Energia Hidroelectrica de Navarra S.A. (EHN). 20 MW produced by 40 GAMESA produced wind turbines has been installed in a first phase in December 1994 and a second phase in October 1995-March 1996. Recently, a test turbine (1.3 MW) has been erected in El Perdon, which is larger, has longer blades and an elevator in the tower for the maintenance. The site has good wind – 8.2 metres/second at an altitude of 740-1,000 meters. The turbines are located in a row and a bird corridor has been established to avoid major collision problems.

Case Study 9 - Wind park Keyenberg, Germany

New wind park, commissioned 2000, in an inland site, at medium wind conditions: wind speed 6,1 m/s at 68 m and 6.2 m/s at 80 m (different hub heights), 9 x 1.3 MW = 11.7 MWe. The park was developed by a professional wind park developer and is operated by a limited partnership (closed funds) which was set up by the developer. The financing schemes bases on feed-in tariffs (9.1 €ct/kWh for 20 years for a low-wind site as in the case) guaranteed by German law, and on tax effects in the first operation years for the private investors of the lim-ited partnership.

Case Study 10 – Single Wind turbine, Vindinge, Denmark

The wind turbine is located at Zealand in a small village called Vindinge just 5 km outside the town of Roskilde. The turbine was erected in 1981 originally at a rated power of 45 kW but was upgraded to 55 kW in 1995. The site is characterised by a fairly low wind speed – the turbine has approx. 1800 full load hours compared with an on-land average of 2200 hours. The wind speed at this site has not been measured. A Danish farmer privately owns the wind turbine. His main interest for putting up the turbine was a general interest in renewables, though the economic profitability of the turbine was essential as well. Although the wind tur-bine has never produced as much power as expected, the owner is satisfied with the decision of erecting the turbine.

Case Study 11 - Off-shore wind turbine Lumijoki, Finland

The turbine was erected 1999 on an artificial island in shallow water, 800 m off the shore-line, in the Gulf of Bothnia, Baltic Sea, Finland. The wind-speed is 6.8 m/s at hub height of 53 m. The developing company was founded by environmentally motivated people, which attracted capital by issuing shares. The project was supported by a governmental 40% invest-



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ment subsidy. The electricity is sold at 4 €ct/kWh to a Finnish green power supplier and to the company’s shareholders. The company intends to use the project’s income for further wind power development.

Case Study 12 - Off-shore wind park Middelgrunden, Denmark

The wind farm was the first private off-shore farm to be established in Denmark and was hence subject to constraints posed by existing legislation. It took more than 3 years to get the final authorisation in 1999, and in each step there were obstacles due to inappropriate legisla-tion involving a range of actors, e.g. the Danish Agency of Energy, Danish Agency of Envi-ronment, municipalities of Greater Copenhagen, the Ministry of Defence, the telecommunica-tion companies, the Danish Maritime Authority, National Environmental Research Institute etc. The farm consists of twenty 2 MWe turbines totalling 40 MWe. The average wind speed is 7.2 m/s (at 50m height, hub height is 60m).

Case Study 13 – Biomass - wood gasification plant, Harboøre, Denmark

In the small Danish town of Harboøre, a full-scale gasification system supplies electricity and district heating to a community of around 560 houses. The system consists of an updraught gasifier, a gas purifying system and a gas engine cogeneration plant. The thermal capacity is 2x1450 kW, the electric capacity being 2x760 kWe. The income from the electricity production depends on the tariff which is structured in three intervals (5,63 €ct/kWh; 8,3 €ct/kWh; 9,9€ct/kWh). Subsidies included in this amount are 2,34€ct/kWh for avoiding CO2 Emissions and 2,28 €ct/kWh from the state.

Case Study 14 - Biomass incineration CHP plant, Silbitz, Germany

The 5 MWe plant is in the construction phase and is situated in the outskirts of the small vil-lage of Silbitz, state of Thuringia, Germany. It is a grate firing installation and will burn non-halogenated wood residues of varying provenance. Although it will serve the village’s district heating network with a maximum load of 3 MWth, with an annual average heat load of below 0.5 MWth the plants predominant character will be the production of electricity from nega-tive- or low-priced wood residues.

Case Study 15 – Biomass - wood incineration plant Mortágua, Portugal

9 MWe wood incineration plant, commissioned in 1999, situated in a rural area to make use of forestry residues. The project is supported in the Portuguese ENERGIA programme. There is electricity supply to public grid, no heat use. Portuguese quasi-monopolist EDP is involved in the development. However, the project failed due to problems with the biomass fuel supply. The conversion to natural gas is under consideration.

Case Study 16 – Biomass - wood incineration CHP plant Lelystad, Netherlands

The 1.8 MWe biomass plant was commissioned in 2000 to replace an existing natural gas fired plant, the electricity is fed to the public grid, the heat is used in the Lelystad district heat-ing system. Fuel is clean biomass: thin out wood from the woods of the region and prune wood from the public gardens from surrounding municipalities. The plant was developed by a



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large Dutch utility and supported by a governmental 20% investment subsidy. The operation is supported by a refund of the Dutch Regulating Energy Tax (5.8 €ct/kWh) for RES-E.

Case Study 17 - Biomass: biogas CHP plant, Roppen, Austria

A 330 kWe biogas CHP plant situated in Roppen, Tyrolia, Austria, commissioned 2001. The installation makes use of rural biological wastes. While the electricity is exported to the grid, the heat is used for fermenting purposes only. The plant’s economics are based on the fixed feed-in tariff provided for by Austrian law: 6,9 €c/kWh.

Case Study 18 – Biomass - landfill gas CHP plant, Boeschistobel, Austria

A 280 kWe CHP plant operating on landfill gas at a rural landfill site in Austria, commis-sioned December 1999. The plant’s heat is used for woodchip drying. The plant is an example of an innovative third party financing scheme: In this case the operator of the CHP landfill gas plant gets the landfill gas free of charge from the operator of the landfill site and sells the electricity back to the landfill operator for a negotiated price of 3,2 €ct/kWh. The landfill op-erator sells the electricity to the utility at the fixed feed-in tariff of approximately 8 €ct/kWh which is provided for by Austrian law.

Case Study 19 - Natural gas CHP plant Alkmaar, Netherlands

The plant (2 x 1MW = 2 MWe) was installed 1996 in the MCA Hospital in Alkmaar, Nether-lands, mainly to cover its heat demand. Approx. 90% of the hospital electricity demand is covered by the CHP plant, additionally surplus power is sold to the utility. The plant is devel-oped and operated by the hospital. In January 2002 the hospital loses its status as captive cus-tomer and will negotiate new terms of supply and delivery.

Case Study 20 - Natural Gas CHP plant Pozoblanco, Spain

The 4 MWe plant is foreseen for a dairy factory in a rural area, to basically cover both power and heat demand. It is operated by liquefied natural gas, since no pipeline is available. The project is supported by public funds in order to support rural industrial structures.

Case Study 21 - Natural gas CHP plant, Ronse, Belgium

The 164 kWe CHP plant was commissioned in 1993 in a 139-bed-hospital, in Ronse, Eastern Flanders, Belgium. Due to the well-known attitude of the Belgian utility, the plant was de-signed not to export electricity but only to supply electricity at times when it is very expen-sive, i.e. at peak hours, whilst simultaneously using the heat produced. A main driving force of the realisation of the project was the personal interest of hospital personnel in CHP, as-sisted by a governmental subsidy programme for demonstration installations.

Case Study 22 - Natural gas CHP plant St Pancras & Humanist Housing, London, UK

The 54 kWe CHP plant was installed 1995 at the St Pancras & Humanist Housing Association in London. They provide a total of 95 one, two and three bedroom flats, and bedsits. The complex also includes an elderly persons’ community centre, ten commercial units and SPH’s own head office. SPH aims to provide their tenants with a full service package rather than



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simply apartments or commercial premises, and they also have a green policy. The plant does not export electricity, it rather serves only the housing blocks, The financing was facilitated by a Government subsidy.

Case Study 23 - Natural gas micro-CHP engine Schonungen, Germany

The 5.5 kWe CHP engine was installed 1996 integrated in the heating system of a newly built single-family house. It is designed to meet the heat demand of the house and is operated in winter only. The surplus power is sold to the utility at 4 €ct/kWh.

Case Study 24 - Phosphoric Acid Fuel Cell Bocholt, Germany

The 200 kWe fuel cell was installed 2001 in the St.-Agnes-Hospital in Bocholt, Germany. It is embedded in an environment of different natural gas CHP engines. The project is subsidised by the local utility, a large gas supplier and a US export subsidy. For the hospital, which oper-ates the plant, the investment costs are restricted to the costs of a comparable CHP engine.

DECENT Final Report Barriers and Success Factors for DG


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8 Barriers and Success Factors for DG Within DECENT, barriers and success factors for Decentralised Generation in the EU were identified through extensive case studies, expert interviews, and literature review. First, how-ever, a characterisation of the actors and typical constellations is given, as it was found to be typical in the DG field. These form an integral part of the barriers and success factors pre-sented thereafter.

8.1 Characterisation of Actors The field of DG in the EU is characterised by a large variety in technologies and in regula-tory, market, and societal frameworks. The large variety in framework conditions is reflected by very different constellations of actors involved in DG development. For example, the structures of the wind sector vary considerably between Denmark, Germany, and Spain, which are hosting the largest shares of wind power in the EU: While in Denmark the operators of wind turbines are usually set up of neighbourhood-based co-operatives, in Germany wind power investors are typically organised by a number of wind development companies into investment funds-type limited partnerships, which draw their profitability to a considerable extent from effects of book losses and depreciation on the individual investor’s income tax. In Spain however, usually neither neighbourhood nor other private individuals play an important role in wind power development: here large companies that are launched by traditional utilities industry, banks and public actors dominate the market, the major driver for public involvement being regional development promoted by settling wind industry. Generally, it was found in DECENT that a very high share of DG operators and developers work as independent power producers (IPPs), or self-producers, and are NOT linked with the established utilities. (This was the case in approx. 75% of the case studies.) In parallel, an equally high share of projects studied is based on highly committed individuals or organisa-tions that work hard in order to overcome the difficulties in the project development, or based on investors that are ready to renounce profit, and accept pay-back periods of ten years and longer. In addition, nearly 100% of the projects studied were financially benefiting from one or more types of public support schemes (mostly investment subsidies, fixed feed-in tariffs above market price, production subsidies, soft loans and/or depreciation schemes) or consid-erable private funding. The overall picture for DG in the EU is therefore characterised by the fact that the economic framework conditions in EU member states are generally so weak (varying, of course, consid-erably from member state to member state and technology to technology) that DG investment is not attractive to “economically rational” actors which are bound to optimise return on eq-uity and short-term profit. DG is therefore mainly developing in niches characterised by either an extraordinarily beneficial economic project environment (e.g. CHP in hospital) or/(and) actors/investors which have other criteria (or framework conditions) for their profitability considerations than large corporations. When discussing barriers and success factors, and subsequently policy implications for DG in the EU, the specific characteristics of the different actor groups on the DG markets need to be kept in mind.



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8.2 Identified Barriers and Success Factors In Table 8-1 an overview on the barriers and success factors identified is shown. They are arranged in a matrix featuring the analytical dimensions used in DECENT and different as-pects of DG development and operation.



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Table 8-1: Overview on barriers and success factors for DG

Dimension aspects

Technological dimension

market & financial dimension

Policy & institutional dimension social & environ-mental dimension

General B1 Specific Difficulties of Small

IPPs B2 Uncertainty on (Support) Policy De-

velopment S3 DG Values apart from

the Energy Markets

Siting and Licensing

B4 Licensing Problems for Biomass Plants (Wood Waste)

S4 Clear Definitions on Waste Categories and Licensing Conditions

B5 Spatial planning & licensing (for RES) S5 Integration of Potential DG Sites in

Spatial Plans

B6 Local Resistance (RES)

S6 Involve Local Actors

Grid Connection

B7 Grid Connection Procedures

S7a Clear Cost Allocation Rules S7b Socialisation of Grid Connection

Costs

Use of Grid

B8 Market Power of Utilities

B9 Intransparent Grid Use Fees

Power Sales � S10 Priority Dispatch

B11 Balancing and Trading of Exported Power

S11 Specialised Green Power Traders

Start-up and Operation

B12 Biomass Fuel Supply S12 Involve Forestrial /Agricultural actors

for Biomass Supply B13 Lack of Skilled Technicians (CHP)

Financing B15 Financing S15 Innovative Financing Con-

cepts

Profitability B16 Ratio of Gas and Electricity Prices (CHP)

S17 Eligibility for Support Mechanisms B17 Lack of Tailored Support Mechanism

Major Barriers and Success Factors are highlighted and printed in bold letters



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8.2.1 Policy/ Institutional Dimension

B2 Uncertainty on (Support) Policy Development

In many EU Member States policies concerning the regulation of the power market, the tran-sition to a liberalised market environment and/or support schemes for DG installations/ RES/ CHP are subject to an intensive political discussion and frequent change. The time horizon for active support policies is sometimes limited to a few years. In addition, the introduction of new schemes or the expiry of time-limited schemes lead to policy gaps which increases uncer-tainty on the frame conditions of a planned DG development. Taking into account the size, flexibility, and financial strength of the developer, uncertainty and policy gaps can thus con-stitute important barriers to DG development.

B5 Spatial planning & licensing (for RES)

The spatial planning requirements determine what kind of licences or approval a DG devel-oper needs in order to physically erect and operate the prospective installation. These proce-dures vary very much between DG technologies, EU member states, and often within a single Member state between different regions, or municipalities. The transparency of necessary procedures and the certainty of approval (under conditions) are crucial for the developers. The amount of time, manpower, technical expertise, and financial resources to be invested into the siting and licensing process can thus vary considerably. For DG based on RES, aspects like visual amenity, protection of local ecosystems, land use, preservation of landscape, historical heritage, monuments, etc. or other possible impacts on the neighbourhood are of relevance.

For (natural gas based) CHP installations such problems matter less, since they are anyway integrated in building structures where energy converters are placed (industry, hospital, hous-ing etc.). As modern natural gas fired CHP engines usually comply with stringent air emission standards, for CHP installations usually noise might form a bottleneck for licensing, depend-ing on the location.

Planning and licensing appear to be a barrier especially for hydro power and wind power; special problems occur for biomass plant firing waste wood (cf. special barrier). For PV developments above 100 kW or in the MW size, siting can pose a serious problem, since most roofs built in the last two decades are not designed to carry high additional loads, and green-field developments can face licensing problems in order to prevent surface sealing and spatial consumption.

An example for this barrier is the Middelgrunden off-shore wind farm near Copenhagen, Denmark, where the planning process took three years due to inadequate legislation. Also in the Lastour wind farm project (Southern France) the necessary adaptation of the spatial plan posed major problems with inexperienced authorities. The Tzschelln hydro plant case study (Eastern Germany) points up how small hydro devel-opment is endangered and prevented by a general negative attitude against small hydro in the administration of the German federal state of Saxony.



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S5 Integration of Potential DG Sites in Spatial Plans

Integration and thus pre-selection of potential sites for DG use, especially wind power, into spatial plans helps to avoid conflicts between DG use of sites and nature protection, or other uses. In Germany this tool proved successful since on one hand it enables local authorities to channel wind power development to preferred sites (and simultaneously to bar other sites) and on the other hand siting efforts for wind developers are considerably reduced. The case study Keyenberg wind farm (Western Germany) can serve as an example of how a wind project benefits from such a scheme.

Similar approaches are possible for other renewable energies, too.

Additional support to DG developers can be given through public inventorying of data on exploitable natural potentials (which is partly done for wind and hydro power) or even heat demand (potentials for small-scale heating grids to be served by biomass or CHP).

B7 Grid Connection Procedures

Here, the terms of physical connection of the generator to the grid shall be distinguished from the terms of use of grid services, once the generator is interconnected. To form the basis for physical interconnection to the grid, DG developers have to agree with the grid operator / the utility on the technical terms of interconnection, on contractual matters including liabilities, and on the allocation of costs for feasibility studies, necessary grid rein-forcements and line extensions. Such issues are covered by regulation in Member States to a different degree. Subject to uncertainty on the DG developer’s side are sometimes the techni-cal specifications regarded as necessary by the grid operator. Technical issues which are disputed are e.g. capacity of grid, necessary upgrades, point of connection, interconnection voltage, line protection technology, reactive power behaviour and islanding options. While lack of grid capacity can prevent projects, cost allocations for other issues can enhance the DG developers costs considerably (cf. case studies Pozoblanco CHP (Spain), Lumijoki wind turbine (Finland), Lastour wind farm (France), St.Pancras CHP (UK) and other RES examples from Germany)

Additionally, missing access to local/regional load management data of the grid operator can impede the DG developer to optimise the choice of DG site (for RES)

S7a Clear Cost Allocation Rules

In German legislation on RES a cost allocation rule is given: The costs for the line extension (power generator to grid connection point + transformer) have to be borne by the plant opera-tor while a possible necessary grid upgrade is to be borne by the grid operator (and can be socialised among all grid users). This rule proved to be rather successful (cf. e.g. case studies Tzschelln hydropower, Keyenberg wind farm, WISTA PV, Silbitz biomass (all Germany)), however in practice (cf. barrier Market Power) disputes remained on cost allocation. A clear-ing office at the German government tries to find solution on such disputes.



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S7b Socialisation of Grid Connection Costs

In Denmark, grid extension for the connection of off-shore wind farms is considered a public good. Thus costs are borne by the grid operator. This cost allocation was a beneficial factor for the studied Middelgrunden off-shore wind farm (Denmark).

B9 Intransparent Grid Use Fees

In a liberalised market environment the grid operators charge fees to power traders. Such grid use fees are subject to regulation in all Member States besides Germany. These grid use fees and the procedures how they are regulated have a high impact on DG viability, in case the generator operates on a trading scheme. This is demonstrated in the Lumijoki wind case study (Finland). However all other studied projects that export power at all operate under a feed-in scheme, where the power is sold under regulated tariffs to the grid operator so that a trading operation as indicated above does not take place (examples from Austria, Denmark, France, Germany, Italy, the Netherlands, Portugal and Spain). However, it is anticipated that the relevance of grid use fees for DG will rise with ongoing liberalisation and the replacement of fixed feed-in tariff schemes by green certificate schemes. Second, during operation of the interconnected DG installation, regulated tariffs (or negoti-ated fees) will determine the costs that are associated with the use of the grid infrastructure both for supply of electricity to the grid/ to customers and for the demand of additional or back-up power (mostly relevant for CHP).

S10 Priority Dispatch

Electricity regulation can foresee that systems operators grant priority dispatch to eligible generators. With such a model, depending on the specifications the operator is paid the market price, or a higher premium price, while the power is passed on to all power traders as a Public Service Obligation, or to captive customers. Such schemes relieve the DG operator from the need to establish and maintain contacts to power customers and to balance production with demand.

All studied projects that are designed to export power (besides the Lumijoki wind turbine, Finland) are benefiting from priority dispatch (examples from Austria, Denmark, France, Germany, Italy, the Netherlands, Portugal and Spain).

B11 Balancing and Trading of Exported Power

In a liberalised environment, DG operators that do not feed-in to the grid operator under a regulated scheme need to contract power customers, balance their production with customer demand, and (if applicable) trade their green (or CHP) certificates. Especially balancing pro-duction with demand is a difficult task for intermittent producers (RES besides biomass; CHP designed to heat load).

S11 Specialised Green Power Traders

The co-operation with specialised intermediate agents like green power traders, certificate traders or associations of intermittent producers relieves IPPs with hardly any administrative capacity and little negotiating power from the need to put too many efforts into balancing and



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market communication. For example, the co-operation with a green power trader was a crucial success factor for the Lumijoki wind project (Finland).

S17 Eligibility for Support Mechanisms

Within the EU Member States a broad variety of “financial” support mechanisms are in place or in preparation that are designed to improve the economics of a DG installation usually in order to account for the external environmental benefits. The shape of these support schemes is usually differentiated between RES and CHP and further between different technologies and installation sizes. Support schemes can include price-oriented instruments like fixed feed-in tariffs, investment subsidies, production subsidies, fuel subsidies, soft loans , ecotax exemptions or other taxing/depreciation schemes, or quantity-oriented instruments like ten-der/fixed price systems or quota/green certificate systems . All studied projects are (or were) benefiting from one or more types of support mechanism. For RES projects the financial support was usually crucial and (mostly in form of investment subsidy, high-price fixed feed-in tariff and/or soft loans) a major driver of the development. One project (Lastour wind farm, France) was realised under a tendering scheme, while quota/green certificate systems are not yet in use. For (natural gas) CHP projects the picture is more diverse: those projects realised before the recent decline of electricity-gas price ratio were generally less dependent on direct public support; they were rather realised in an economical niche provided for by utilities’ tariff struc-tures and own heat and power demand patterns. Other projects that were suffering from bad economics were realised only with the strong wish of the investors to install a CHP unit ignor-ing more economic alternatives.

B17 Lack of Tailored Support Mechanism

When designing support mechanism the specific needs of the actors developing and investing in DG should be taken into account (cf. chapter 8.1). Problems encountered by project developers within the support mechanisms were: Long-lasting uncertainty on availability and amount of investment subsidies (e.g. Lumijoki

wind, Finland), long-lasting uncertainty on availability of soft loans (German RES projects), small-sized developer/operator cannot make use of accelerated depreciation rules high efforts to handle tax refunds (e.g. Schonungen CHP, Germany) Generally for the rather small-sized IPPs high transaction efforts, complicated regulation and lack of long-term clarity on the support conditions constitute a barrier within a support scheme.

8.2.2 Market/ Financial Dimension

B1 Specific Difficulties of Small IPPs

Most operators and developers of RES installations are not the long-established utilities but new and comparably small-sized enterprises. This is due to the relative recency of these tech-nologies and the well-known difficulties to operate them profitably, which attracted mostly environmentally committed individuals to engage and invest in RES DG projects (cf. also chapter 8.1). Compared to other market actors those developers have often disadvantages in



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knowledge, experience and capacity. Their activities are often restricted to local niches, which on one hand can be an advantage (successful co-ordination of local framework and actors); on the other hand, however, they don’t have the possibility to flexibly position themselves in an integrating European market. It should be realised, however, that NOT all RES developers/operators are small IPPs (e.g. case studies Madrid PV (Spain), El Perdon wind farm (Spain), Mortágua biomass (Portugal), Lelystad biomass (Netherlands). CHP installation are by definition (local use of heat) subject to strong local considerations, the operators/users of DG-CHP are usually in a weak negotiating position confronted with grid operators / utilities.

B8 Market Power of Utilities

DG operators, which are in most cases IPPs are usually confronted with established players on the electricity market. Important market players to deal with are grid operators, fuel and technology suppliers, and (depending on the type of market structure for RES/CHP) traders, customers and/or ESCOs. Market power used against IPPs is often reported in connection with grid connection and grid use issues and –where not regulated- feed-in tariffs. Grid companies (often only to a very lim-ited degree unbundled from power generation and wholesale activities) can impose many un-justified problems on DG developers seeking interconnection. The amount of market power used is influenced on the way unbundling and market opening is realised in the respective Member State, and on the level of detail of regulation. However, this barrier is limited neither to unjustified technical or financial requests to the DG operator seeking grid connection nor to failure of acknowledging values that the DG capacity and power might constitute to the grid. In addition the procedural behaviour of the grid opera-tor to slow down, complicate, and boycott an interconnection application unofficially can lead to prevention of DG developments, especially if the DG developers lack funds, time and ca-pacity to sue the grid operator/ utility. Other fields where market power is used are e.g. access to end customers for traders, unjust valuation of power fed back to the grid, capacity charges or fuel supply (e.g. conditions of gas supply to CHP installations). Policies of grid operators towards DG vary considerably from company to company and vary over time, too. While some grid operators / utilities seem to have a decided policy to impede third party DG development, others might simply lack experience. Negative experience with grid operators was gained especially in the case studies Pozoblanco CHP (Spain), Ronse CHP (Belgium), St.Pancras CHP (UK), Schonungen CHP (Germany), Silbitz biomass (Germany); in addition very negative experience is reported from some other German utilities. In Spain, successful RES developments are characterised by the involvement of utilities in the developing consortium.

B15 Financing

The relation between investment, fuel prices and (heat and )electricity prices are such that DG projects (besides specialised CHP applications) are in most cases economically viable only



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with support mechanisms. However, even with support mechanisms profitability of DG pro-jects is in most cases rather low compared to alternative investment and not satisfying for “economically rational” actors (corporations) that try to maximise their profit. Financing con-cept thus rely often on committed actors that are ready to accept reduced profitability. In addition to raised equity of committed investors banks have to be found for financing. Here, it is a problem that DG projects are still relatively new to the financing market in some EU member states. Developers that rely on project financing, and thus cannot borrow on their company assets, have additional problems providing loan security. Examples for financing problems are found in the case studies on Lumijoki wind plant (Finland), WISTA PV plant (Germany), Port Mort hydro plant (France), Harboøre biomass CHP and Boeschistobel land-fill gas CHP.

S15 Innovative Financing Concepts

Financing schemes attractive to private investors have been successful both in Germany and Denmark (closed funds; cooperatives) supported by both taxation system and motivation for green or neighbourhood investment. In the case studies Magliano hydropower (Italy), Lastour wind farm (France), and Port Mort hydropower (France) equity for financing was raised by the developer in Germany, where private investors for RES are relatively easy to attract. Standardised financing concepts/contracts to decrease transaction costs for small actors are yet to be developed.

B16 Ratio of Gas and Electricity Prices (CHP)

The changing ratio between natural gas and electricity prices in the last years has made opera-tion of natural gas fired CHP hardly feasible. This appears to be the major barrier for CHP development presently, and has led already to the decommissioning of CHP plants. The CHP plants studied in the case studies were either developed way before the present decline of the ratio between gas and electricity prices (and are already written off) (e.g. Alkmaar CHP (Netherlands), Ronse CHP (Belgium)) or operate in a specialised high price niche (Po-zoblanco CHP, Spain) or are operated with very little or no expectation of pay-back to the investor (Bocholt fuel cell (Germany), Schonungen CHP (Germany), St.Pancras CHP (UK)).

8.2.3 Technological Dimension

B4 Licensing Problems for Biomass Plants (Wood Waste)

In most countries, solid biomass use relies on industrial waste wood, which triggers the dis-cussion “waste or biomass?” While wood waste is attractive through the negative or neutral fuel price, it has its disadvantages through licensing difficulties and a bad public reputation of waste incineration. In addition the future development of prices for biomass waste wood fuel is relatively unknown. Licensing problems were encountered e.g. in the Lelystad biomass project (Netherlands) and in the Silbitz biomass project (Germany).



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S4 Clear Definitions on Waste Categories and Licensing Conditions

Clear definitions on waste categories and licensing conditions help to overcome the licensing barrier for biomass plants based on waste materials: Although the Silbitz biomass projects (Germany) had its difficulties in obtaining the operation license, the process was facilitated through relatively clear definitions of waste categories in German legislation on eligibility for RES support and on conditions for an operation permit.

B12 Biomass Fuel Supply

The use of biomass for power/heat production has a very large potential in the EU Member States. However, severe problems to be overcome in development and operation are posed in securing fuel availability and organising (and financing) fuel logistics. Biomass plants that use “fresh” biomass residues as fuel, have to cope with high fuel costs. Difficulties with bio-mass supply were e.g. encountered in the Mortágua biomass project (Portugal). Biogas instal-lations base on a sound organisation of fermentation input, too (cf. Tyrol biogas case study (Austria)). Projects relying for cost reasons on industrial wood waste as fuel have high prob-lems to secure long term fuel supply (cf. Silbitz biomass plant, Germany).

S12 Involve Forestrial /Agricultural actors for Biomass Supply

The Tyrol biogas case study (Austria) shows, how early involvement of the local agricultural association contributed to the project’s success. In contrary, the involvement of local actors had been neglected in the Mortágua biomass project (Portugal), which led to severe problems in fuel supply.

B13 Lack of Skilled Technicians (CHP)

In the process of installing and interconnecting small-scale or micro-CHP, a lack of skilled technicians who are not used to deal with relatively new technologies can lead to increased efforts and cost for starting-up the plant. This problem was encountered in the case studies Ronse CHP (Belgium) and St.Pancras CHP (UK), while in the Schonungen CHP project (Germany) the local presence of the technology provider avoided such problems.

S14 Technological Innovation

The use of information and communication technologies (ICT) can considerably help to lower operation and administration costs. For example, in the St.Pancras CHP project (UK) the use of telematic metering and a specialised software package made the successful implementation possible.

8.2.4 Social and Environmental Dimension

S3 DG Values apart from the Energy Markets

If it is possible to achieve a valuation of other DG related benefits (besides (green) power, heat, and grid services), this can prove very advantageous for DG development: For many, mostly rural, DG developments, the systems border for project evaluation can be widened: The objective of the development is then more than supplying electricity to an



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anonymous power market. Additional objectives might be e.g. energy supply for businesses in remote areas (CHP, RES, cf. Pozoblanco CHP, Spain) or structural changes in agriculture (e.g. energy crops) based on a labour intensive “Biomass economy” (cf. Mortágua biomass (Portugal), Tyrol biogas (Austria), Harboøre biomass (Denmark)). Thus DG can form a means to deliver regional structural benefits. One example is wind power development in Spain (cf. El Perdon wind farm), which has a very broad political support as a means of regional devel-opment in structurally weak regions. The positive image factor of an environmentally friendly DG installation is sometimes taken into account by operators. This is often the case for PV installations which would usually be uneconomic if only calculated as an electricity generator. If PV (or other DG) becomes part of a company’s PR strategy, the systems border is widened and the installations turn economic. This process can seen e.g. in for the PV strategies of retail companies and service station op-erators in Europe. Similar examples can be found if PV is integrated e.g. into buildings and the module takes over a building’s function, like roofing or façade.

B6 Local Resistance (RES)

Despite of the broadly accepted environmental benefits of DG, local resistance can be strong. Reasons vary between technologies: source of air pollution closer to the people (CHP, bio-mass), danger of smell (biomass), noise (CHP, wind), ecosystem protection (hydro, wind), integrity of landscape (wind, green field PV) etc. However, major resistance against natural gas CHP occurs hardly since such CHP installations are usually integrated in building struc-tures which (acceptably) host energy converters anyway. Local resistance can constitute a high barrier to be overcome in a development, since neighbourhood participation rights in spatial planning and licensing/siting processes have generally grown strong, and neighbourhood resistance might also be reflected in non-cooperation of local authorities. No project failure due to local resistance was encountered in the case studies. However, re-ports of projects (esp. wind and hydro) prevented due to neighbourhood or environmentalist pressure group resistance are numerous e.g. in Germany and in the UK.

S6 Involve Local Actors

Schemes to ensure financial involvement in DG developments or benefits to the neighbour-hood can help significantly to reduce local resistance and foster local support. Some examples for such schemes can be seen e.g. in Denmark (e.g. Vindinge wind project), where investors of wind parks should be based in the immediate vicinity/municipality of the site, Germany (e.g. Keyenberg wind farm), where some developers grant easier access to the financing scheme for local investor individuals, or in Spain (e.g. El Perdon wind farm), where certain regions mandate 40% of value-added to be gained within the respective region. To involve environmental NGOs in the development process also proved to be successful e.g. in Germany.

DECENT Final Report Policy Implications


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9 Policy Implications

9.1 Introduction The purpose of this chapter is to elaborate the key regulatory issues arising under EU and Member States’ (MS) electricity policy and regulation relating to Decentralised Generation (DG) and to prepare recommendations to the relevant decision makers to enhance the feasibil-ity of DG projects within the internal energy market. In order to address the way and extent to which EU rules and policies relating to DG are being translated into MS rules and policies, and the way these two complement and/or inter-relate with each other, we focus on the EU legislation relating to DG and apply the rules to the vari-ous stages in the development of DG projects (cf. chapter 3.2). These stages include authorisations and permitting, interconnection, contracting, financing, and operation. Wherever possible, the analysis has taken into account the country-specific rules and policies in the elaboration of the relevant market structures and regulatory regimes. However, within the framework of the DECENT project, it was not possible to examine in detail the systems of all 15 EU Member States, and therefore, recommendations directed at national or local level have been formulated in general terms. In its analysis, the project team has formulated and applied a number of fundamental general principles for the future reform of electricity markets and related regulatory regimes. These principles are related generally to the concept that in the long run, DG should be integrated into current electricity markets not through subsidies or support mechanisms, but rather, upon the recognition of the environmental and other values of DG, the internalisation of external costs, the creation of a level playing field, non-discriminatory and transparent treatment of DG, and proper incentivisation of distribution system operators. Thus, although we discuss and analyse the various support mechanisms in place, and their possible harmonisation, it should be clear that the indefinite perpetuation of the current support systems is not recom-mended. Because policy development takes place within a legal framework, and should be analysed as such, every policy component discussed herein is correlated to the applicable rules at EU level and to some extent at national level. Despite the local character of many DG installations, the "policy environment" is varied and multi-dimensional, with numerous inter-related compo-nents as indicated in the diagram below. Therefore, in some ways it is not possible to articu-late a "single policy" for DG, given that it does not fit into existing responsibilities and institu-tional structures. Nevertheless, steps should be taken to counteract the fragmentation of the current situation and to increase co-operation and co-ordination such that DG is more often treated in a non-discriminatory manner.



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DG

Internal MarketDirectives

EU energypolicy

CHP Directive?

National regulatorysystems

Renewables Directive

National regulatorysystems

Plus:•Planning policies•Environmental policies•Waste policies•Security of supply•Energy efficiency (CHP)•Energy taxation•Emission trading•Energy Performance Buildings

Figure 9-1: DG and the legal and regulatory environment

In terms of EU energy legislation, the Electricity Directive 96/92/EC40 and Gas Directive 98/30/EC41 have general relevance to electricity producers using DG, and they contain spe-cific references to the treatment of electricity from renewable energy sources (RES) and/or combined heat and power (CHP) production. The transposition of the Electricity Directive in the EU Member States are probably most significant for DG in the area of network access and unbundling requirements. However, as pointed out by the European Commission itself, issues relating to national network access fall primarily within the competence of national authori-ties. The most significant existing EU legislation for purposes of clarifying the regulatory issues relating to DG is therefore the EU Renewables Directive of 200142, and in particular its pro-visions relating to “grid system issues” (Article 7 of the Renewables Directive). Similar rules are also under development for CHP, in accordance with the proposed Directive on the pro-motion of cogeneration based on useful heat demand43. In its explanatory memorandum, the European Commission has explained this similarity as follows:

“Cogeneration producers are generally faced with the same difficulties as producers of electricity from renewable energy sources in relation to grid system issues. As a consequence, this proposal in many respects bases itself on the same provisions as those contained in the [Renewables Direc-tive]”.44

In addition to the above, this report considers the possible impact of the relevant provisions in the recently proposed EU legislation to complete the internal energy market. This is primarily because the amended proposal for a Directive to amend the Electricity and Gas Direc-

40 Directive 96/92/EC of the European Parliament and the Council of 19 December 1996 concerning common

rules for the internal market in electricity, OJ L 27/20 (1997).

41 Directive 98/30/EC of the European Parliament and the Council of 22 June 1998 concerning common rules for the internal market in natural gas, OJ L 204/1 (1998).

42 Directive 2001/77/EC of the European Parliament and of the Council of 27 September 2001 on the promotion of electricity produced from renewable energy sources in the internal energy market, OJ L 283/33 (2001).

43 See European Commission, Directive of the European Parliament and of the Council on promotion of cogene-ration based on useful heat demand in the internal energy market, COM(2002) 415 final.

44 Ibid., at 15.



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tives45 contains provisions which define "distributed generation"46 and which set forth some proposed common rules on how DG should be treated. Moreover, both the Renewables Direc-tive and the proposed CHP Directive contain cross-references to the Electricity Directive, meaning that the various (proposed) Directives must be considered together to understand the (anticipated) legislative framework at EU level. A variety of other existing and draft measures and communications at EU level are relevant to DG and these are described in detail in Annex A to this report.

Analysis of Success Factors and Barriers to the Implementation of DG Projects

The following subchapters describe and analyse the main success factors and barriers to the implementation of DG projects. Figure 9-2 outlines the various stages in initiating and operat-ing a DG project that are taken as the basis for the analysis. For each stage, the main barriers and success factors are listed, based on the analysis of case studies in chapters 7 and 8. The case studies, which are referred to in the analysis, are also described in more detail in those chapters. For each of the DG project stages, the barriers are linked to the main policy areas and the main actors that determine the result of the relevant project stage. On this basis, it is possible to identify the main criteria for policy improvements per project stage. Furthermore, depending on the political level at which the relevant policies per project stage are defined, as well as the key actors involved, it can be decided at which level a policy response is war-ranted.

45 COM(2002) 304 final (7 June 2002).

46 Under the proposed Article 2(32) of the amended proposal, "distributed generation" shall mean "generation plants connected to the low-voltage distribution system". This term was selected by the European Commission in favour of the earlier proposed term "embedded generation".



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Project stage and barriers policy key actors improvement level main improvement

criteria

Authorisation and Permitting Spatial planning; local resistance; licensing problems for biomass plants

local/regional spatial planning local, regional government; national governments and regulators

Member State + local transparency, certainty

Environmental policy local, regional and national government

Member State + (EU) transparency, environmental integrity

Interconnection Grid connection procedures; Market power of utilities

Liberalisation: network regulation network operators; regulators; judicial authorities

Member State + EU transparency, certainty

Contracting Balancing services and trading; Market power of utilities; Non-transparent grid use fees

Liberalisation: power market organisation

traders, suppliers: regulators Member State + EU efficiency, market conformity

Financing Support mechanisms; Financing problems

financial incentive policies national governments; financial institutions

Member State + EU certainty

Operation Non-transparent grid use fees; Market power of utilities; Ratio of gas and electricity prices (for CHP)

financial incentive policies national governments; financial institutions

Member State + EU efficiency, certainty

Liberalisation: transmission and distribution fees

grid operators: regulators Member State + EU certainty

Barriers not specific to a particular stage:

Uncertainty on policy development

Lack of skilled technicians

Figure 9-2: Actor-phase diagram for DG in a liberalised market



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9.2 Authorisations and Permitting In the authorisation and permitting stage, there can be substantial delays and transaction costs due to numerous and possibly lengthy procedures. A variety of authorisations, licences, con-sents, or permits are required, usually issued or granted by various authorities. In particular, operators of DG installations usually must obtain at a minimum a construction and/or operat-ing license. Distinction can be made between the following main types or authorisation or permits:

• An authorisation or license to engage in the business of electricity generation and related authorisations (e.g. heat production), which are normally required or exempted under pro-cedures pursuant to the national energy legislation

• construction and/or building permits linked to spatial planning procedures and regulations; • environmental permits. In some countries, DG installations are exempt from national authorisation procedures and would need only the second and third types of permits. The associated procedures vary strongly among DG technologies, EU Member States, and often within a single Member State among different regions, or municipalities. The local level is very important in this context because local governments are responsible for issuing the permits, and because local opposi-tion can successfully delay or even prevent the issuance of the permits. In addition to the gen-eral procedural efforts that are needed to obtain the required permits, a considerable amount of RES developers – being small independent power producers (IPPs) – suffer of a lack of financial resources and flexibility needed for the long procedures. Transparency and a clear timeframe of authorisation and permitting procedures are important to reduce the scope for lengthy procedures.

9.2.1 Construction Permits and Spatial Planning

Renewables

Permitting and planning requirements appear to be a barrier especially for hydro power and wind power. For PV developments above 100 kW or in the MW size, there may be construc-tion problems since most roofs built in the last two decades are not designed to carry high additional loads. Moreover, green-field developments can face permitting problems with re-spect to surface sealing and spatial consumption. Spatial planning appeared as a barrier in three case studies, concerning offshore wind in Den-mark, and onshore wind in France and in The Netherlands. In all three cases, the planning process took several years. The Middelgrunden off-shore wind farm was the first private off-shore wind farm in Denmark, and no planning rules had been established for this kind of plants. Lack of experience on the authorities’ side was also a problem in the Lastour wind farm project (Southern France) where the delay was caused by the necessary adaptation of the spatial plan. However, since then (1999), regulations for wind farms have been introduced in France, providing more clarity. The wind farm Zwaagdijk in the Netherlands has been apply-ing for planning permission for 6 years. The planning permission procedure required the mu-nicipal zoning plan has to be adjusted. This includes public appeal procedures and final ap-proval from the provincial council.



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In contrast, case studies on wind projects in Spain, Germany and Finland did not encounter such serious difficulties in the planning stage. The case study Keyenberg wind farm (Western Germany) project has benefited from the German spatial planning scheme which encourages local planning authorities to identify priority sites for wind power development. In Spain (El Perdon wind farm) the planning provisions were also described as transparent. The Spanish situation is quite different from that in most other countries. The (wind farm) developer se-lects a site, but in many cases this concerns common land, without private interests, and there-fore only the regional government has to consent. Large developers dominate the market, and they often involve regional governments, local industrial partners and local utilities in the organisational structure of the proposed project to ensure the required support. As far as planning processes are concerned, Doyle (2001) confirms that the time until ap-proval is much shorter in Germany (up to 6 months) than in the UK (up to 3½ years) and The Netherlands (up to 6 years). In each country, the key problem lies in another part of the plan-ning process: planning permission (UK), revision of the legally binding local plan (Nether-lands) and the construction permit (Germany). Most (environmental) licensing problems encountered in the case studies were related to bio-mass plants (see the next section). In addition, the Tzschelln hydro plant (Eastern Germany) case study illustrates how small hydro development can be delayed by a negative attitude in the administration of the German federal state of Saxony47. The granting of the permit has been in question for a long time and is still to be decided upon in a legal case. More in general, problems can occur because permitting or licensing processes are not well suited to the concept of smaller, decentralised generation facilities. There may be several ap-plicable and potentially overlapping permits, codes, and requirements for a DG project, each with its own separate process, constituency and decision-makers (ADL, 1999). The way in which the spatial planning and licensing process is conducted is essential for the duration and complexity of the procedure. Differences between Member States occur in the following key issues. • Who takes the lead in identifying suitable sites? In some countries, such as in The Nether-

lands and the United Kingdom, existing land use plans must be revised to include DG pro-jects (wind or hydro). If project developers are the ones that identify possible sites and have to appeal for such revisions, this is a lengthy process, which may also incur signifi-cant additional costs for the DG developer.

• The government level on which the planning authority is placed (in most cases local, sometimes regional) and the amount of experience or competence of local authorities. Lo-cal governments need to balance potentially conflicting interests. Doyle (2001) states that for both the UK and The Netherlands, the main issue that causes rejection or long delays is the balancing of local visual impact arguments against higher level benefits on a case by case basis.

47 Within the federal state of Saxony, a generally negative image of small hydro plants prevails within the

administration, following the „bad behaviour“ in the early 90s of some hydro plant operators, which sometimes let parts of rivers fall dry in order to maximise power production.



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• The criteria used for the environmental impact assessment and/or construction permit. In some countries, municipalities have considerable freedom in setting requirements for permits. Various different licenses may be required, such as a building permit, and envi-ronmental permit, and depending on the size also an environmental impact assessment.

• The transparency of necessary procedures and the certainty/time of approval (under condi-tions). Keeping in mind that many DG developers are small actors that are not dealing with these procedures on a regular basis, transparency is an important requirement. In some countries, national planning procedures can be improved on specific issues such as reception points and deadlines.

CHP

As for renewable electricity, permitting and licensing procedures may also form a barrier to the development of decentralised CHP projects. The DECENT case studies have provided little evidence that decentralised CHP schemes in buildings, or on commercial or industrial premises, have been hindered by authorisation procedures. This is because the CHP installa-tions were normally located within existing buildings or their license application was included in a wider application for a construction permit. This does, however, not exclude regulatory obstacles, such as lengthy procedures to obtain operating permits, during the authorisation of decentralised CHP plants as referred to in the Commission's CHP Strategy (European Com-mission 1997). This can be illustrated with the practices in Greece, where CHP developers have complained about centralised and lengthy procedures to obtain the relevant permits al-though funding for projects has been authorised.

EU legislation

In line with Article 5(2) of the Electricity Directive, many countries have laid down specific criteria for the grant of authorisations for the construction of new generating capacity in their territory. The Directive lists certain acceptable criteria for the grant of authorisation, but these are often supplemented by countries in their national legislation. In some energy laws, exemp-tions from certain application requirements, for example, financial or technical background requirements, are expressly waived for applicants for installations using RES and/or CHP. For example, the requirement of “availability of sufficient funds” need not be proved in certain countries by applicants for licences for electricity generation from renewable resources, unless the installed capacity of the electricity-generating equipment is higher than a specified amount. Another example would be rules that require an expedited treatment (with time dead-lines) for the processing of licence applications. Under Article 6(1) of the Renewables Directive, the main obligations on the Member States are to "evaluate the existing legislative and regulatory framework with regard to authorisation procedures … with a view to reducing regulatory and non-regulatory barriers …" (Article 6(1)), and to publish a report on the relevant findings of this evaluation and on actions taken (as described in Article 6(2)). Specifically, Article 6(1) of the Renewables Directive provides:

Member States or the competent bodies appointed by the Member States shall evaluate the existing legislative and regulatory framework with regard to authorisation procedures or the [tendering] pro-



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cedures laid down in … Directive 96/92/EC, which are applicable to production plants for electricity produced from renewable energy sources, with a view to:

• reducing the regulatory and non-regulatory barriers to the increase in electricity production from renewable energy sources,

• streamlining and expediting procedures at the appropriate administrative level, and

• ensuring that the rules are objective, transparent and non-discriminatory, and take fully into ac-count the particularities of the various renewable energy source technologies.

Similar rules relating to CHP can be found in the Article 9 of proposed CHP Directive, with one additional limitation (or objective); namely that the evaluation should be also be con-ducted with a view to "encouraging the design of cogeneration installations to match eco-nomically justified demands for heat output and avoiding production of more heat than useful heat". The proposed amendments to the Electricity Directive (as of June 2002) contain an affirma-tive obligation that is more firm than found in either the Renewables Directive or the pro-posed CHP Directive. Article 5(3) would require that:

Member States shall take appropriate measures to streamline and expedite authorisation procedures for small and/or distributed generation. These measures shall apply to all facilities of less than 15 MW and to all distributed generation.

Recommendations

The provisions in the Renewables Directive provide a good basis for Member States to review and improve their administrative procedures for planning and permitting processes. Given the subsidiarity principle, there is not much scope for additional Commission action at this stage, except that the communications towards Member States should stress that they should start their evaluation in a timely manner to ensure the issuance of a first report to the Commission by October 2003. Within most Member States, however, there is ample scope for improvement of authorisation and permitting procedures depending on specific national administrative systems. Most of the recommendations apply to the local or regional level within the Member States. As a conse-quence of the country specific nature of administrative procedures, the recommendations are stated in general terms. - Permitting or licensing procedures should be transparent and efficient. In some countries,

national planning procedures can be improved on specific issues such as clear reception point for applications, and reasonable deadlines.

- Local authorities should take a lead with a pro-active planning strategy, as is the case in other planning policies such as housing. Integration and thus pre-selection of potential sites for DG use, especially wind power, into spatial plans helps to avoid conflicts be-tween DG use of sites and nature protection, or other uses. In Germany this tool proved successful since on one hand it enables local authorities to channel wind power develop-ment to preferred sites (and simultaneously to bar other sites). On the other hand siting ef-forts for wind developers are considerably reduced.

- The work of planning authorities could be facilitated by improving the database or re-source potential to better enable them to reach balanced decisions. This could for instance



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be done through public inventorying of data on exploitable natural potentials (which is partly done for wind and hydro power) or even heat demand (potentials for small-scale heating grids to be served by biomass or CHP).

- If the competence of local authorities is a barrier, training programmes for personnel that issue the permit could be established.

- Local support is essential, because this is the level where most individual projects are submitted for approval. Public information campaigns could therefore also be used to in-form about the benefits and drawbacks of renewable electricity and CHP.

- Because of the small scale of DG installation and their operators, Member States could introduce fast-track authorisation procedures.

These provisions are already partly incorporated in the Renewables Directive and could also be integrated into the proposed CHP Directive and the amended proposed directive on Energy Performance of Buildings. The European Commission could also require Member States to conduct feasibility studies for CHP ("heat planning", "energy planning" or the like) in re-gional and local spatial planning procedures. This could be a more specific requirement than the current requirement to assess the national potential for CHP as stated in the proposed CHP Directive. Through its energy framework programmes, the European Commission could foster interna-tional exchange programmes on best practices in authorisation procedures.

9.2.2 Local Resistance Despite the broadly accepted environmental benefits of DG, local resistance can be strong. Reasons vary between technologies: source of air pollution closer to the people (CHP, bio-mass), danger of smell (biomass), noise (CHP, wind), ecosystem protection (hydro, wind), integrity of landscape (wind, green field PV) etc. Local resistance can constitute a high barrier to be overcome in a development, since neighbourhood participation rights in spatial planning and licensing/siting processes have generally grown strong, and neighbourhood resistance might also be reflected in non-co-operation of local authorities. In this respect, it can be expected that there is a relationship between a country’s population density and the amount of public opposition – the ‘not in my backyard’ syndrome is less im-portant when there are enough locations available that are reasonably far away from any-body’s backyard. No project failure due to local resistance was encountered in the case studies. However, re-ports of projects (esp. wind and hydro) prevented due to neighbourhood or environmentalist pressure group resistance are numerous e.g. in Germany and in the UK. Difficulties were en-countered in Silbitz (Germany) where the local acceptance was set back by the fact that de-spite of the developer’s wish to communicate the plant as “green bioenergy” the (wood) waste incineration character of the project was a major drawback. There is also some case study evidence pointing in the opposite direction. Several of the stud-ied projects would never have succeeded without the engagement of motivated persons or local/regional authorities. These examples also show several approaches of involving local people in the project.



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The developer of the Lumijoki offshore wind turbine is a company, founded by environmen-tally engaged people from the plant’s neighbourhood. The company issued shares to people that would be mainly environmentally motivated to participate. The developer of Keyenberg wind in Germany also tried to engage the neighbourhood in the project by granting easier ac-cess to investment: the minimum investment for local investors was reduced from 10,000 €to 2,500 €. The investor did not face major resistance against the project. The FIRE study (Langniss, 1998), also concludes that the financial involvement of local peo-ple can help reducing the barriers to renewable projects, because if local people can acquire equity shares of the project, their interest in the project’s success will be large. Another bene-fit is that project developers can – in an early stage – learn from local shareholders what the specific concerns of the local community are, and take these into account. Doyle (2001) even suggests that there would be quite a strong correlation between the share of wind power de-velopment in a country and the degree of local ownership.

Recommendations

The main recommendation, targeted to Member States, in order to reduce public opposition is to involve local actors. Schemes to ensure financial involvement in DG developments or benefits to the neighbourhood can help significantly to reduce local resistance and foster local support. Some examples for such schemes were identified in the case studies and in (Lang-niss, 1998). Table 9-1 presents these schemes and shows that some schemes can be applied by the project developers themselves without intervention from national or regional govern-ments. In this case, ways should be found to communicate this information to them. Table 9-1: Examples of schemes to involve local actors in the development of a DG

project

Scheme for involving local actors Responsible

1. Grant easier access to the financing scheme for local investors, by giving them favourable conditions. For instance the mini-mum share can be lower for local people than for strangers or they receive preferential dividends (Germany).

Project developer

2. Give site owners the opportunity to bring the ground into the project as part of the equity instead of selling it (Spain).

Project developer

3. Offer local owners an arrangement where they get the equity by contributing in kind instead of in cash (Denmark, farmers com-mitting to deliver raw materials).

Project developer

4. Address local people and bodies preferably when acquiring eq-uity (Italy).

Project developer

5. Involve environmental NGOs in the development process (ask them to approve a design and communicate about this)

Project developer

Given the diversity of local and regional conditions, it is probably best to leave the elabora-tion of these activities at the Member State or regional level. Therefore, we recommend Member States to stimulate local involvement by:



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- Starting education and information campaigns to raise interest and informed debate amongst the general public. At the local level, it is important to show non-energy benefits, such as the provision of local jobs.

- Involving national or regional energy agencies in providing and disseminating this infor-mation. Energy agencies could also fulfil a mediating role between project developers and other stakeholder with respect to the recommendations in the above table. The role of re-gional energy agencies is also emphasised in (EEA, 2001). The EU financially supports the establishment of regional energy agencies through its ALTENER and SAVE pro-gramme.

9.2.3 Permitting Problems for Biomass Plants based on wood or waste In most countries, the use of solid biomass relies on industrial waste wood, which triggers the discussion “waste or biomass?” While wood waste is attractive through the negative or neutral fuel price, it has its disadvantages through licensing difficulties and a bad public reputation of waste incineration. In addition the future development of prices for biomass waste / wood fuel is relatively unknown. Permitting problems were observed in the case studies on the Lelystad biomass project (Neth-erlands) and in the Silbitz biomass project (Germany). In Lelystad, the permitting process took one year. Every new biomass project must decide beforehand on the fuel input, be it biomass or waste, in order to obtain a specific license. Most exploiters of biomass installa-tions therefore prefer an open license, to maintain the flexibility to use the cheapest fuel (bio-mass or waste) from the market. However, an open license involves stringent emission de-mands, and requires an exhaust gas cleaning installation, which makes the plant more expen-sive. Another complicating factor is when pre-treatment of supplied biomass takes place in the plant area. In that case, the plant would be considered a waste treatment installation in-stead of a biomass plant. As a consequence, the province (region) instead of the municipality would have to grant the relevant permits. The Silbitz biomass project did have its difficulties in obtaining the operation license, but the processes was facilitated through relatively clear definitions of waste categories in German legislation regarding the eligibility for RES support and on conditions for an operation permit. The plant needs an operation license covering possible emissions to air and water. The permit is to be granted if the emission standards are met and the local pollution standards are not en-dangered. The plant is classified as a type of residues/waste processing plant. This enhances possible public alert, and makes the licensing process more difficult. Authorities were very cautious in the licensing process, which slowed down the process considerably.

EU legislation

In the Renewables Directive the following definition of biomass has been adopted: ‘the biodegradable fraction of products, waste and residues from agriculture (including vegetal and animal substances), forestry and related industries, as well as the biodegradable fraction of industrial and municipal waste’

As far as emission permits are concerned, it has been decided that all fuels that satisfy the above definition, are regarded ‘clean biomass’, and have to comply to the emission require-



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ments in the Directive on limitation of emissions from large combustion plants48. All other biomass and waste streams have to comply to the more stringent regime set up in the Direc-tive on incineration of waste49. At the moment, the EU waste policy lacks clarity on the distinction between waste disposal (removal) and useful application of waste by co-incineration. There is no clear guideline that states a caloric value. The distinction is important, because waste that can be co-incinerated (useful application), is allowed to be transported through Member States, while waste to be disposed may not.

Recommendations

At EU level, the biomass definition as stated in the Renewables Directive has provided suffi-cient clarity. On the other hand, the waste policy should include a criterion to distinguish be-tween disposal and useful application. This should be accompanied by measures that ensure that the waste hierarchy referred to in the Renewables Directive is observed, as creating a caloric threshold for useful waste may divert waste above the threshold from the recycling stream. Again it must be noted that permitting regimes are country specific, and closely related to government structures. Therefore the following recommendations are stated in general terms, and are meant for actors on Member State level. • Clear definitions on waste categories and on licensing conditions may help to overcome

the licensing barrier for biomass plants based on waste materials. • Develop a simple and standard biomass acceptance procedure, based on quality assurance

at the biomass fuel supplier's side, thus relieving the biomass plant operator from the re-sponsibility of demonstrating fuel quality.

• Simplification of the permitting regime will be a great step forward, because the number of different laws and rules that might apply to a biomass installation is very confusing.

48 2001/80/EC of 23 October 2001

49 2000/76/EC of 4 December 2000



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9.3 Grid Connection All generators wishing to participate in the electricity market need to have non-discriminatory access to the use of the transmission and distribution networks. Even for installations operat-ing in island-mode, access to the grid is often required for back-up power. Non-discriminatory access to the grid and transmission and distribution services50 is therefore fundamental to en-sure that DG can compete with other sources of electricity on an equal basis. Consequently, the provision, pricing and regulation of connection to the grid and of transmission and distri-bution network services is very important for the penetration of DG in the EU electricity mar-ket. As the structure of the European electricity markets has been developed from a central-ised paradigm, DG developers and operators often face additional barriers relative to central-ised plants. These barriers to the use of the grid can be distinguished in barriers relating to the connection to the grid and barriers relating to the use of transmission and distribution ser-vices. Barriers relating to the use of system are considered in chapter 9.6.1. The current sec-tion considers barriers to connection to the grid. As the case studies from several countries and technologies illustrate51, negotiations on the costs of interconnection to the network can be a lengthy process, involving contractual mat-ters including liabilities and the allocation of costs for feasibility studies, necessary grid rein-forcements and line extensions. Such issues are covered by regulation in Member States to a different degree52. Furthermore, the technical requirements for connection imposed by the grid operator may be subject of dispute and can cause uncertainty about the cost of connec- 50 Transmission and distribution services refer both to transportation services and to services related to the safe

and reliable operation of the grid, such as frequency control, back-up power provision, voltage support, etc.

51 Some examples from the case studies are:

- Pozoblanco CHP (Spain): The terms of grid access were an important barrier to the development of this project and increased its costs considerably. The project developer wanted to have a connection at the shortest possi-ble distance, but the distribution company would only grant this if they paid for a grid upgrade. Connection was finally granted at a sub-station (which was not the closest possible point) and this made it more expen-sive and bureaucratic because they had to apply for a lot of passage permissions.

- Lastour wind farm, France: the project was complicated by a dispute on costs of both upgrade of existing grid and new line from power plant to grid that had to paid by the developer.

- Lumijoki offshore wind turbine, Finland: The terms of grid access were under heavily dispute with the grid company. The grid connection fee was subject to a court trial.

- St Pancras Housing London (UK) and the public hospital in Ronse (Belgium): In both cases, the project devel-opers anticipated from the outset that the grid operators would make grid connection so difficult that they ruled out the possibility to export electricity to the grid. The resulting design of the CHP scheme dimen-sioned on electricity demand reduced the efficiency and profitability of both installations. In order to achieve maximum efficiency, CHP schemes should normally be designed to meet the heat demand on site, and to ex-port electricity surpluses to the public grid.

52 The COGEN Europe study on administrative obstacles to decentralised CHP (COGEN Europe 1999) identi-fied in three Member States (France, Netherlands and the UK) high connection costs, high costs of grid rein-forcement charged on the CHP developer, complex and lengthy administrative procedures etc. The study em-phasises that CHP developers are faced with many of the same problems in the three countries although imp or-tant differences in rules and general framework conditions also exist.



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tion. Technical issues which are disputed are e.g. capacity of grid, necessary upgrades, point of connection, interconnection voltage, line protection technology, reactive power behaviour and islanding options. Below we analyse the main grid connection issues emanating from the case studies somewhat further.

Connection charges

Negotiations on the cost of connection can often be lengthy process. This is partly due to the lack of transparency in the cost calculation methods. Two main types of connection charges with different economic rationales can be distinguished: shallow and deep connection charges.

• Shallow connection charges only bring into account the cost of line extension to the near-est connection point and the equipment needed to connect the line to the rest of the grid. No charges are made for adjustments, reinforcements and upgrades necessary to facilitate the integration of a generator into the grid beyond the point of connection. The cost of such grid adjustments are recovered by the grid operator through the grid use tariffs and are thus socialised among all users of the grid53. The grid is considered a pure public good. Shallow connection charges can be standardised relatively easily. For example, in the Netherlands the cost of the line from the cut (the point of connection to the grid) to the plant is standardised per meter54.

• Deep connection charges bring into account all the cost of integration of a generator into the network, including the cost of all adjustments beyond the point of connection to the network. Not only will the cost of deep connection charges usually be higher, it will also be much more uncertain as the cost will be highly specific per location, generation capac-ity and mode of operation. Thus the cost have to be independently assessed for each new generator. The methodology of assessing which technical adjustments are necessary and how the cost of these is going to be assessed is often non-transparent. With deep connec-tion charges the costs are not socialised55.

Point of connection

With shallow connection charges a project developer would generally aim to connect to the nearest point on the grid, as this is the cheapest solution from the project developer’s point of view. However, determining the point of connection with deep connection charges is more 53 Shallow connection charges have benefits for DG operators in that they reduce the uncertainty relating to the

cost of connecting to the system. On the other hand DG operators will not be credited for possible benefits they bring to the system. Moreover, if DSOs are subject to regulation that requires them to cut their cost annually they may be reluctant to connect a DG operator when this entails grid adjustments. This disincentive to connect may cause DSOs and TSOs to obstruct or slow down connection procedures

54 Tariff Code 2000, Dte, 2000.

55 Deep connection charges have also been identified as barrier in a recent Ofgem consultation. Interestingly, all the distribution network operators denied that deep connection charging policies constituted a barrier. The view of the majority of generators was that they constitute a significant barrier. See: Ofgem (2002) “Distributed generation: price controls, incentives and connection charging. Further discussion, recommendations and fu-ture action.” http://www.ofgem.gov.uk/docs2002/26distributedgeneration.pdf



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complicated, because the location specific cost of grid adjustments will be taken into account both by the generator and the network operator. Both the project developer and the network company will seek to minimise their cost. This problem of conflicting interests between the grid company and the project developer regarding the point of connection, and the according allocation of cost is illustrated in the case study on the Pozoblanco CHP project. The cost of grid adjustments for different points of connection is related to the costing meth-odology and furthermore depends on existing grid expansion and capacity plans. These plans generally do not account for the connection of decentralised electricity sources. The grid op-erator has an interest to align the point of connection and the technical adjustments as much as possible with the existing grid structure and plans for grid expansion and upgrades. The DG operator on the other hand merely wishes to minimise their cost of connection.

Safety and liability issues

The power system is a complex web of assorted hardware, including generators, power lines, substations, transformers, switches, breakers, fuses, and other components, including users’ loads. All this operates in a synchronous mode, using 50 cycles per second in Europe. Rules and standards for grid connection are aimed at maintaining the reliability and integrity of this electrical power system. The question is whether these rules are adequate or too strict. Part of the problem is that, historically, electricity systems have been conceived to be operated in a centralised manner and the utility operating the network was used to deal with big centralised generation plants and had little experience with smaller ones. In such a system the power flows in only one direction: from the power station to the network and to the customer. Some utilities are still used to this traditional centralised approach of distribution of electricity, and grid connection requirements are often designed to be appropriate to big units of a few hun-dred MWe, but not to small ones. Moreover, grid operators are responsible for a safe and reliable operation of the network. As they are often under pressure of price regulation they will try to shift as many of the costs and risks of safety measures to the users to the grid, mainly to producers. The cost of safety meas-ures related to network connection may entail special safety and contingency equipment in the connection to the grid and adjustments elsewhere (in the case of deep connection charges), demands on the operation of the plant, etc (ADL, 1999). Necessary safety measures are gen-erally determined by the grid operator taking a very risk averse approach. Moreover, a con-nection contract may specify conditions on the liability in case safety conditions are not met by the operator of a plant. The safety requirements on equipment and operation can compound the cost of connection. Moreover, the basis of establishing the necessary measures is not al-ways transparent.

Lack of transparency

When establishing the cost of connection to the grid it is important that both the procedures for requesting and negotiating connection and the cost assessment methodology are transpar-ent and non-discriminatory. Whenever they are not transparent the scope for discriminatory practices is also larger. As described in the paragraph on connection charges grid operators may have incentives to obstruct connection by delaying the connection procedures in the case



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of shallow connection charges. Moreover, the case studies provide a number of examples where connection was delayed by the grid companies. Clear procedures (including deadlines) can reduce the scope for this kind of antagonism. Furthermore, in the case of deep connection charges the transparency of the methodology of establishing the technical needs for grid ad-justments and the costing of these adjustments is key to the negotiation on grid connection cost between the generator and the grid operator. The Netherlands, UK and Norway are amongst the few exceptions, where information on grid connection costs is publicly available. In the absence of any standard conditions, new entrants will face uncertainty with regard to the cost of connection. This uncertainty constitutes a barrier for any new CHP and RES pro-jects. On the other hand clear cost allocation rules between developer and (distribution) grid opera-tor have proved to reduce uncertainty, thus facilitating DG development (cf. e.g. case studies Tzschelln hydro (D), Keyenberg wind farm (D), Silbitz biomass (D)). In these cases, the German Renewable Energies Act stipulates that only direct connection costs have to be borne by the developer, while grid reinforcement costs are to be borne by the grid operator. In addi-tion, a clearing office has been installed at the German Ministry of Economics for the settling of further disputes and ambiguities.

Business practices

It is not perceived to be the core business of grid operators to facilitate and optimise the inte-gration DG into their networks. The priority is the operation of the grid and maintenance of the assets. Furthermore, there is no incentive structure to stimulate the fast and efficient han-dling of connection procedures. Therefore, connection requests by DG have a relatively low priority.

Benefits of connection

Benefits of connection of DG may arise from deferral of transmission and distribution net-work upgrades and expansion, decongestion, improved local reliability, and the provision of ancillary services to the grid56 (Van Sambeek, 2000). These benefits are usually not reflected in the connection charges, which only take into account the cost of connection. Particularly in the case of deep connection charges there is scope to take into account the benefits of decen-tralised capacity, as the methodology of assessing the (full) cost of connection including nec-essary adjustments beyond the point of connection (cut) is more geared to also incorporating the benefits of avoided future upgrades and capacity expansion. However, it depends on the type of regulation on the grid companies whether or not the grid company has an incentive to pass these benefits on to the DG operator. For example, when the grid company is subject to price regulation (such as in the Netherlands and the UK) and if a grid company may incorpo-rate the benefits of deferred upgrades/expansion in its rate base, then it has a clear incentive to connect DG where such benefits are likely to accrue. The only thing that regulation needs to

56 The costs and benefits from DG to the grid can be measured against the cost of providing grid services accord-

ing to the centralised capacity plans. Deferring of avoiding (parts of) the implementation of these plans may lead to cost reductions (benefits), while necessary extra reinforcements may increase the cost of connecting.



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do in that case is to make sure that the benefits are shared between the DG operator and the grid company.

Lack of price signals

DG operators seek to minimise the cost of connection to the network. Network operators also seek to minimise the cost of connecting DG to their network and seek to minimise the amount of effort involved in handling connection requests and in integrating DG in their grid plan-ning. As described before the aims of both actors are often difficult to reconcile as a result of non-transparent procedures and cost assessment procedures. Above it is indicated that trans-parent cost assessment methodologies and connection procedures can facilitate the negotiation on grid connection between the DG operator and the network operator. However, this negotia-tion only takes place after a connection request has been submitted for a specific location, which cannot take into account the full additional cost or benefits to the network. Both the network operator and the DG operator could benefit greatly if the cost of connecting to the network per location are known in advance. For example, the network operator could indicate on which locations it would like to encourage or discourage the connection of DG, and pro-vide incentives through the connection charges accordingly. This means that where connec-tion to the grid entails a benefit, e.g. though avoided or deferred grid investments, DG opera-tors receive a bonus for connecting57. Likewise, where there are cost associated to connecting a generator beyond the point of connection (cut), e.g. necessary grid reinforcements, there should be an indication on the size of these costs to provide DG operators incentives to con-nect elsewhere. By providing clear geographically differentiated incentives for the connection of DG to the grid, connection can be done in a more optimal way, while minimising the cost to the DG operator and the grid operator. Moreover, transparency on the feasibility and cost of connecting on a specific location will provide more ex ante certainty to DG project developers on the feasibility of their project.

DSO (Distribution System Operators) incentives

The incentives arising from price regulation on network companies determines the attitude of grid companies to the connection of DG. Most network companies in the EU are subject to some kind of price regulation. The price that can be charged for transmission and distribution in these regulatory models is based on the operational cost, the capital cost and an allowable return on capital. Thus the main issue is how grid connections and reinforcements are incor-porated in the asset base of grid companies. Furthermore, DSOs mostly charge fees for trans-porting electricity in one direction from the transmission system to the consumer (Mitchell, 2000). If demand diminishes due to DG the capital cost per kWh distributed from transmis-sion to the consumer increases. However, when the distribution fee is fixed (or discounted each year, such as in the UK and the Netherlands) the DSO reduces its return on capital. The DSO may therefore have an incentive not to connect DG in the first place. Price regulation should thus be altered in such a way that this discriminatory effect on DG is removed.

57 Preferably based on the actual benefit incurred to the system.



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Co-ordination of spatial planning and network planning

The location of DG projects is often constrained by spatial planning and resource availability. This is particularly the case for RES projects using wind and biomass resources. In response to the challenge of integrating wind development sites into spatial plans and overcoming local resistance to wind parks governments at various levels have moved to appoint specific loca-tions within their jurisdiction for wind development. The sites that are appointed on this basis or that most eligible from a resource point of view are not always the most optimal sites from a network integration point of view, thus raising the cost of implementation through connec-tion charges. It would therefore be prudent to seek co-ordination between the designation of wind and other DG development sites and the cost of connection at various locations. Of course, for this it is necessary that the cost of connection are known to those involved in spa-tial planning. Ex ante price signals in the network could greatly enhance transparency in this regard. Vice versa, it would be commendable to take the designated wind/DG development areas into account in the grid planning by network operators. This can minimise the cost of integration of DG into the network in the long run. This is not to say that the integration of DG will always lead to a least cost electricity planning option. Indeed there may be extra cost involved in taking DG into account. How to allocate these cost between the users of the net-work (shallow connection charges) and the DG operator (deep connection charges) will have to be discussed in the framework of national electricity regulation.

EU legislation

The EU Renewables Directive is the most significant and specific EU legislation on the mat-ter of grid connection issues. This binding legislation is substantively linked with the Euro-pean Commission’s proposed directive on CHP, which contains a section on “grid system issues” that is very similar to the section in the Renewables Directive. In brief, the binding obligations relating to grid system issues under the Renewables Directive require Member States to adopt a legal framework or require distribution system operators (and TSOs):

• to set up and publish their standard rules on the bearing of costs of technical adaptations, such as grid connections and grid reinforcements (Article 7(2));

• to provide any new producer wishing to be connected with a comprehensive and detailed estimate of the costs associated with the connection (Article 7(4)); and

• to set up and publish their standard rules relating to the sharing of costs of system installations, such as grid connections and reinforcements, between all producers benefiting from them. (Arti-cle 7(5)).

The obligations relating to cost-sharing rules in Article 7(5) represent a new element of EU electricity legislation: equivalent rules do not appear in the Electricity Directive or the current proposed amendments to the Electricity Directive (as of June 2002). Specifically, Article 7(5) of the Renewables Directive requires a mechanism that takes into account the benefits that “initially and subsequently connected producers … derive from the connections”:

Member States shall put into place a legal framework or require transmission system operators and distribution system operators to set up and publish their standard rules relating to the sharing of costs of system installations, such as grid connections and reinforcements, between all producers benefiting from them.



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The sharing shall be enforced by a mechanism based on objective, transparent and non-discriminatory criteria taking into account the benefits which initially and subsequently connected producers as well as transmission system operators and distribution system operators derive from the connections.

The implementation of these cost-sharing rules in the Member States will most likely take place as part of the development of the overall set of rules applying to connections and con-nection costs. Article 7(2) of the Renewables Directive sets forth the Member State obliga-tions in this respect:

Member States shall put into place a legal framework or require transmission system operators and distribution system operators to set up and publish their standard rules relating to the bearing of costs of technical adaptations, such as grid connections and grid reinforcements, which are necessary in or-der to integrate new producers feeding electricity produced from renewable energy sources into the interconnected grid.

These rules shall be based on objective, transparent and non-discriminatory criteria taking particular account of all the costs and benefits associated with the connection of these producers to the grid. The rules may provide for different types of connection.

In other words, we can distinguish between the Directive's rules on "cost-sharing" and rules on "cost-bearing" in the area of connections. The latter is the general category, whereas the former is a refinement or subset of the latter. Both types of rules seek to refine the rules apply-ing in the Member States to the allocation of costs of connections for producers using RES. is a refinement or subset of the latter. Both types of rules seek to refine the rules applying in the Member States to the allocation of costs of connections for producers using RES. Similarly, the Article 8 of the proposed CHP Directive would introduce obligations relating to connec-tion costs and cost-sharing rules similar to Articles 7(2) and 7(5) of the Renewables Directive. These more specific rules in the Renewables and proposed CHP Directives are a considerable improvement over the relevant provisions relating to connections in the present Electricity Directive. As has been duly noted, the Electricity Directive's rules on operation of the trans-mission system require the system operator to draw up clear technical rules on interconnection (Art. 7(2)). A similar rule does not apply to distribution system operators. Improvements in the Electricity Directive can be expected in light of the Commission's pro-posals of June 2002. The proposed amendments to the Electricity Directive would require (under Article 22(1)(g)) that national regulatory authorities monitor the electricity market with respect to “terms, conditions and tariffs” for connections:

Member States shall designate one or more competent bodies as national regulatory authorities. These authorities shall be wholly independent of the interests of the electricity industry. They shall at least be responsible for continuously monitoring the market to ensure non-discrimination, effective competition and the efficient functioning of the market, in particular with respect to:

….

the terms, conditions and tariffs for connecting new producers of electricity to guarantee that these are objective, transparent and non-discriminatory, in particular taking full account of the benefits of the various renewable energy sources technologies, distributed generation and combined heat and power.

Further explanation of the rationale for this proposal is provided in the Commission's explana-tory memorandum of June 2002:



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Amendment 57 [of the European Parliament] states that costs of connecting producers of electricity from renewables and combined heat and power shall be objective and non-discriminatory. The Commission is of the opinion that the costs of connection of all producers should be non-discriminatory, but that, in addition, the specific characteristics and the costs and benefits of connect-ing producers from renewables and combined heat and power to the grid should be taken into ac-count. This is reflected in Article 22. The explicit reference to ensure no obstacles exist to the stimu-lation of dispersed generation, is taken on board in Article 22(1g) as well, where the regulators shall monitor the measures taken by Member States to ensure that the benefits of connecting renewables producers and distributed generation to the system are taken in account. (Article 22(1g) electricity).

On the technical side, under the auspices of the European Committee for Standardisation CEN, a European-wide standard on requirements for grid connection for micro-cogeneration systems for domestic use and with installed capacity up to 10 kWe is currently under devel-opment58. Initially, this standard will not be established as a full-fledged EN norm, but as a so-called CEN Workshop Agreement (CWA). This project would be a first step to the crea-tion of cheap, reliable, and safe standards in the domestic micro-CHP sector. Obviously, this sector is only a limited segment of the total DG market. The development of technical stan-dards for other types of DG installations is still to be addressed.

Recommendations

The Renewables Directive provides a legal basis for the Member States to take steps to accel-erate the removal of barriers to network access and the associated costs allocated to producers of renewables-based electricity. The related national administrative actions or procedures (e.g., the formation of working groups on DG or the institution of formal regulatory reviews by regulators) can easily be extended by the relevant national authorities to cover other forms of DG. With respect to the reporting obligations under the Renewables Directive, Member States should observe their reporting deadline of October 2003. • As a first step to improving access to the grid, transparency on connection procedures and

cost assessment methodologies, as well as the cost of connection at various locations in the grid should be improved. This will provide more certainty to project developers as to the cost of grid access that may be anticipated in the implementation of a project and re-duce project risks.

• Second, due to the lack of transparency on cost assessment methodologies, it is not always clear whether the costs are assessed in an economically efficient manner. Cost assessment should take least cost central capacity planning as the baseline/benchmark against which the costs should be assessed. Consequently, after the costs have been accurately deter-mined according to efficient economic principles, rules have to be devised to distribute the cost amongst the users of the grid. Preferably these cost allocation rules should follow the principle of economic efficiency. However, it is recognised that if this path is followed (e.g. through deep connection charges) the cost of connection to the grid may become pro-hibitively high to certain DG/RES investors. Therefore, in view of the aim to increase the share of RES in the internal market, and to improve the effectiveness of support policies to this end, it may be commendable to socialise part of the cost of connecting DG to the grid. In finding the balance between socialisation of cost and direct attribution of cost to DG operators the principles of equity and fairness to market actors and consumers/society should be taken into account.

58 http://www.cenorm.be/standardization/tech_bodies/workshop/otherthanict/ws5.htm



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Based on the above, we can identify five general criteria for improving regulation with regard to grid access for DG. These are transparency, economic efficiency, effectiveness, equity, and predictability. These principles should also be taken into account in the monitoring of the policies and regulations put into place by the Member States pursuant to Article 7 of the Re-newables Directive. These criteria can be put into operation to respond to the barriers identi-fied above in the following ways:

• There should be uniform technical standards for interconnection to the grid. This would reduce the scope for dispute on the technical requirements associated with grid connec-tion. In the process leading to this standardisation, it is important that all relevant stake-holders are involved in the discussion so that the standards do not introduce a bias in fa-vour of any particular party.

• There should be transparent and efficient rules relating to the allocation of costs of techni-cal adaptations, such as grid connections and grid reinforcements to all users of the grid, including future generators. More specifically, these rules on allocation of costs should define not only the respective obligations of the DSOs and the DG producers (cost-bearing rules)59, but also the framework for determinations to be made on the sharing of costs among initially and subsequently connected producers (cost-sharing rules).60

• There should be clear procedures and norms for dispute settlement in case of disagreement on the cost of connection. To enforce these procedures and norms and to provide a deposi-tory for complaints, an independent dispute settlement entity can be established by the Member State governments. The national energy regulators can also fulfil this function.

• System operators should publicly provide an ex ante indication of favourable and prob-lematic sites for grid connection based upon geographically differentiated price signals to DG project developers. The Electricity Directive can be amended in Articles 9 and 12 to require Member States to ensure that information on free grid capacities is made available to developers of new capacity while respecting confidentiality. The national regulators can require DSOs and TSOs to provide such information publicly, for example through their websites.

• Price and quality regulation should provide incentives to network companies to deal with connection requests in a fair and efficient manner. Two issues play a role here: first, a

59 Examples of cost-bearing or cost allocation rules can be seen e.g. in Germany and Denmark. In Germany, for

grid connection of new RES capacity covered by the Renewables Energies Act, all costs incurred by necessary grid reinforcements are borne by the grid operator, while direct connection costs are borne by the RES devel-oper. In Denmark, however, grid extension for the connections of off-shore wind farms are considered a public good, and thus borne by the grid operator.

60 In the United Kingdom, amendments made in the spring of 2002 to the Electricity (Connection Charges) Regulations require an electricity distributor to recover certain amounts from subsequent users of electric lines and plants first provided to another person in making an initial connection, such that refunds can be made to the person who previously had to bear the expenses of the initial connection. At present, these rules allowing partial reimbursement of initial contributors only apply to households (domestic premises). The regulator OF-GEM has taken action in June 2002 to extend the reimbursement mechanism to DG as part of the wider initia-tive to remove inappropriate charges and perverse incentives that might inhibit the development of DG.



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network company should not have any economic incentive to avoid DG connection, and second, business practices should be encouraged to take a proactive and service oriented stance towards facilitating DG connection. Both aspects need to be taken into account by national regulators in defining the regulatory models for network companies.

• Co-ordination between spatial planning, network planning and RES interconnection. The interactions between spatial planning, network planning and RES siting and interconnec-tion are numerous and cross various administrative levels. In order to achieve good co-ordination good co-operation between the administrative bodies, network companies and regulators, is necessary. Most likely several iterations in adjusting all these planning ef-forts are necessary to minimise the overall cost of network expansion, DG implementation and ensure public acceptability. This recommendation is particularly addressed to local and regional governments, TSOs, DSOs, Member State governments, and regulators.

• The EU should undertake responsibility for setting technical specifications to impose safe and realistic grid connection requirements for decentralised producers which would be less restrictive. To be effective, the specifications should be safe and fit for the purpose, low-cost, reliable and widely accepted. Such requirements could be issued as EN norm through Cenelec, the European Committee for Electrotechnical Standardisation. The European Commission should support the definition of such standards by initiating ex-change programmes and projects on this matter.

The UK provides a first example of how some of these recommendations can be implemented at the Member State level. In March 2002 the UK energy regulator Ofgem published propos-als outlining short and long term measures to provide a fair and transparent regulatory regime for distributed generation61. The proposals for immediate action include: • as an interim arrangement, prospective decentralised generators should have the choice of

paying the costs of connection ‘up-front’ or paying only for the ‘shallow’ costs in this way, the balance being collected through an ‘annualised connection charge’ negotiated with the DSO.

• making it easier for domestic Combined Heat and Power (DCHP) customers, who have a heating system which can generate its own electricity, to connect to the networks by estab-lishing a standard set of procedures

61 Ofgem (2002) Distributed generation: price controls, incentives and connection charging. Further discussion, recommen-dations and future action.



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9.4 Market Access and Contracting Liberalisation and restructuring of the electricity markets in the EU has been vastly increasing the possibilities of old and new actors in the electricity sector for contracting. In principle this also applies to the possibilities of decentralised generators to contract their output. To reap the full benefits of trade and competition, with the associated plurality in contract forms, strict unbundling of generation, trading and supply from transmission and distribution activities is a pre-requisite. Non-discriminatory access to the market (e.g. electricity exchanges) and grid services is of key importance. However, strict unbundling is no guarantee for a level playing field for decentralised generation in the internal market. Many barriers with respect to the physical interconnection of decentralised generation remain even in a strictly unbundled in-dustry. Furthermore, grid use tariffs may also discriminate in favour of centralised generation. In addition, electricity markets have always been developed from a centralised perspective. Therefore these markets often do not take the specific characteristics of decentralised genera-tion into account. The terms of market access and the design of the markets may thus put de-centralised generation at a disadvantage compared to centralised generation. In other words, there is no level playing field between centralised and decentralised generation. Below a number of issues relating to market access and contracting possibilities for DG in liberalising electricity markets are elaborated in more detail.

9.4.1 Balancing and Settlement Systems Balancing and settlement systems serve to maintain system balance and to provide a system for the settlement of the cost incurred in maintaining system balance. At the basis of a balanc-ing and settlement system is the responsibility for certain actors in the electricity supply chain to balance their own or another party’s supply and consumption. This is referred to as balance responsibility. Failure to meet this balance responsibility results in penalty payments. The level of these penalty payments may be determined through a balancing market in which short-term electricity supply and demand bid in order to restore system balance. Several coun-tries have now instituted such a balancing market. Balancing markets and associated settle-ment systems are an important condition for the liberalisation of electricity markets as they provide in the freedom for generators and consumers to select the party to whom they want to transfer their balance responsibility. The free transfer of balance responsibility is important for contract freedom as contracted power has to be balanced on both the supply and demand side. As liberalisation proceeds and the electricity market is further opened more and more generators and consumers are given balance responsibility. The main problems with respect to the integration of DG into balancing and settlement sys-tems is that intermittent RES (solar, wind) and heat driven CHP cannot always adjust their loads to match a pre-specified load pattern as stipulated in bilateral power contracts or as bid into the spot market a day ahead. This results in high penalty payments for these sources in the settlement process. These imbalance cost reduce the value of the electricity that is pro-duced from these intermittent sources. This loss in value in turn needs to be compensated through support mechanisms or in the market for renewable energy.



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Example: New Electricity Trading Arrangements in the UK

The problems above are particularly important in the UK under the New Electricity Trading Arrangements (NETA), and also in the Netherlands. The example of NETA will be used as an illustration. The scheme was introduced in early 2001. NETA is based on bilateral trading between generators, suppliers, traders and customers, and include long-term forward and fu-tures markets, a short-term power exchange, a balancing mechanism to ensure system stabil-ity, and settlement rules. The balancing mechanisms and the settlement rules are incorporated in the Balancing and Settlement Code (BSC). Under the balancing mechanism, participants are asked to give estimates of their likely electricity production. If their real production is be-low the estimate, they have to buy additional electricity from the balancing mechanism. If they produce more, they spill their surplus into the grid. In both cases, they are penalised un-der the settlement rules, because the feed-in price they receive is very low, and the top-up price can be extremely high. In general, generators prefer to have a position of overproduction and spill electricity into the system, rather than having to buy expensive top-up electricity. Under NETA, CHP producers that chose to contract ahead in bilateral markets participate in the balancing system. This has, however, often damaging effects, because their electricity output is designed to follow the heat load and therefore often not sufficiently predictable. In order not to be penalised, most CHP producers have chosen not to participate in the balancing system. The same problems have been reported from the Netherlands. Decentralised CHP producers in particular could also join with other decentralised generators and aggregate their electricity output. The co-operation with specialised intermediate agents like green power traders, certificate traders or associations of intermittent producers could potentially provide relief from the need to participate actively in market schemes. This would imply additional costs but allow them to respond better to the balancing system. It has, how-ever, been reported that there are not enough such services offered under NETA. This raises doubts whether aggregation is a commercially attractive and viable option in this case. Most CHP producers in the UK have therefore chosen for a contract with suppliers to sell their output locally. This situation compares with the previous situation, before electricity market liberalisation. However, less local distributors seem to be willing to take the risk of having CHP generators in their production portfolio, because they see them as a risk factor in a system that heavily penalises imbalances. The example of NETA shows that the design of electricity trading schemes and particularly the associated balancing and settlement systems can seriously reduce the commercial value of the electricity output from decentralised CHP, and thus the economic viability and survival of these schemes. It also shows that the effort to participate in any electricity market can consti-tute a high hurdle for decentralised CHP producers. These problems could explain why a re-port from the UK's electricity regulator OFGEM on the impact of NETA on small generators has shown that average output from small generators dropped by over 40% in the 3 months since NETA came in, up to 60% for CHP62. NETA therefore has seriously reduced decentral-ised electricity production in the UK. 62 OFGEM (2001) Report to the DTI on the Review of the Initial Impact of NETA on Smaller Generators. Pub-

lished on http://www.ofgem.gov.uk/docs2001/52_small_gens_review.pdf



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EU legislation

One response to the balancing problem for DG operators is to use the possibility of priority dispatch under the Electricity Directive and Renewables Directive, as described below. Under priority dispatch, renewable and CHP electricity may be exempt from their balancing respon-sibility. Effectively this means that other actors are required to assume balance responsibility on their behalf. Furthermore, eligible generators receive a price for the electricity they deliver to the grid. This price may be the market price, the avoided cost to the utility, or a higher premium price, while the power (including the respective payment obligation) is passed on to all power traders as a Public Service Obligation, or to captive customers. The Electricity Directive explicitly opens up the possibility for Member States to require (transmission and distribution) system operators, when dispatching generating installations, to give priority to generating installations using renewable energy sources or waste or producing combined heat and power in Articles 8(3) and 11(3). This is merely an option for Member States to consider, and its use would constitute an exception to the normal rule that the dis-patching of generating installations should take place on the basis of criteria, which take into account the economic precedence of electricity. The Renewables Directive goes further by requiring, in Article 7, transmission system opera-tors to give priority dispatch to generating installations using renewable energy sources "inso-far as the operation of the national electricity system permits". Furthermore, Member States shall take the necessary measures to ensure that TSOs and DSOs in their territory guarantee the transmission and distribution of electricity produced from renewable energy sources, and they may also provide for priority access to the grid system for such electricity. The proposed CHP Directive contains only the equivalent of the first sentence of Article 7(1) of the Renewables Directive: it would require that the Member States shall take the necessary measures to ensure that TSOs and DSOs in their territory guarantee the transmission and dis-tribution of electricity produced from cogeneration. It appears that the proposed amendments to the Electricity Directive (as of June 2002) would not explicitly impose further prioritisation obligations. It appears that the proposed amendments to the Electricity Directive (as of June 2002) would not explicitly impose further prioritisation obligations.

Discussion of the instrument priority dispatch

As long as DG constitutes only a small fraction of electricity production, priority dispatch can be a useful instrument to shield DG from the effects of market mechanisms that have been tailored to centralised supply. However, as the share of DG increases so do the imbalances caused by these sources, and consequently the cost of these imbalances to the operation of the electricity system. Not allocating these costs to the sources that cause the imbalances will provide no incentive to intermittent generators to improve the controllability or predictability of their electricity supply. This is, however, needed in view of the longer term development of the electricity system. In Denmark approximately 15% of total electricity consumption is by now covered by wind-generated power production. However, wind power capacity is unevenly distributed at the two separate power supply systems in Denmark and therefore more than 20% of total power con-



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sumption in the Western power area is supplied by wind power and only approximately 8% in the Eastern supply area. Now and then this causes economical and technical problems in the Western area. Economical problems are encountered when unexpectedly much wind power is supplied to the power system and the systems operator has to sell this “excess” production at the Nordic power market to a low price. Through the Public Service Obligation this loss will have to be covered by all electricity consumers. Technical problems might occur when wind power generates an excess supply at a time when all available power transmission lines from Denmark are utilised to the limits for export and when conventional power plants already do operate at the lowest possible production. Presently the systems operators are analysing pos-sible actions to be undertaken in this case to prevent the technical power system from becom-ing unstable or in a worst case to break down. Another problem associated with priority dispatch is the valuation of the electricity. Most priority dispatch schemes are linked to feed-in tariffs. The basis for the feed-in tariff can be the avoided cost to the utility, a premium price based on the energy source, or some kind of proxy for the price of wholesale power. As becomes clear from these examples the valuation of the electricity from DG is not through the market. Thus, in two ways priority dispatch keeps DG out of the market of which it is ultimately to become part: 1. Exemption from balancing responsibilities 2. Valuation of electricity from DG is not based on the market Thus in the medium-term as the share of RES and CHP in the internal market increases (given the EU targets of 22% and 18% respectively) electricity policy should be targeted towards integrating intermittent RES and CHP in the balancing and settlement system. More research as to how this may be done is needed. In the mean time the priority dispatch provision can be used to temporarily exempt intermittent sources from their balancing duties. In the medium run, however, as the share of RES increases, the cost of this exemption to the rest of the sys-tem may rise to the level where a solution needs to be found to integrate intermittent RES in the balancing system.

Recommendations

To overcome the barriers to the contracting of DG and to minimise the cost of integration of DG in the electricity market there are several measures that can be undertaken. • Priority dispatch: in the short term, priority dispatch can be a feasible measure to reduce

the cost of balancing and contracting to DG developers and operators.

• Research on technical solutions to imbalances: due to the intermittent nature of mainly wind real cost are incurred by the electricity system as a whole. These costs are not re-solved through priority dispatch. In order to enable DG operators to limit imbalances re-search technical solutions to these imbalances (e.g. storage) is needed.

• Research on market solutions to balancing problems: As described before, in the short run priority dispatch may be a mechanism to shield DG from the effects of balancing and set-tlement systems which have not been geared up to integrate DG. However, as the share of RES and CHP in the generation mix increases so will the need to integrate these sources into balancing systems. More economic research should be directed at how intermittent renewables and CHP can be treated in balancing and settlement mechanisms.



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9.4.2 Transaction Costs Most DG projects are small-scale projects, developed and operated by small-scale actors. Due to the small scale of most DG projects transaction costs of participating in power markets and complying with the balancing and settlement system are often high. Whilst their core business is not electricity generation, they would need to get acquainted with the trading system and rules, and spend additional resources in participating in the trading systems. In order to profit from the possibilities of the power market, transaction cost should be lowered and DG should be allowed to participate in the balancing market. Most DG developers and operators in the case study pool are rather small actors compared to typical utility size actors. Combined with the fact that most projects are small scale by them-selves as well, the transaction cost for contracting are relatively high compared to bulk power trading. The main conclusion that can be drawn from the case studies is thus that because of the small scale of the project and the RES operator transaction cost of contracting output per unit of power delivered are relatively high compared to centralised production.

Recommendations

Aggregation of DG output can reduce the transaction cost of contracting. Furthermore, aggre-gation can reduce the cost of imbalances in the balancing and settlement system, first of all because a designated party that assumes balancing responsibility for a whole portfolio of DG can afford to build up knowledge on the balancing system and actively participate in it. Sec-ond, imbalances may average out in the aggregation of loads and predictability of aggregated production may increase. An additional problem in some countries is the lack of availability of momentary load and price data to DG operators. Because of this lack of information they are not able to respond to changing market and balancing situation on the system. It can be anticipated that in the short run it is not feasible to give every small actor access to all market and system data at low cost. For example, membership fees to power exchanges are still prohibitively high. Once again, aggregation of supply can provide a solution to this problem. The structure of the power market should allow for this kind to aggregation to take place, for instance in the framework of power exchanges and balancing and settlement systems.

9.4.3 Gas Liberalisation In the context of contracting the DG installations fuel and production, the Gas Directive is of relevance, too. Article 18(2) of the Gas Directive requires Member States to designate all gas-fired power generators as eligible customers. However, gas consumption thresholds for CHP installations may be introduced which then prevent certain CHP installations’ eligibility. Such a threshold would, if implemented63, contribute to a market distortion between gas-fired power producers above and below the threshold. However, the Amendment Proposals fore-sees that in the course of an accelerated market opening all non-domestic customers, includ-ing CHP operators, shall be eligible customers as of 1st January 2004 as the latest. Thus, the 63 According to COGEN Europe, the Netherlands, France, Denmark and Spain have made use of this provision

and have introduced threshold values.



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present distortion would, provided the amendment being adopted, disappear in a reasonable timeframe.

Recommendations

The option to discriminate CHP installation against other gas-fired generators should be re-moved from the Gas Directive. Thus the Commission’s Amendment Proposal which contains this removal is to be supported.



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9.5 Financing Starting point to the discussions on financing DG is the principle that in the long run, DG should be integrated into current electricity markets not through subsidies or support mecha-nisms, but rather upon the recognition of the environmental and other values of DG and the internalisation of external costs. Renewable energy and CHP technologies are often characterised by high capital require-ments. This capital carries a cost in the form of dividend, interest and debt payments. The costs and financial feasibility of renewable power projects are therefore particularly sensitive to the financing conditions. Key to financing any project are the expected future cash flows. These cash flows principally depend on the contracting possibilities, support mechanisms, and market developments. In addition, the financial risk (certainty of the cash flows) and the tech-nical risk of a project plays an important role. The market structure and applicable regulatory regimes therefore directly and indirectly affect the financing conditions.

9.5.1 Financing Issues, Barriers and Solutions At the moment, most RES projects are economically viable only with support mechanisms. However, even with support mechanisms the profitability of RES projects is often rather low compared to alternative investment options. This reduces the attractiveness of financing RES projects. In addition, many RES projects are relatively small compared to other utility invest-ments, which increases the transaction cost of financing. Many investors also perceive the technical risk of RES projects as high. The small size of projects, the perceived technological risk, the low returns and the relative unfamiliarity of financiers with RES projects increase the cost of financing. A new and unique financing solution has to be found for every project. Fi-nancing therefore often relies on committed actors, which are not solely and primarily moti-vated by profit, but also by local and environmental concerns. Like in the case of decentralised RES, the profit margin of small CHP projects is compara-tively small. Furthermore, a key barrier to the financing of CHP projects is the risk due to the current energy market conditions: unpredictability, instability, unfavourable gas-electricity price ratio, and lack of integration of external environmental costs of energy production in the market prices for energy. In this context, it must be mentioned that recently, Awerbuch (2000) and (Lovins, 2002) have argued that the attributes of DG technologies, especially their vulnerability to risks, are pro-foundly different from those of traditional centralized technologies. Therefore, this should be recognized explicitly in financial evaluations and comparisons. Simply adopting more appro-priate techniques of financial analysis, i.e. a portfolio approach using risk-adjusted valuation procedures, would dramatically alter the comparison between traditional and innovative gen-eration, in favour of DG. Some developers in the case studies, who used project financing, had difficulties in providing loan security. Examples are found in the case studies on the Lumijoki wind plant (Finland), WISTA PV plant (Germany), Port Mort hydro plant (France), Harboøre biomass CHP and Boeschistobel landfill gas CHP. Lenders have strict and demanding requirements on income from projects that are often very difficult to meet, because of uncertain policy and market



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developments. This introduces a relative bias towards equity finance, which in turn becomes less attractive as profit and tax benefits are spread out over more equity, thus lowering the return. Stable market conditions can soften some of the loan conditions, increase the debt ra-tion, and thus lower overall financing cost. However, most case studies did not encounter any significant problems in financing. This was mainly due to feed-in tariffs, which provided long-term revenue security to the projects under consideration.

EU legislation

EU legislation does not directly provide common rules on the financing of DG projects, al-though the EU Treaty rules on state aid are applicable to the various support mechanisms and other benefits to the extent they constitute state aid. As indicated above, most RES and CHP projects are dependent on support schemes for fi-nancing. In most Member States, support schemes seem to be subject to frequent changes. These changing market conditions can cause significant uncertainty about the future value of a project, and can complicate financing. The Renewables Directive provides a basis for the development of a harmonised framework for support schemes and the creation of a single market for RES. The Renewables Directive also establishes indicative targets for the penetra-tion of RES for each Member State. To meet these targets Member States are rapidly develop-ing their national renewable energy policies.

Harmonisation of the renewables support framework

Renewables Directive, uncertainty arises about the shape of future policy frameworks in cer-tain Member States. As described above, the policy conditions and support framework for renewables and the rest of the electricity market are fundamental to the risk and financing of RES projects. Currently, in many EU countries regulatory risk is one of the major complicat-ing factors in financing. Not only can this potentially stop or delay projects, it also raises the cost of financing as increased risk needs to be compensated by increased returns. To minimise the cost of financing financiers would benefit from stable long-term policy conditions. In view of the current policy and market developments in the Member States it can be antici-pated that the required regulatory certainty for low-cost project development is some way away from us in several Member States. Through the international trading of RES the policy conditions affect not only the value of renewable energy in their own countries but also in the other Member States. As a the trading of RES across the EU is likely to increase, the effec-tiveness of policies will be more and more dependent on policies in other countries. There-fore, in the transition to a harmonised support framework and EU market for RES, regular adjustments to the national support mechanisms may be made to compensate for the effects of policy developments in other Member States. This could lead to prolonged fragmentation into national markets. Furthermore, it causes the value of RES to vary as policies adjust. This pol-icy-induced uncertainty regarding the value of RES in the Member States complicates financ-ing and increases the risk premium. Investors in countries which have a support framework that is not linked to the trading of RES or green certificates, such as feed-in systems, will perhaps be less exposed to this regulatory



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risk pertaining to policy interactions between Member States. Nevertheless, the effectiveness of such policies to reach their policy targets will be affected by EU-wide trade. Thus indi-rectly these countries are affected and they will need to respond to the international policy developments. The difference with trading based regimes is that the uncertainty of policy in-teractions may be not directly noticeable on the project level. Harmonisation of the support framework and the creation of an EU market for RES can re-duce this uncertainty, as a large market with sufficient liquidity will provide efficient incen-tives for investment. In a truly harmonised EU market there would be one equilibrium price for RES which would provide the investment incentive for all EU countries. Moreover, in such an EU market forward markets can arise which provide a very clear financing bench-mark of the future value of RES in the EU market. However, when Member States continue to pursue their own course a fragmented and uncertain market is likely to persist. The Renewables Directive aims to provide a framework for the future harmonisation of RES support schemes in the EU. To provide a basis for harmonisation the Directive stipulates that the Commission will present a report on the experience gained with the application and coex-istence of different support schemes in the Member States (art 4.2 and art 8). This report is due in 2005. Based on the findings from the Commission the report may be accompanied by a proposal for a Community framework for RES support schemes. The Directive also stipulates that such a proposal for a harmonised support framework should allow a transition period of at least 7 years in order to maintain investor confidence. Thus the process of harmonisation will only commence 3 years from now and will then take at least another 7 years to complete. In the first 3 years uncertainty is likely to persist because of development and amendments of national policies. In the following 7 years of transition uncertainty for new investments may be caused by the uncertain outcome of the harmonisation process. This uncertainty may be reduced somewhat by clearly indicating the targeted support framework at the beginning of the harmonisation process, and accelerating the process as much as possible. For CHP, harmonisation of support schemes will also become increasingly important under the proposed CHP Directive. Similar to the Renewables Directive, the European Commission will provide for an evaluation of existing national CHP support schemes in the proposed CHP Directive. Member States will probably be requested to provide reports on the design and the success and shortcomings of national support mechanisms. Based on the findings, a decision could be taken on a Community framework for national CHP support schemes.

Recommendations

Following from the discussion above several recommendations for policy development or improvement can be derived to improve the conditions for financing CHP and RES projects: • Involvement of local actors in financing: local communities have in several countries

proven to be a good source of equity. Financing schemes attractive to private investors have been successful both in Germany and Denmark (closed funds; co-operatives) sup-ported by both taxation system and motivation for green or neighbourhood investment. Involvement of local communities has the additional benefit of reducing local resistance during planning procedures as local actors are economically engaged in the project. Local



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involvement in financing renewables projects can be encouraged through a range of in-formation activities.

• Establishment of regional energy agencies: Regional energy agencies can be a facilitator to reduce transaction costs in many ways; through providing information about support schemes, bringing project developers, manufacturers, financiers and local communities in contact with each other. National, regional and local governments, but also industry or-ganisations can play a role in setting up these agencies.

• Harmonisation of RES support framework and creation of a single market for RES: The continued changes in national support framework during the transition to a harmonised EU market for RES cause uncertainty with regard to the value of renewables. The creation of a single market for RES would provide clear short and longer term price signals for in-vestment in new RES across the EU. This argument calls for a quick harmonisation of EU support frameworks and RES markets, particularly for new plants. It is recognised that for existing plants the certainty provided by old support schemes is fundamental to their eco-nomics. Therefore, as the Renewables Directive indicates, a transition period is necessary during which these existing plants can continue to operate under the old support frame-work. To stimulate new capacity, however, quick harmonisation is desirable. This recom-mendation addresses both the Member State governments as well as the Commission. From the Member States it requires that they develop their policies taking into account the developments in other countries and that the co-ordinate their policy making with other countries. From the Commission it requires that it pays particular attention to the interac-tion of policy schemes in the reporting under the Renewables Directive, and that – where it can – it accelerates harmonisation.

• Standard financing concepts: For small actors, transaction costs could be decreased by standard financing concepts or contracts. National energy agencies could be assigned the task of developing such contracts in co-operation with the market actors and promoting them.

• The allocation of State Aid for RES and CHP should continue only as long as current market distortions exist and external costs are not internalised. In the long run, when trad-able CHP certificates these mechanisms, new taxes on energy products and CO2 trading mechanisms are established, these mechanisms should be phased out.

• More people could benefit form existing national experiences with (innovative) financing concepts for CHP through exchange programmes and enhanced networking. In this re-spect, Community programmes and initiatives such as SAVE or ALTENER are a suitable tool to spread innovation and knowledge.

9.5.2 Support Mechanisms Within the EU Member States a broad variety of financial support mechanisms are in place or in preparation that are designed to improve the economics of a DG installation usually in or-der to account for the external environmental benefits. The form of these support schemes is usually differentiated between RES and CHP and further between different technologies and installation sizes. Support schemes can include price-oriented instruments like fixed feed-in tariffs, investment subsidies, production subsidies, fuel subsidies, soft loans, ecotax exemp-



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tions or other taxing/depreciation schemes, or quantity-oriented instruments like tender/fixed price systems or quota/green certificate systems. This is illustrated in Figure 9-3. It is beyond the scope of this report to discuss the various policy instruments for renewables and their rela-tive merits and disadvantages more extensively.64.

supply

demand

Feed-in tariff / green prices

(Germany, Austria,

Spain, France,Greece, Portugal,

Finland

price quantity

Price supportof the demand(Netherlands)

Obligation (%) forconsumers or suppliers(Denmark, UK, Sweden, Austria

(small hydro), Belgium)

Tender(Ireland)

Obligation for producers(Italy)

Figure 9-3: Classifying renewables support mechanisms

Despite the success of feed-in tariffs in stimulating the development of RES projects in the case studies a few comments need to be made. In the short term, fixed feed-in tariffs give maximum investment security to RE developers. However, as the contribution from renew-able sources to the generation mix increases, the cost of a fixed feed-in tariff system could become too high in the longer term, and political support for the system will diminish. Thus the long-term investment security is low because of the inherent political instability of the system. Furthermore, utilities that are located in areas with a large potential of renewable en-ergy sources will likely be offered more renewable electricity, and will therefore have to pay more premium tariffs. In a liberalised electricity market this puts these utilities at a competi-tive disadvantage relative to utilities in areas with low renewable energy potentials. The limited success of CHP support schemes with regard to small-scale, decentralised CHP producers could be explained through high transaction efforts, complicated regulation and lack of long-term clarity on the support conditions prevent the satisfactory uptake of support schemes for decentralised CHP. The decision to grant state aid to DG, and the design of the support schemes is essentially a responsibility of the Member States. The European Commission has already contributed its part by explicitly providing much scope for national support schemes for DG in its Commu-nity Guidelines for State Aid for Environmental Protection.

EU legislation

Currently, the "Community guidelines on State aid for environmental protection" set out the main conditions under which Member States can grant firms aid in a variety of forms to pro- 64 See, e.g., Van Dijk et al,(2002).



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mote environmental protection. The approach looks favourably upon aid for renewable energy sources and CHP. Member States can choose between several options for granting such aid up to certain thresholds.

Recommendations

The design of support mechanisms should take into account the specific needs of the actors developing and investing in DG, such as • uncertainty of continued availability and amount of subsidies

• uncertainty of continued availability of soft loans • small-sized developer/operator cannot make use of accelerated depreciation rules • high efforts to handle tax refunds Furthermore, procedures, eligibility and the term for support should be clear to investors from the outset of developing the project. This should provide more certainty for investors. In view of the ongoing liberalisation and integration of EU electricity markets policies should increasingly focus on setting the market conditions in which CHP and RES can be developed, without or with less support. Under such conditions, much could be left to the interplay of market forces and by using tools such as CHP certificates, guarantees of origin for RES, or CO2-trading schemes. Examples of policy developments in this direction are: • establishing concrete energy and environmental policy objectives, such as CO2/CHP ob-

jectives and quotas (CHP Directive, Amended Electricity Directive) • setting "true" energy prices by internalising all external costs (Directive on Energy Taxa-

tion) • the indicative targets for renewable electricity (Renewables Directive) combined with

green certificate trading systems.



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9.6 Operation Article 7(6) of the Electricity Directive requires that, unless the transmission system is already independent from generation and distribution activities, the (transmission) system operator shall be independent at least in management terms from non-transmission activities. An amendment to the Electricity Directive to establish a similar rule applying to DSOs has been proposed by the European Commission, but does not currently exist. In order to recover the cost of network services, transmission and distribution system operators set tariffs for the use of the grid. In all EU Member States the grid use tariffs are regulated, except for Germany. The grid use fees and the procedures on how they are regulated may have a high impact on DG viability, particularly when a producer is not operating under a feed-in system and has to trade its electricity on the market. The structure and the level of the tariffs for decentralised generators determine the cost of electricity from decentralised generation on the electricity market. Users of the electricity network may broadly pay for the following network services: grid use fees, ancillary services and back-up power. It is anticipated that the importance of grid use fees for DG will increase with ongoing liber-alisation and with the implementation of green certificate schemes. In green certificate schemes generators have to sell their electricity on the normal power market. Grid use tariffs may define the cost of trading on the electricity market, and therefore impact the value of DG electricity on this market. All users of the grid pay for the provision of ancillary services by the TSO. These ancillary services include balancing power, and voltage and frequency control. DG can provide some of these ancillary services. However, in many cases there is no market through which DG can be remunerated for delivering these services. In the case where markets for ancillary services do exist DG often do not have access to them, such as in the case of balancing markets. Issues relating to balancing and settlement systems are more extensively discussed in chapter 9.4.1. Most projects in the case studies operate under a feed-in scheme; the power is sold under regulated tariffs to the grid operator so that active trading of the electricity as indicated above did not take place (case studies from Austria, Denmark, France, Germany, Italy, Portugal and Spain). Therefore the issue of grid use tariffs, ancillary services and provisions with respect to back-up power requirements did not show up as a major concern in this research. Neverthe-less, because of their potential discriminating effect, we look at the effects of grid use fees on DG in more detail below.

9.6.1 Grid Use Fees In order to be able to establish business contacts, access to the grid, and transparent, and non-discriminating grid use fees are crucial. In all market segments, the market power used by incumbent utilities has been a continuing problem. Excessively high network tariffs discourage third party access and electricity exports from DG operators, and form a barrier to competition because they could provide revenue for cross subsidy of affiliated businesses in the competitive market. Network tariffs and the related regulatory procedures have thus also a high impact on the viability of decentralised CHP pro-jects.



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In general, excessive tariffs for network use of decentralised electricity producers and third party users of the grid can be attributed to the following: • The network operator may not deduct the avoided cost savings when billing network

charges to decentralised producers, thus obtaining additional revenue at their cost. • The network operator may charge the use of all voltage levels to electricity exports from

decentralised generators. It can be questioned whether this is justifiable. • The network operator may charge extremely high prices for back-up and top-up services. Non-transparent cost calculation methods for network charges make it virtually impossible to smaller generators or any new entrants into the market to verify whether such charges have been calculated in a non-discriminatory way and reflect a fair account of the real costs that various users (both electricity consumers and producers) cause in the grid. Decentralised generators have the potential to avoid costs of the system operator: • First, in terms of network capacity, because decentralised autoproducers normally also

consume part or all of their electricity production on-site. This avoids electricity imports through the transmission and distribution system, and thus investment into transport ca-pacity. Moreover, electricity exports from DG producers stay within the low-voltage net-work, where they are consumed. This means, also the exported part of electricity avoids transport capacity at higher voltage levels of the system.

• Second, the reduced need for electricity imports from remote areas and passing through different voltage levels reduces transmission losses. In total, losses in the European trans-mission systems are normally in the magnitude of 1-2 % of the total power transported. The relative additional losses of additional transports can however be much higher65. Transport losses on the low voltage grid may be about 2%, at medium voltage levels ap-proximately 1%. Also, transformation across from the high voltage grid through a medium level to the low voltage network can imply losses of roughly 2%66. In Germany, transmis-sion losses amounted to about 4.7% in the Western part of the country, and 9% in the East in 1995. In 1999, total transmission losses in the entire country were 5.5%. The Western level is considered to be close to the technically achievable optimum67. These losses have to be recovered by additional generation, which network operators usually have to buy from generating companies for this purpose, and thus have to deal with costs of losses. Decentralised generators, by preventing these losses, help the network operators avoid parts of these costs.

As regards the Member State level, for transmission, charges are generally made separately for export to the grid (producers) and for reception from the grid (consumers). Charges to exports to the grid are zero in most Member States, or represent a much lower proportion of total overall tariffs.

65 Haubrich, H.-J.; Fritz, W. (1999) Study on Cross-Border Electricity Transmission Tariffs by order of the European Com-mission, DG XVII / C1. Final Report. (http://europa.eu.int/comm/energy/en/elec_single_market/florence/cbett_en.pdf) 66 Deutscher Bundestag (1994) (Ed.) Mehr Zukunft für die Erde. Schlussbericht der Enquete-Kommission des

12. Deutschen Bundestages "Schutz der Erdatmosphäre. Bundesanzeiger Verlagsgesellschaft, Bonn.

67 Press Information from VDEW (1997 and 2000) on http://www.vdew.de



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For transmission between most Member States there are international 'postage-stamp charges', meaning that there is no variation in transmission tariff by location. For Greece, Ireland, Italy, Sweden and the UK transmission charges vary by location, usually on a zonal basis, to pro-vide incentives to generators to choose the correct locations. For distribution (within a coun-try), there are generally postage-stamp charges with no separation of export and reception of electricity or locational signals, although for Italy there is a distance related component. For both transmission and distribution, Member States usually base their tariffs on a combina-tion of capacity (€/KW/year) and flow (€/MWh) charges, although there are variations in the balance between these parameters. Transmission and distribution tariffs can be added together to produce a network charge for customers connected at different voltage levels68. Tariffs for use of distribution networks for CHP electricity exports vary significantly between EU Member States. Prohibitive distribution network tariffs have been found in Belgium, which also does not apply any distinction between CHP plants of different sizes. In general, the criteria used for determining network charges for CHP electricity exports remain unclear, and in a number of countries this information is difficult to obtain69. For instance, four out of ten German network operators simply refused to submit the basis of their price calculation to the German Cartel Office - entrusted to exercise regulatory functions in the energy sector - which wanted to investigate excessive network charging70. Under these circumstances, control of network operators is virtually impossible. Generally, unusually high network tariffs have been reported from Austria, Germany, Spain and Portugal. On the other hand, Denmark and the UK feature relatively low charges. In Germany, grid use fees hardly play a role for DG operators due to the fixed feed-in tariffs combined with priority dispatch for RES fixed by law and the common feed-in agreements for DG. Since the introduction of the liberalised system in Germany, new power traders and re-tailers are complaining about high, discriminatory fees for grid use especially in distribution grids. However, this does not concern especially DG but rather generally the access to the power customers in competition to the local ex-monopoly utility. In addition, not all distribu-tion grid operators have published general tariffs for use of the grid. This has led to several investigation cases led by the cartel authorities. As mentioned, DG is concerned only so far as specialised green power traders and retailers offering RES and CHP based power supply are concerned.

EU legislation

Article 16 of the existing Electricity Directive relates to “access to the system”. Under the proposed amendments to the Electricity Directive, Article 16 would oblige the adoption of a system of regulated TPA based upon regulator-approved tariffs or methodologies. The pro-posed Article 16(1) is as follows:

68 Commission of the European Communities (2001) First report on the implementation of the internal electric-

ity and gas market. Commission Staff Working Paper.

69 Initial conclusions from research undertaken in the STAGAS project (SAVE), unpublished.

70 National Economic Research Associates (2002) Global Energy Regulation N° 34, March 2002.



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Member States shall ensure the implementation of a system of third party access to the transmission and distribution systems based on published tariffs, applicable to all eligible customers and applied objectively and without discrimination between system users. Member States shall ensure that these tariffs, or the methodologies underlying their calculation, are approved prior to their entry into force by a national regulatory authority referred to in Article 22(1) and that these tariffs are published prior to their entry into force.

In other words, the approval would thus be given ex ante. This would provide more security and predictability to decentralised producers, who may lack the resources to enter into open dispute and legal action against the network operators on an ex post basis, i.e. after the con-nection has been made already. The EU rules on balancing and ancillary services are less clear and less well-developed. Al-though the Electricity Directive contains some rules about distribution system operation (Ar-ticle 10-12) these are not very detailed at present and do not contain obligations on provision of ancillary services at the level of distribution (defined in the Directive as medium-voltage and low-voltage transport). Similarly, in the Renewables Directive, there are no explicit references to provision of ancil-lary or balancing services. However, fees charged for transmission and distribution services are referred to generally in Article 7(6), which provides:

Member States shall ensure that the charging of transmission and distribution fees does not discrimi-nate against electricity from renewable energy sources, including in particular electricity from renew-able energy sources produced in peripheral regions, such as island regions and regions of low popula-tion density.

Where appropriate, Member States shall put in place a legal framework or require transmission sys-tem operators and distribution system operators to ensure that fees charged for the transmission and distribution of electricity from plants using renewable energy sources reflect realisable cost benefits resulting from the plant's connection to the network. Such cost benefits could arise from the direct use of the low-voltage grid.

The European Commission has only recently begun to discuss publicly the operation of the balancing market in considering the implementation of the internal market in electricity and gas. In its first report on the subject in December 2001, it reviewed the three main approaches used by TSOs in the Member States for determining imbalance charges. In so doing, it re-ferred to the special needs for back-up supply due to variations in the output of wind tur-bines.71 The discussion at EU level is reflected in the proposed amendments to the Electricity Direc-tive (version of June 2002), which include new draft provisions relating to the provision of balancing services by DSOs. The obligation under the proposed Article 11(4) provides flexi-bility to the Member States because it is stated in a conditional sense:

Where distribution system operators are responsible for balancing the electricity distribution system, rules adopted by them for that purpose shall be objective, transparent and non-discriminatory, includ-ing rules for the charging of system users of their networks for energy imbalance. Terms and condi-tions, including rules and tariffs, for the provision of such services by distribution system operators

71 European Commission, First Report on the implementation of the internal electricity and gas market, 3 Dec

2001 (working paper), at 5.



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shall be establis hed in accordance with Article 22(2) in a non-discriminatory and cost-reflective way and shall be published.

The proposed Article 22(2) would ensure a role for the regulatory authority in such cases: The national regulatory authorities shall at least be responsible for fixing, approving or proposing prior to their entry into force, the methodologies used to calculate or establish the terms and condi-tions for :

(a) connection and access to national networks, including transmission and distribution tariffs;

(b) the provision of balancing services.

However, in Member States where DSOs are not responsible for balancing, the obligation under Article 11(4) presumably would not apply. Likewise, in such countries, there would appear to be little impetus for adopting measures to implement Article 22(2) with respect to regulatory powers over the provision of balancing services by DSOs. The proposed amendments to the Electricity Directive would not make changes to the defini-tion of ancillary services (described above). The European Parliament made a proposed amendment to delete the definition of ancillary services72, but the Commission rejected this73. The proposed amended Electricity Directive also does not provide a definition of "balancing services". Presumably, the Commission's discussion of the topic in the report of December 2001 is relevant, even for DSOs. In that paper, the Commission expressed concerns about the asymmetric prices for balancing energy "with very high top-up prices and low spill prices especially during individual balancing periods".74 However, the proposed amendments to the Electricity Directive would not extend to DSOs the existing rules on TSOs about "ensuring the availability of all necessary ancillary ser-vices"(Art. 7(3)). The proposal also would not impose explicit general duties on DSOs to pro-vide terms and conditions explicitly on the provision of back-up, top-up or standby power. In contrast, the proposed CHP Directive does contain an obligation relating to “back-up or top-up supply” which is not mentioned in the Renewables Directive, but which is arguably an important service for promotion of both CHP and RES. The proposed Article 8(6) provides:

Unless the cogeneration producer is an eligible customer under national legislation in the sense of [the Electricity Directive], Member States shall take the necessary measures to ensure that the tariffs for purchase of electricity to back-up or top-up electricity generation are set on the basis of published terms and conditions. Such tariffs and terms and conditions shall be fixed or approved in accordance with objective, transparent and non-discriminatory criteria by an independent regulatory authority prior to their entry into force.

72 The European Parliament adopted the following texts on its sitting of 13 March 2002 concerning the Commis-

sion’s Amendment proposal of March 2001:

· P5_TAPROV(2002)0106 Internal market in electricity and natural gas

· P5_TAPROV(2002)0107 Cross-border exchanges in electricity

73 COM(2002) 304 final - 2001/0077 (COD) - Amended proposal for a DIRECTIVE OF THE EUROPEAN PARLIAMENT AND OF THE COUNCIL amending Directives 96/92/EC and 98/30/EC concerning rules for the internal markets in electricity and natural gas, 7.6.2002

74 Ibid. at 5.



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This proposed formulation of the concept is weakened by the opening clause. In the amended proposals to amend the Electricity Directive, the definition of non-household customers in-cludes producers.75 The proposal is that Member States should ensure that all non-household customers should be eligible customers from 1 January 2004. The clear implication is that the obligation of Article 8(6) of the CHP Directive would not apply in countries that have trans-posed the customer eligibility requirements as proposed in the amended draft Electricity Di-rective. In other words, if the amendments to the Electricity Directive were adopted and im-plemented in a given Member State, CHP producers in that Member State would not be enti-tled to benefit under this (conditional) rule in the CHP Directive after January 2004. In addition to new rules on network access and balancing services, the proposed amendments to the Electricity Directive would require the application of new minimum criteria. These cri-teria are designed to ensure the independence of DSOs in cases where they are not fully inde-pendent in terms of ownership from other activities (proposed Article 10). However, the pro-posal also makes clear that a combined TSO/DSO is acceptable, provided that it meets all of the minimum criteria (see Article 12a).

Recommendations

The following general principles can be formulated to remove the barrier imposed by exces-sive grid use fees for DG. 1. Stricter separation of generation, trade and supply from transmission and distribution ac-

tivities (unbundling) 2. Grid use fees should be transparent 3. Regulation should take into account the full benefits and cost of decentralised generation

for network operation, considering the impact on ancillary services, decongestion, back-up power requirements, etc.

4. Tariffs should provide a level playing field between centralised and decentralised genera-tion so that both can compete in the electricity market on fair terms.

These principles are operationalised in the proposed amendments to the Electricity Directive, which are expected to tackle the main underlying problems and will provide national govern-ments with the possibility to prevent excessive, non-transparent and discriminatory grid use fees imposed on DG producers. For renewable electricity, this is also covered by the Renewables Directive in Article 7(6), which prohibits discriminatory transmission and distribution fees. For CHP, this could alter-natively be achieved through the proposed CHP Directive. However, given the reluctance of some Member States to exercise their control functions, and the seemingly strong resistance of some grid operators against transparency of prices and price calculation methods, stronger mechanisms could be necessary to protect DG producers against abusive grid use tariffs. For instance, annexes to the amended Electricity Directive could specify the requirements for the calculation and publication of grid use tariffs and their

75 A "non-household customer" is defined in the proposal to amend the Electricity Directive as “any natural or

legal person purchasing electricity which is not for its own household use and shall include producers and wholesale customers”.



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approval through electricity regulators in more detail. These could set out a minimum cata-logue of items and information that communications on grid use tariffs need to contain.

9.6.2 Ratio of Gas and Electricity Prices for CHP Obtaining the necessary funds required to finance a decentralised CHP project can be a high hurdle. The economies of CHP projects are characterised by a high initial investment, the de-preciation of which depends heavily on the following factors: • fuel price • electricity price

• price for top-up and back-up electricity

• yearly hours of operation • efficiency of the scheme

• support schemes and other additional incentives Many private sector companies try to reduce their financial risks to the largest extent possible and accept payback periods of not more than 2-3 years. Public authorities and private indi-viduals have a higher tolerance in this respect and are more willing to accept reduced profit-ability. Yet, soaring gas prices and sharp drops in electricity prices have, during the last two years, had a negative impact on the depreciation of many CHP installations. These price de-velopments were on the one hand a result of uneven liberalisation of gas and electricity mar-kets. Fierce competition in the electricity sector, together with existing production overcapaci-ties in some countries, turned out into extremely low electricity prices. At the same time, far less competition and market opening in the gas sector, and the continued link between the oil and gas prices, caused the latter to climb significantly. The effect of this combination – re-duced profitability of decentralised CHP plant - was most noticeable in countries such as Netherlands, Germany, or Spain, where the bad gas-electricity price ratio generated a stale-mate in the development of new projects. The changing ratio between natural gas and electricity prices in the last years has therefore made operation of natural gas fired CHP hardly feasible. This appears to be the major barrier for CHP development presently, and has led already to the decommissioning of CHP plants. The CHP plants studied in the case studies were either developed way before the present in-crease of the ratio between gas and electricity prices (and are already written off) (e.g. Alk-maar CHP (Netherlands), Ronse CHP (Belgium)) or operate in a specialised high price niche (Pozoblanco CHP, Spain) or are operated with very little or no expectation of pay-back to the investor (Bocholt fuel cell (Germany), Schonungen CHP (Germany), St.Pancras CHP (UK)).

Community and national policies and experiences

The effects of energy market liberalisation and the lack of internalisation of external costs generally figure among the most commonly cited problems for CHP. A study76 evaluating the impact of the liberalisation of the electricity market on the CHP and district heating and cool-ing sector has made analyses of the economic viability of CHP in the internal electricity mar-

76 “Evaluation of the impact of the European electricity market on the CHP, district heating and cooling sector”,

Cowi Consulting Engineers and Planners et. al., SAVE programme, 2000.



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ket. The study states that electricity markets in Europe currently are made up of a complex structure of new and depreciated power production. These markets are characterised by low power prices as a consequence of price competition often at short-term marginal production costs in saturated markets. Therefore, many CHP plants built under different political and economic framework conditions have come under pressure. Likewise, the economic interest in establishing new CHP capacity has diminished. The opening of gas markets to competition is also important for the economics of CHP due to the widespread use of natural gas in CHP plants. Market opening should in principle in the longer-term lead to lower gas prices and therefore be beneficial also for CHP plants. So far, no significant price cuts in gas prices for CHP can be identified. On the contrary, some CHP plants have during the past year experienced higher gas prices which are still being linked to the oil price. Restructuring the gas market trough unbundling, transparent price setting etc. will increase competition and weaken this linkage to the oil price.

Recommendations

Community measures to correct the imbalance in the gas-electricity price ratio could tackle the problem from both ends. With regard to the electricity price, it should better reflect the external costs, notably environmental costs, in the future. New efficient gas fired CHP tech-nologies, in principle, should be competitive to new efficient condensing power plants. How-ever, if the electricity prices do not reflect real costs (including internalisation of external costs), only large gas fired CHP plants are feasible. Internalisation of external costs would make a larger number of CHP plants economically viable than is the case to date. The pro-posed Directive on a new taxation scheme of energy products would be a crucial step in this regard, as it would lead to a harmonised solution across the Community, and could be of-set by reducing statutory charges on labour. The full external (environmental and other) costs of electricity production, such as determined through the ExternE project77, should be taken into account when fixing the new tax levels. A second economic mechanism to internalise environmental costs into the electricity price is the envisaged European CO2 trading scheme. The pilot phase of the scheme (2005-07) will affect decentralised CHP production (only the upper range of CHP plants included into DE-CENT because small scale is excluded from the scheme), and certain activities in the refinery, ferrous metal, mineral, pulp and paper industry. In order to make decentralised CHP eligible under this trading scheme, two conditions would need to be set: • Firstly, the unfair treatment of CHP according to the suggested provisions of the Emis-

sions Trading Directive (see Annex A) needs to be removed. The approach and wording of the Directive needs to be redesigned such a way that the CO2 savings achieved by new CHP installations are rewarded, and the increased on-site fuel consumption through CHP is not penalised.

77 http://externe.jrc.es/. The ExternE project is the first comprehensive attempt to use a consistent 'bottom-up'

methodology to evaluate the external costs associated with a range of different fuel cycles. The European Commission launched the project in collaboration with the US Department of Energy in 1991.



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• Secondly, after the pilot phase, the trading scheme should be expanded to include also smaller CHP units wishing to participate in the scheme.

With regard to the gas price, the current status of liberalisation of the gas markets is largely insufficient. The Commission's proposal for further liberalisation of this market is an appro-priate measure supposed to bring about important price drops in the medium term. The Com-mission should also support efforts to de-link the gas price on the world markets from the oil price.

9.6.3 Biomass Fuel Supply The use of biomass for power/heat production has a very large potential in the EU Member States. However, severe problems to be overcome in development and operation are posed in securing fuel availability and organising (and financing) fuel logistics. Biomass plants that use “fresh” biomass residues as fuel have to cope with high fuel costs. The uncertainty of the fuel market development is a major impediment for the development of solid biomass plants in Germany. In all biomass case studies, fuel supply plays an important role. For the Mortágua biomass project (Portugal), fuel logistics are a major problem due to a lack of involvement of local authorities in the planning of the plant. These local actors were expected to contribute to the fuel supply of the plant, but as a result of poor information, they tended to ignore the plant. For the Silbitz biomass plant in Germany the price of biomass fuel determines the financial viability of the project. Its economics are based on the current situation that clean wood resi-dues (for which the plants are licensed) will be available at low price levels, i.e. a negative price (premium) or a small positive price.

Recommendations

• National governments should provide long term certainty on the price of biomass fuels as far as subsidies are concerned.

• Involve forestrial /agricultural actors for biomass supply. The Tyrol biogas case study (Austria) shows, how early involvement of the local agricultural association contributed to the project’s success.



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9.7 Barriers and Success Factors not Specific to a Particular Stage

9.7.1 Other Benefits of Decentralised Generation A number of local and regional benefits can be related to the use of decentralised generation of power. In many cases these local/regional benefits are not accounted for in the economic calculations of the DG-plants, mostly because they might be difficult to evaluate in concrete terms. But if these benefits are monetarised they could turn out to be the crucial part making some DG-projects economic viable. In the following some of these local/regional benefits are mentioned.

Generation of local welfare and employment

Many decentralised plants are established in (remote) rural areas, often characterised by a weak regional and economic development. Thus biomass and biogas plants could generate additional income and employment to farmers in these areas, as could be the case for wind farms as well if owned by local farmers. In the case of wind energy, some parts of the turbine are often manufactured locally. Thus decentralised generation might substitute other social and economic measures for increasing local welfare.

Decentralised generation

As shown by a number of studies (e.g. the EU-project REVALUE78 the establishment of de-centralised plants might lower transmission losses because in many cases a large part of the decentralised generated power is used within a close distance from the place of generation. Other advantages might accrue as well e.g. less need for reinforcing the grid at weak points in rural areas.

A “green” profile

A positive image is often related to the use of environmentally friendly decentralised gener-ated power, which may be especially important for companies with a “green” profile This is often the case for photovoltaic installations (PVs), which would usually be uneco-nomic if only calculated as an electricity generator. If PVs (or other DGs) become part of a company's PR strategy, the systems border is widened and the installations might turn out to be economic viable. This process can be seen e.g. for the PV strategies of retail companies and service station operators in Europe. Similar examples can be found if PVs are integrated into buildings and the modules take over a building's function, like roofing or facade.

Environmental benefits

Strategies for developing DGs are often seen as part of greenhouse gas reduction strategies, thus normally the value of CO2-substitution is taken into account. But this might not be the case for other local/regional environmental benefits, as reduction of SO2 and NOx.

78 Mitchell, C et al. The value of renewable energy (REVALUE2). EU research project JOR3-CT98-0210, Feb-

ruary 2001, http://users.wbs.warwick.ac.uk/cmur/publications/revalue.htm



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Recommendations

If local/regional benefits are taken into account these might turn otherwise not economical DG-projects into economic viable ones. Factors as local welfare generation, benefits for the power system of decentralised generation, local/regional environmental benefits and positive PR for companies and individuals of utilising “green” technologies are important to address and evaluate specifically in DG-projects, thus widening the scope and system borders of de-centralised technologies.

9.7.2 Uncertainty on Policy Development Uncertainty on policy development is one of the key barriers for the development of DG pro-jects. It is mainly caused by the current transitional phase of electricity and gas market liber-alisation across the EU entailing comprehensive legislative reforms at the national level, but also independently from EU influences by short-term, disruptive national policy design. For renewables, the adoption of the Renewables Directive has started a transition towards a har-monised market and support framework for RES. Although this is expected to provide inves-tor security in the medium term, the current transition phase merely increases the uncertainty on the development of national and EU-wide support schemes. Uncertainty makes it impossible to assess the costs and benefits associated with the develop-ment and operation of a DG project, and therefore to evaluate the risks and calculate the pay-back period for the initial investment. DG projects in general are characterised by a high ini-tial investment. Finance providers for DG projects therefore require a high certainty about their economic prospect. For instance, whilst the Dutch government CHP policy covers only a period of 3 years, finance providers have to do economic project appraisals for a 10-year pe-riod. This situation appears to be generally more detrimental to smaller DG operators with less financial reserves to withstand temporary market turbulence.

Renewables

Each Member State has unique conditions for the development of RES. Where some countries have ample of wind resources, others may have more biomass, and where the one country has a large potential for RES, the other may have only a very limited potential. Moreover, the technological and institutional infrastructure vary per Member State. As a consequence differ-ent Member States employ a different portfolio of support schemes in order to promote the use of RES. Whereas to date these portfolios are mostly aimed at developing the national RES potential with the aim of reaching national RES targets, the liberalisation of the EU electricity markets and the Renewables Directive now provide the possibility to reach national targets through European trade of renewable electricity. The trading of renewable electricity across the EU exploits the benefits of varying local circumstances by first using the least expensive options available in the EU. An assessment of the benefits from a harmonised EU RES trad-ing scheme has been made in the REBUS project (Voogt et al, 2001), which demonstrated that significant cost savings can be achieved through trading. At the same time a harmonised market would provide clear short- and long term price signals to investors to establish new plants.



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However, in absence of a harmonised trading framework, and given the differences in support schemes between member states the value of RES varies per country according to the support mechanisms that are in place. Due to the trading these differences in the value of renewable electricity affect the effectiveness of support mechanisms in the different Member States. This may cause policy makers to constantly adapt the national support frameworks in view of de-velopments in the other Member States. This constant adaptation causes a lot of policy uncer-tainty. Of course such uncertainty predominantly plays a role in the transition to a harmonised market and support framework for RES. In a completely harmonised market the price signal should be the same in each country. Thus while the transition period allowed for in the Re-newables Directive was meant to provide enough certainty to provide investors confidence in the transition to a harmonised market, the effect may be the reverse. Due to the prolonged transition adaptations in the national support policies are likely to continue which increases uncertainty, particularly for new projects. Although most of the case studies in this research were operating under a guaranteed feed-in scheme, in several other cases it was indicated that the uncertain policy framework conditions were indeed a major barrier in developing the project. Both the Lumijoki offshore wind tur-bine and Magliano Hydropower (Italy) had to deal with uncertainty regarding the revenues, respectively the amount of subsidies and the duration of the Power Purchase Agreement. For the Lastour wind farm (France) an incomplete legal framework (at that time) caused the un-certainty. Similar problems occur now for offshore wind because of its recent market intro-duction, for instance the Middelgrunden offshore wind farm in Denmark. On the other hand, studied cases in Spain and Germany in general were reported not to suffer from uncertainty because of the long time horizon of the German Renewables Act and the Spanish decree on renewables. Also, for the fuel cell in a hospital in Bocholt, the high uncer-tainty of state support mechanisms was offset by utilities' subsidies and producer's export sub-sidy.

CHP

Only the following categories of decentralised CHP projects - which are rather the exception than the rule – will normally have a chance to be built when the long-term costs and returns are uncertain. It is no surprise that the case studies in DECENT belong to these categories. • Very profitable schemes with a short payback-period which can, for instance when the

scheme is operating 6000 or more hours per year or under a favourable gas-electricity price ratio.

• Schemes that for other reasons do not rely on a secure and short payback. These include CHP units built and operated by non-profit making actors such as private households or public authorities (Hospital in Ronse (B), dwelling in Unterfranken (D), St Pancras Hous-ing in London, hospital in Alkmaar (NL)), and national pilot projects or RTD actions, etc. (Diary industry in Pozoblanco (E), hospital in Ronse (B)).

EU legislation

As regards policies at the Community level, a great deal of regulatory and economic uncer-tainty has been caused by initiating the process of liberalising the electricity and gas markets



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through the Electricity and Gas Directives. This situation will probably continue for at least some years, as the Directives are still under implementation in several countries. Also, the Commission presses ahead with its proposals on completing the internal energy market, sug-gesting that the current degree of liberalisation is limited and that a more complete opening of the markets could be achieved in less time. Uncertainty on policy developments forms intrin-sically part of this process, because the relevant Directives need to be transposed into national law, leaving scope for national deviations and delays. Apart from the liberalisation of European energy markets, other Community policies relevant to decentralised generation are very new. Most policy papers, legal proposals and final legislation on climate protection, CHP, renewable energies, energy efficiency or state aid for environmental protection are from 2000 or 2001. Extended periods of uncertainty about policy developments and support frameworks for CHP can therefore be expected also in these policy areas, simply as a result of their novelty and the national implementation processes which some of them will require. It needs to be kept in mind, however, that the outreach of Community legislation and policies is limited. National policies and administrative practices are essential for preventing or neu-tralising much of the uncertainty-related blockages to the development of DG projects. In this respect, the currently revised EU state aid guidelines explicitly allow a broad variety of na-tional support schemes to help the sector bridge these difficult times.

Recommendations

There are several mechanisms to reduce the perception of uncertainty of DG project inves-tors/developers to a level where they would be more likely to make decisions in favour of the project. Principally, the source of the uncertainty could be removed. A swift process of policy devel-opment and implementation reduces the period of transition associated with any process of political change. The sooner the situation returns back to normal routines, i.e. to more reliable and well-known the conditions, the better are the chances that DG projects could be devel-oped. With regard to the Community level, is thus important that Community policies deemed to have an impact on DG are devised and implemented as fast a possible. This also accounts for policies having a negative impact as this accelerates obtaining certainty. This means, the second stage of the liberalisation of energy markets, the proposed CHP Directive, and other relevant pieces of EU legislation should not suffer any unnecessary delays. More stability could equally be achieved through the introduction of time frames for EU pol-icy provisions, similar to the Community Guidelines on State Aid where it clearly says these will be in force until 2007. For CHP, provisions on a mandatory minimum duration of spe-cific regimes, such as state aid programmes to support CHP, could still be stipulated in the envisaged CHP Directive. For the Renewables Directive, this could be included in the reports. Recognising that the economics of many projects is dependent on the policy conditions under which they were set up, a transition period is warranted during which these policy conditions may remain intact for certain existing plants. However, as indicated in the section on financ-ing, the stimulation of new RES plants would benefit from reduced uncertainty through a swift harmonisation of the EU renewable electricity markets.



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Yet, in the long run it will be necessary to shape electricity, gas and heat markets to promote DG under market conditions. Examples of market-conform mechanisms include CO2-emission trading and Green and /or CHP certificates. These create added value to renewable electricity or CHP by internalising their external environmental benefits. Especially combined with mandatory national targets and annual timetables for DG Development until 2010 (the year when the Community's 18% CHP target and 22% renewable electricity target are to be achieved) and beyond, such a system could achieve relative predictable conditions under (un-certain) market conditions and set the basis for coherent, measurable national policies to de-velop DG. For CHP, it could be set up through provisions in the proposed CHP Directive. Yet, the need for such measures at the Community level would need to be balanced against the desirability of subsidiarity. A means to reduce long-term uncertainty is also to reduce the payback period of DG installa-tions by making the initial investment smaller through subsidies. This makes the evaluation of the plant's likely depreciation easier and creates more confidence in its results. The State Aid Guidelines do explicitly cover these measures.

9.7.3 Market Power of Utilities As described earlier, DG operators can be, and often are, exposed to market power exercised by incumbent utilities e.g. during the project phases connection to the grid, contracting, and operation. Here, incumbent utilities, usually grid operators integrated with generation and retail departments, can use their position to distort the markets and treat new generation or retail competitors in a discriminatory way. The newcomers’ position is further weakened when they are small IPPs, lacking the resources and standing to risk a legal dispute.

EU legislation

In order to avoid misuse of the established position of integrated utilities the Electricity Direc-tive requires unbundling of accounts for generation, transmission, distribution and non-electricity activities of integrated electricity undertakings (Article 14). In addition, TSOs are subject to limited obligations on unbundling of management. Article 7(6) of requires that, unless the transmission system is already independent from generation and distribution activi-ties, the (transmission) system operator shall be independent at least in management terms from non-transmission activities. As mentioned above, a similar rule does not presently exist in the Electricity Directive with respect to DSOs, but this has been included in the amended proposal to amend the Electricity Directive (see Article 7(6)). As mentioned above, the case studies show that DG projects are often seen by incumbent integrated distribution utilities as an unwelcome competition in the generation (and sometimes retail) sectors. Therefore they are exposed to prohibiting business practices in during grid connection, grid use, and contract-ing. Stricter unbundling rules, such as those presently proposed, is therefore likely to be a step ahead in the direction of reducing unfair market power of established integrated utilities against DG projects. However, it remains in doubt whether legal unbundling will be sufficient to lead to a factual non-discriminatory behaviour of the distribution companies.



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9.7.4 Specific Difficulties of Small Independent Power Producers (IPPs) A high share of DG developers/operators consists of relatively small independent power pro-ducers and not based on nor affiliated with established electricity undertakings. Developers and investors often act with a high level of (environmental) commitment are ready to accept profitability conditions lower than conventionally calculating large businesses. They may also be prepared to accept a higher risk because they still need to establish a market position. The characteristics of who the DG developers and operators are, is differing considerably be-tween Member States, determining factors seeming to be historical development of DG, prof-itability of DG, and political backing, and, based on the previous factors, utilities’ attitudes towards DG. It is presumed that DG will remain to a relatively high extent a business of “non-economically” behaving actors as long as the short-term profitability of DG will improve con-siderably. Specific difficulties do materialise during permitting, grid connection, contracting, and opera-tion, depending on how clear, transparent and calculable the respective regulations are and how fair the market partners behave.

9.7.5 Lack of the Skills Required to Plan and Install a CHP Plant The realisation of CHP projects comprises of a number of phases and requires in many cases the development of tailored solutions. Except for packaged, 'plug and play' type CHP units, for instance small engines for domestic use which are readily available on the market, many schemes will combine different individual components according to the specific requirements. The installation of a CHP unit includes feasibility studies, evaluation of different variants, correct sizing of the unit, purchase of components, installation, connection to the electricity network, connection to the gas network (if the unit is gas-fuelled), connection to the local heat network, contractual matters with electricity and gas companies, maintenance, etc. The swift realisation of a good quality project therefore requires expert knowledge, which – as the case studies in Ronse (B), St. Pancras (UK) show – is sometimes lacking. There is no doubt that these projects would never have been realised without the high personal commit-ment of individuals, who were ready to acquire the knowledge to realise the projects. In the case of Ronse it was largely individual commitment that initiated the knowledge transfer from the Netherlands to Belgium necessary to realise the project. Likewise, the availability of spe-cialists from the SenerTec Service Centre in Schonungen (D) can explain much of the smooth installation and the success of this project. At the Community level, various activities and programmes exist to enhance the European dimension of training and education, such as the Leonardo Da Vinci and Socrates research programmes, and the activities of the CEDEFOP, the European Centre for the Development of Vocational Training. Despite these efforts to support and link national training schemes at the Community level, these are not sufficiently connected with regard to CHP. There appears to be no common European knowledge basis for CHP, and transfer of skills and know-how is insufficient. The international project "Educogen" started from the assumption that the development of cogeneration in Europe requires the availability of a sufficiently large body of skilled profes-sionals. The project aimed to address the European education landscape on CHP and help



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train the next generation of European engineers and technicians on CHP through a complete educational package on energy efficiency and decentralised power production. Educogen was supported under the SAVE II programme, and created a European educational tool on cogene-ration, including some of the most innovative technologies, which has proven very popular79.

Recommendations

The probably most important incentive to develop a sound knowledge and skill base for in-stalling CHP schemes are strong national policies stimulating growth in this sector. A high demand for the installation of good quality by CHP schemes will open new market opportuni-ties. Market actors will seek to acquire the necessary skills and know-how to be successful in this market. For instance, the Educogen project indicates that Denmark and the Netherlands managed to achieve significant growth in CHP through decisive national policies, without more or better CHP engineering courses being offered in their schools than in France or Bel-gium. Education and training on CHP are thus a result of, rather than a precondition for, the promotion of CHP through national policies.. In this regard, any Community policy promoting CHP will also promote the development of skills to plan and install CHP plants. An important precondition for the acquisition of better-quality skills is that only CHP plants that meet stringent quality criteria are promoted.

79 http://www.cogen.org/projects/educogen.htm



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9.8 Policy Implications of the Outlook to 2020 In this chapter, the scenarios that illustrate possible futures of DG in the year 2020 are used to assess the robustness of the policy recommendations. In the DECENT futures study, scenarios were developed along two main drivers, i.e. the weight of the greenhouse effect on the politi-cal agenda and the degree of technological innovation (which corresponds to DG costs). The scenarios are summarised in Figure 9-4, for a full description we refer to chapter 6.

greenhouse effect highon the agenda

greenhouse effect lowon the agenda

hightechnological

innovation

lowtechnological

innovation

I

II III

IV

Figure 9-4: Drivers for scenarios for DG futures in 2020

The policy recommendations that were developed in the framework of DECENT are charac-terised by two main objectives: • to reduce room for discrimination and unfair market behaviour and enhance transparency

in order to create a level playing field on the electricity market for DG in comparison to other power producers

• to explicitly open up opportunities for Member States to establish national RES and CHP policies that facilitate DG development on the grounds of e.g. environmental protection, global warming or security of supply.

The first aspect (level playing field) is touched by the different scenarios only to a limited degree: While choosing two drivers for the identification of four scenarios, it was implied that the general wish for a liberalised energy market is constant through the scenarios. However, based on scenario specifications, e.g. assumptions on the number and type of anticipated char-acteristic actors, implications on the need for a smoothly functioning, undistorted internal energy market may be identified. The second aspects (links to RES / CHP support policies) is more directly linked to the driver “greenhouse effect on the agenda”: The need for the adoption of these policy aspects into leg-islation before 2010 will be linked to the weight the greenhouse effect has on the political agenda in the different scenarios. It is important to note that many of the recommendations formulated in the previous chapters remain valid under all scenarios, because they aim at removing currently existing barriers, and



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creating a non-discriminatory playing field for DG. One could argue that once such a level playing field is established, the future role of DG depends on the evaluation of its costs versus its environmental benefits, which is exactly the difference between the four scenarios.

9.8.1 Scenario I – Green Power and Nuclear Ecology Under this scenario, ‘there has been no substantial progress in the technological development of renewable energy technologies or combined heat and power production. The achieved cost reductions are minimal. On the other hand, the greenhouse effect is considered to be a very urgent issue. (…) The electricity business is split into the mainstream, which is dominated by big utilities and on the other hand the green power market with a large share of small idealis-tic companies trying to push renewable generation technologies. (…)’ For this scenario, the possibility for Member States to have RES/CHP support mechanisms at hand that are compatible with the internal market rules is vital, in order to be able address environmental needs within energy policy. In addition, removing market barriers against a level playing field for DG is helpful for the existing DG niches. Thus, all recommendations hold in this scenario. In this scenario, local acceptance of renewable projects will be less of a problem, which means that the efforts in education and information activities are less crucial. All recommen-dations regarding streamlining of procedures still hold. Furthermore, given the (still) high costs of renewable technologies, financing will remain an important barrier, so the recom-mendations on this issue would gain more weight.

9.8.2 Scenario II – Huge Fossils Under this scenario, ‘there has been no substantial progress in the technological development of renewable energy technologies or combined heat and power production. The achieved cost reductions are minimal. The greenhouse effect is not very present in the general discussion. Most decision-makers do not consider it to be an urgent issue. The European power market is dominated by several transnational power companies holding a market share of more than 90%. Large power plants using fossil fuels and nuclear power are predominant in the electric-ity production. (…)Decentralised generation consequently plays a minor part in the electricity supply. (…)’ From the point of view of increasing DG penetration, this scenario presents the most difficult future. Promotional policies for RES and CHP have not been implemented, thus there is no need for enhanced environmental “door openers” within the liberalisation framework. Grid connection issues for the distribution grid are deemed to be rather irrelevant. Generally a lib-eralised market is valued as bringing cost reduction to the customers. Thus, the policy rec-ommendations lose some relevance. In this scenario, DG benefits related to security of supply and regional development are still acknowledged. Therefore, education and information policies, as recommended, should stress these benefits to both (regional) policy makers and the general public.

9.8.3 Scenario III – Widespread Economic Niches Under this scenario, ‘there has been an innovative push on renewable energy technologies. Great cost reductions have been achieved for both renewables and combined heat and power



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production. The greenhouse effect is not very present in the general discussion. Most decision makers do not consider it to be an urgent issue. (…) Due to computer aided power manage-ment systems it is easy to integrate decentralised power generation technologies into the exist-ing supply concepts. Actors in the electricity business are mainly big utilities offering multi-utility services together with highly specialised, profit oriented service companies. (…)’ In this scenario, DG has to compete with other electricity generation technologies purely on the basis of costs. The environmental benefits will not be a reason for special government support, and DG technologies will be used in those niches where other benefits (e.g. reliabil-ity or self sufficiency) play an important role. All policy recommendations still hold; actions to increase public acceptance could be stressed, and all recommendations targeted to an easy and transparent access of DG to the electrical system are very useful.

9.8.4 Scenario IV – Hip Ecology Under this scenario, ‘there has been a strong development in the fields of renewable energy technologies, fuel cells and other CHP technologies. Great cost reductions have been achieved and the greenhouse effect is considered to be an urgent issue. (…) Due to innovative techno-logical developments and a strong environmental awareness in the public certain renewable energy technologies have gained an importance as status symbols for customers. (…)The pro-file of actors in the energy business has broadened. Although the major share of electricity is produced, distributed and sold by big transnational companies a wide variety of small and medium sized companies have entered the market’. For this scenario, the possibility for Member States to have RES/CHP support mechanisms at hand that are compatible with the internal market rules is vital, in order to be able address environmental needs within energy policy. In addition, all provisions facilitating the easy ac-cess of DG to the electrical grid would have proven very useful. Thus all recommendations hold. Summarising the robustness check, it can be stated that the relevance of the recommendations is reduced only in one of four scenarios developed in the DECENT futures study.

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10 Security of Supply in Relation to the Deployment of Decentral-ised Energy Technologies

10.1 Introduction Back in the late 70’s and early 80’s security of supply was an important issue to address. But in the following 15 to 20 years security of supply lost interest, mostly because environmental issues were considered to be more important. But recently the issues of security of supply have gained interest again, especially with the publication of the EU Commission’s Green Paper “Towards a European strategy for the security of energy supply”. In this chapter the importance of security of supply in relation to the deployment of decentral-ised energy technologies will be treated. Security of supply will be addressed mainly in rela-tion to two aspects: • The dependence of the energy supply on imported fuels • The availability of the required energy production capacity, especially seen in relation to

possibilities and threats at the liberalised power market In the next two sections these two above-mentioned issues will be addressed in general. Fol-lowing that the pro and cons of decentralised generation will be discussed in relation to secu-rity of supply.

10.2 The Dependence of the Energy Supply on Imported Fuels At present the energy demand in the EU is covered by 41% oil, 22% gas, 16% coal, 15% nu-clear energy and 6% renewables. If a business as usual scenario is envisaged in 2030 the en-ergy picture will be dominated by fossil fuels: 38% oil, 29% gas, 19% solid fuels, 8% renew-ables and 6% nuclear energy. The business as usual scenario of the EU final energy consumption until 2030 is shown in Figure 10-1, below (European Commission 2001 (Green Paper on Security of supply)).

0

250

500

750

1000

1250

1500

1750

1990 2000 2010 2020 2030

Industry

Transport

Households,services

Figure 10-1: Business as usual scenario for final energy consumption in the European

Union until 2030.

The expected increase in the business as usual scenario is a little more than 1% p.a. The busi-ness as usual development in the EU energy supply is shown in Figure 10-2 (European Com-mission 2001 (Green Paper on Security of supply)).



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0

250

500

750

1000

1250

1990 2000 2010 2020 2030

Oil

Natural gas

Solid fuels

RenewablesNuclear

Figure 10-2: Business as usual scenario for energy supply originating from within the

European Union until 2030.

As shown in Figure 10-2the supply of EU energy resources will have its peak in 2000-2010 and then it will gradually decline to 2030 to a level lower than in 1990. The total picture for the EU dependence on energy resources from abroad is shown Figure 4-6, below (European Commission 2001 (Green Paper on Security of supply)).

Figure 10-3: The EU dependence on imported energy resources.

Referring to Figure 10-3 net imports of fuels in the business as usual scenario will gradually increase to approx. 60% of final energy consumption in the EU. In 2000 approx. 35% of total EU energy consumption was imported, thus the expected reliance on resources from abroad will be significantly higher in 2030. To lower this dependence on energy resources from outside the EU, the green paper has out-lined some of the elements of a long-term energy strategy:

• Because the possibilities of increasing the energy supply from EU sources are limited the focus will primarily be on demand policies.

• With regard to energy demand, the Green Paper is highlighting changes in consumer behaviour, especially through the use of taxation instruments.

• With regard to energy supply, especially utilisation of new and renewable energy sources are highlighted.

0200400600800

10001200140016001800200022002400

1990 2000 2010 2020 2030

production

net imports

consumption



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Thus although decentralised technologies and especially renewables have an important role to play with regard to diversifying the energy supply, in general changes in energy supply is not expected to be significant in improving security of supply. This might partly be explained by the narrow definition of security of supply adopted80, where mostly the dependence of im-ported fuels are included, while more subtle characteristics of decentralised generation are not taken into account. In this chapter the use of decentralised generation technologies, including those based on re-newable energy sources, will be evaluated with regard to their significance for the EU security of supply, not only related to the dependence on imported fuels but also addressing the value of decentralised generation in the power system in a wider context.

10.3 The Availability of the Required Energy Production Capacity One thing is that the required fuels are available from indigenous sources in the EU. This does not necessarily imply that the required energy production is available when and where it is needed. This can be caused by two reasons:

• Due to a fluctuating inlet of energy sources (e.g. lack of wind, solar or precipitation) the needed energy production is not available

• Due to lack of investment in new technologies the required production capacity is not available

This problem is not treated in the EU Green Paper, but is an important issue especially in rela-tion to the development of the power markets. Liberalisation of the electricity markets has been going on for some time now. A considerable number of European countries already have liberalised or are in the transition phase of liberalising their electricity generating industry, and electricity exchanges are being developed to facilitate liberalised electricity trade. In the Northern part of Europe the Nordic countries together have established the NordPool power exchange, consisting of Norway, Finland, Sweden and Denmark. Although peaks and troughs in price-determination have been observed, the experiences gained until now have mostly been successful. But at the same time this power market is characterised by a consid-erable excess capacity of power. Thus until now the power market has mainly acted as an hour-to-hour market for operating existing power plants, while virtually no investments in new capacity have been initiated by the market.

Thus some important questions arise:

• Will decentralised technologies have any advantages compared to larger conventional ones in such a market, where you do not know if the market by itself will succeed in initi-ating the needed investments in new power capacity?

• Will fluctuations in production from technologies as wind power and photovoltaics be serious drawbacks compared to more conventional technologies in a liberalised market context?

In the next sections some of these characteristics for decentralised plants will be evalu-ated.

80 Pointed out in the hearing comments to the EU Green Paper.



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10.4 Evaluation of Decentralised Plants in Relation to Security of Supply

10.4.1 Criteria for Evaluating decentralised plants In this section some of those special characteristics that decentralised generation possess will be pointed out in relation to security of supply, both with regard to the above mentioned de-pendence on energy resources from abroad and in ensuring that the necessary power capacity will be available. Thus decentralised generation technologies will in the following be evaluated according to these criteria: • Substitution of imported fuels. To what extent will the development of decentralised

plants replace the use of fuels imported from abroad? • Reliability in ordinary operation, taking into account required major annual overhauls and

capabilities for load management. • Flexibility with regard to establishing new plants, especially with regard to lead times and

the introduction into existing energy systems. • Economic attractiveness on competitive terms, that is with out any subsidies. Economics

comprise investments, operation, maintenance and fuel costs, including the uncertainty of the future development of fuel prices.

• Financial risks. The risk the investor is facing in terms of possible economic losses.

• Vulnerability, especially in relation to external occurrences.

In evaluating the decentralised technologies the reference will be establishing larger conventional fossil fuelled power plants. In the following each of the criteria will be dis-cussed in more detail.

10.4.2 Substitution of Imported Fuels What kind of conventional power production is replaced by decentralised production will de-pend on the hierarchy of load management. Assuming that the cheapest power production in terms of short-run marginal costs is hydropower and nuclear power, then all decentralised production will substitute fossil fuels. But of course this does not necessarily mean that imported fossil fuels are replaced. If the de-centralised plants substitute conventional base load plants probably coal, oil or gas will be replaced. If peak power production is substituted, then probably oil or gas will be replaced. If decentralised production replaces oil and gas this will at the margin substitute imported fuels. This will not always be the case if coal is the replaced fuel. Quite a number of Member States in the EU have a domestic coal production and in those cases an indigenous fuel could be substituted. Thus expectedly the following will hold true for decentralised power production and substitu-tion of imported fuels: • If possible, small scale hydropower for economic reasons will substitute peak power pro-

duction from conventional plants. Thus it is expected that small hydro plants essentially will substitute imported fuels.



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• Due to the fluctuating character of their power production, wind power and photovoltaics will mainly substitute peak power, essentially replacing imported fuels.

• Biomass plants are expected mainly to be based upon indigenous energy sources. Most probably biomass plants will have a positive impact upon security of supply substituting imported fuels, but nothing definite can be said.

• CHP-plants (excluding those based upon biomass) and fuel cells will expectedly mostly be based upon natural gas. A high efficiency in electricity production will be favourable with regard to security of supply, substituting more fuel than they consume, but essen-tially these plants will be neutral in terms of substituting imported fuels.

• Fuels cells are not restricted to use natural gas, but can use fuels as hydrogen, eventually produced by wind power, or gasified biomass. This means that fuel cells will have the possibility of substituting imported fuels. Though in general it is difficult to know to what extent the use of fuel cells will replace imported fuels.

10.4.3 Reliability In this analyses reliability comprises availability of the energy production facility as well as availability of the energy production itself. What concerns the availability of production ca-pacity this parameter is just as high for decentralised power plants as for conventional ones. For wind turbines the availability factor is 97-98%. However, due to the fluctuating energy sources for wind power and photovoltaics the pro-duced power is not always available when needed. Therefore these two technologies can only to a limited extent be used as a reliable power base – normally other sources of power produc-tion should be available within short notice if production from wind power or photovoltaics suddenly falls off. Especially fuel cells but also CHP using natural gas have excellent load following capabilities – actually better than most coal- and oil-fired power plants. And of course this is even more the case for small hydro, which is capable of very fast load following. But due to seasonal changes in precipitation hydropower cannot be expected to be available always when needed. Finally with regard to load management biomass plants are expected to be at approximately the same level as a coal-fired power plant.

10.4.4 Flexibility When new technologies are established at least two issues are important to consider with re-gard to flexibility: • How can the new technology be absorbed by the existing energy system; is there “room”

available for the new capacity without interfering significantly with the operation of the present system? Or will the new plant have a considerable impact upon the functioning of the total energy system?

• When the investment is undertaken and the plant on stream what is the robustness of the plant if central parameters are changed compared to the expected development? A change in the fuel mix used by the plant could be such a case, relative prices changing in disfa-vour of the presently used fuel.



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The establishment of wind power81, photovoltaics and fuel cell plants will all tend to be mar-ginal to the existing energy system, while this will also be the case for small-scale CHP and hydro power plants although to a lesser extent. Thus, it is reasonable to expect that small-scale decentralised plants will be fairly easy to introduce into the existing energy system. Especially fuel cells have an advantage due to their modularity implying that they can be dimensioned to the specific use. What concerns robustness all the considered decentralised plants generate power and some of them (fuel cells, CHP and biomass plants) produce heat as well. Thus they will all be sensitive to changes in the price of power and heat, as all conventional plants are as well. Wind turbines, photovoltaics and small hydro plants are of course dependent on the availabil-ity of the natural resources, but they are totally independent of the price of other fuels. Thus the production costs of these decentralised plants will be robust towards changing fuel prices. Biomass plants are almost totally designed to specific biomass fuels, although some flexibility does exist. But in general, it is difficult to convert a biomass plant to another fuel. Thus a biomass plant does not have the possibility to use other fuels and if the price of biomass will stay constant in the future is subject to considerable uncertainty. Finally, the situation is al-most the same for CHP plants. Most of these plants are connected to natural gas with limited possibilities for changing to other fuels. To a lesser extent the same can be said about fuel cells. Most fuel cells require hydrogen as input and the possibility exist to produce hydrogen from different sources. Though, the high-temperature fuel cells can use other fuels than hydrogen, e.g. natural gas, gasified biomass or gasified coal. But even for fuel cells the possibilities for changing fuels are limited.

10.4.5 Economic Attractiveness Except for CHP and perhaps small hydropower plants none of the decentralised technologies are economically attractive seen from an investor viewpoint unless some kind of subsidies are attached to them. But a number of economic advantages and drawbacks do exist for these technologies compared to large conventional plants:

• Wind power, photovoltaics and fuel cells are all technologies that are well suited for serial production and therefore candidates for serious price-reductions in the future. Though for wind power part of these benefits are already captured.

• Some of the mentioned technologies are that new, that considerable uncertainty does exist with regard to operational performance and lifetime of components. This is especially the case for more advanced types of photovoltaics and fuel cells.

• Wind power, photovoltaics and small hydro plants are virtually independent of the devel-opment of fossil fuel prices in the future.

• The economics of biomass plants are not directly depending upon fossil fuel price devel-opment, but indirectly the price of biomass could reflect changes in the price of other fu-els. Finally the future price of biomass is by itself subject to considerable uncertainty.

Presently, the general lack of economic attractiveness (not including subsidies) does not make life easier for these technologies at the power market. The future development is expected to

81 Offshore wind power farms might not be considered marginal to the existing energy system.



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change this picture, making decentralised technologies closer to be economic competitive to conventional ones. Finally, not only economic attractiveness can be seen as a barrier towards the deployment of decentralised generation, the framework conditions of the national power markets are highly important as well. Although economics of a decentralised plant might be equivalent to a large power plant, other considerations concerning the plants capabilities of contributing to the gen-eral load management or in keeping up the required reserve capacity might be more important in deciding what kind of plant to construct. Especially for utilities not facing a liberalised power market such considerations might easily favour the large power plants, while for power companies taking part in a competitive spot market economics are the dominant issues, leav-ing systems considerations to the system operator.

10.4.6 Financial Risk Financial risks in new investments are related to relatively few but important parameters: • The absolute size of the investment

• The pay-back profile • The distribution between fixed cost and variable costs • Expectations to power market development • Expectations to the development of future subsidies, including the political perspectives In a liberalised power market investments are initiated when the spot price (short-term mar-ginal costs) is equal to or higher than the expected long-term marginal costs82 for investments in new plants. But a considerable risk premium has to be included due to uncertainty if the spot price in average will stay at or above this level or not. In the perspective of this liberalised power market it is undoubtedly an advantage, that all decentralised technologies are small what concerns the absolute size of the investment com-pared to large conventional plants. Thus, although the relative risk is the same the absolute risk for decentralised technologies will be lower than for large conventional power plants. And therefore expectedly the risk premium in this respect should be lower for decentralised plants than for conventional ones. But as mentioned above most decentralised plants can not compete economically on their own relative to large power plants. Photovoltaics, biomass plants and to a certain extent wind power still has to rely on subsidies, feed-in tariff etc. Thus, the question is if the political de-cided subsidies are more or less reliable than spot market prices. A question that can only be answered in relation to the specific investment. Finally, the highest risk is associated with those technologies that are most capital intensive and have the lowest O&M and fuel costs, that is wind power, hydro power and photovoltaics. Other technologies as CHP, biomass plants and fuel cells have the opportunity to cut down expenses by lowering energy production, implying lower fuel costs and O&M-costs. As mentioned above changing input and/or output prices have a significant impact on the profitability of energy investments and are subject to considerable uncertainties. For decen-tralised plants the risk associated with the output price (power and heat prices) is the same as 82 The expected cost calculated per kWh, including levelised capital costs, O&M, fuel costs and a risk premium.



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for conventional plants, while this is not the case for input prices. As for wind power, photo-voltaics and hydropower these are independent of fuel inputs, while the future price of bio-mass is considered to be highly uncertain. Finally, the development of the natural gas price will influence CHP plants and fuel cells as it will for conventional plants. Although fuel cells have the opportunity of using other fuels, thus are subject to a lower risk than CHP-plants. Against this stands a higher technological risk for fuel cells: These are highly advanced technologies and at present it is difficult to as-sess, if these plants will work properly all the way through their expected lifetime Thus with regard to financial risks a number of pros and cons exist for decentralised power plants. To conclude: • Wind power, hydropower and photovoltaics are expected to be in the same risk category

with low absolute risk, independent of fuel price volatility, but dependent of future subsi-dies, although the last-mentioned to a lesser extent for wind power and perhaps not at all for hydropower. In general financial risks are expected to be lower for these plants than for conventional ones.

• Biomass is expected to be the most risky of the decentralised investment, mainly due to the uncertainty related to the future biomass price. Investment in a biomass plant is con-sidered to be a little more risky than investments in conventional plants.

• The only advantage for decentralised CHP-plants is that they are small in size, reducing the absolute risk compared to conventional plants. Otherwise decentralised CHP-plants are exposed to the same risk as conventional ones.

• Fuel cells have a number of advantages including small sizes, modularity and for some of them the possibility of fuel switching. On the other hand these technologies are highly ad-vanced and reliable operation over the lifetime of these plants is not proven yet. Fuel cells are assessed to be at the same risk level as conventional plants.

10.4.7 Vulnerability Compared with larger conventional plants (especially with nuclear plants) the vulnerability towards external disturbances is much lower for decentralised plants. With regard to acci-dents, terrorism or natural catastrophes the break down of one or more decentralised power plants will have only minor impacts upon the functioning of society. This is of course mainly due to the small sizes of these plants and the decentralised locations, but the low operational risks are important as well, especially compared to nuclear. Thus, seen from the overall viewpoint of society, no accidents or catastrophes at decentralised power plants will have any significant impact upon the security of supply. On the contrary, decentralised power plants might have a role of stabilising the grid in situations with major power system failures, keeping up the power in their supply areas.

10.5 Conclusions and Recommendations Table 10-1 gives an overview of the results of the evaluation of decentralised power plants with regard to the above-mentioned criteria, in comparison with larger centralised fossil fuel fired power plants.



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Table 10-1: Overview of the evaluation results for decentralised technologies

Substitution

of imported

fuels

Reliability Flexibility Economic

attractiveness

Financial

risks

Vulnerabi lity

Wind power High Low High Low/

Neutral

Low/

Neutral

Low

Photovoltaics High Low High Low Low/

Neutral

Low

Biomass High/

Neutral

Neutral High/

Neutral

Neutral/

Low

Neutral/

High

Low

Small hydro High High/

Neutral

High Neutral Low/

Neutral

Low

CHP Neutral High/

Neutral

High/

Neutral

High/

Neutral

Low/

Neutral

Low

Fuel cells Neutral/

High

High/

Neutral

High Low/

Neutral

Neutral Low

Especially if security of supply is defined in a broader context than seen in the EU Green Pa-per, including not only the dependence on imported fuels, but the pros and cons of decentral-ised generation as well, then a picture emerges mostly favourable of small-scale plants com-pared to large conventional ones with regard to security of supply, although the picture is not totally clear. In the following some of the pros and cons are summarised: • In general decentralised plants tend to substitute a high degree of imported fuels. • Due to their small sizes they are fairly easy to introduce into an existing power system.

Technologies as wind power, hydropower and photovoltaics are very robust towards fu-ture changes in fuel prices.

• With regard to capacity availability decentralised plants are at least at the same level as conventional ones. With regard to the availability of the energy production wind power and photovoltaics are less reliable, due to their dependence on natural resources.

• Larger plants can to a much higher degree take advantage of economies of scale. With the exception of CHP and perhaps small hydropower plants most decentralised technologies do need some kind of subsidisation. Though wind power is moving fast towards being competitive with conventional plants.

• Though the analysis of financial risks shows an unclear picture, it tends towards a lower risk for most decentralised technologies compared with conventional ones.

• In general the vulnerability towards external disturbances is much lower for decentralised plants than for large centralised ones. Especially in situations with transmission line fail-ures, DG may benefit by having the possibility of keeping up the power with in its supply areas.

Thus although the picture is a little bit scattered, in general the deployment of decentralised generation technologies will improve security of supply within the EU. To diminish some of



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the barriers for decentralised technologies to play a larger role in security of supply the fol-lowing policy actions are recommended: • The definition of security of supply should not be restricted to dependence of imported

fuels, but should include other characteristics of decentralised generation as well, among these robustness towards external changes, availability of capacity and vulnerability.

• The possible deployment of decentralised technologies seems to depend heavily on the organisational set-up of the power industry in the member states. Although economics of decentralised plants might be equivalent to large power plants, other considerations con-cerning the plants capabilities of contributing to the general load management or in keep-ing up the required reserve capacity might be more important in deciding what kind of plant to construct, especially if the power industry is not taking part in a liberalised power market. Thus part of this barrier could be abandoned if the power industry was liberalised in all EU member states.

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11 EU Energy Technology R&D Policy

11.1 Introduction Technology research and development plays a key role in developing and implementing de-centralised energy generation in the EU. One of the findings from the DECENT futures sur-vey “Future Decentralised Energy Systems 2020”83 (cf. chapter 4.3) was that lack of R&D was considered one of the main barriers to the realisation of decentralised energy generation. In this study, For example the lack of R&D resources was highlighted as a barrier for the re-alisation of statements regarding: • Development of new revolutionary wind turbine concepts • Cost reduction in biomass

• Improvement of energy efficiency in CHP • Improvement in lifetime of CHP fuel cells In other words, the respondents considered R&D resources an important mechanism regard-ing research, technology and development activities involving considerable technological uncertainty and risk. The results from the futures study are in line with the findings from suc-cess stories about renewable energies during the 1990s, in which the priority to research and development was one of the key actions for success within photovoltaics, solar thermal, bio-mass and wind energy (EEA 2001). In this chapter, the importance of R&D resources is further analysed in relation to the actual EU R&D policies and recommendations. The analysis is based on existing materials and re-ports rather than on new R&D indicators of decentralised energy projects compared to other (larger) energy projects. In the first section, a short overview of the actual EU energy research is given, including its objectives, its institutional incentives and the political priorities in relation to renewables. Hereafter, the results from a quality assessment of retained proposals for the EU energy re-search are used to benchmark the findings from the DECENT futures study. This leads to a description and comments on the future key actions for sustainable development of the 6th Framework Programme, which are foreseen to be launched end of 2002. Finally, some rec-ommendations are made regarding the future EU energy research policy.

11.2 EU Research and Development Policy Economic and social development requires adequate availability of energy services, in par-ticular sustainable energy production, transformation and consumption. Research, develop-ment and demonstration are needed to identify new pathways for European energy systems. For this reason, the EU has had research, technology and demonstration programmes for non-nuclear energy for many years.

83 The DECENT futures study was designed as an adapted Delphi investigation characteris ed by iteration. In an

anonymous survey, 66 external experts have ranked central statements about the future development of decen-tralised energy generation. On this basis, the project team has constructed four scenarios for 2020, see Chapter 9.8, which have been further evaluated by a group of DG experts.



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The actual European energy research has the following complementary objectives (European Commission, EUR 19466: 6): • Energy objectives: Higher efficiency of energy use, a larger recourse to renewable energy

sources (doubling the share of renewables of 6% in 2000 to 12% in 201084), and greater security of supply.

• Environmental objectives: Reduction of negative impacts on environment and climate stability, in particular reduction of green house gases by 8% in 2008-2012 compared to 1990 (The Kyoto Protocol).

• Socio-economic objectives: consideration of the energy system on competitiveness in the global market, on employment, on reducing economic gaps of less-developed regions etc.

Historically, the demonstration programme, THERMIE was operated outside the Framework programme by the DG Energy, while the R&D programme JOULE was provided within the Framework programme by DG Research. In the 5th Framework Programme (1998-2002), JOULE-THERMIE was merged into one single programme ENERGY, which represents one of two sub-programmes within the specific programme “Energy, Environment and Sustain-able Development”. The total budget for the 5th framework programme, including the Euratom programme is 14,960 mil. Euro, of which 2,125 mil. Euro are allocated to Energy, Environment and Sus-tainable Development. The sub-programme ENERGY receives 1,042 mil. Euro85 while the other sub-programme Environment and Sustainable Development receives 1,083 mil. Euro. In comparison the Euratom programme receives 1,260 mil Euro. ENERGY is divided into two key actions: • Key Action 5: Cleaner energy systems, including renewable energies (479 mil. Euro) • Key Action 6: Economic and efficient energy for a competitive Europe (547 mil. Euro) The objective of Key Action 5 is to minimise the environmental impact of the cost-effective production and use of energy in Europe. This will help the ecosystem by reducing emissions at local and global levels and by increasing the share of new and renewable energy sources in the energy system. It will also have socio-economic impacts by enhancing the capability of European industry to compete in world markets, helping to secure employment and promoting social cohesion with less favoured regions. The objective of Key Action 6 is a reliable, clean, efficient, safe and cost-effective energy supply and services for the benefit of its citizens. This is essential for the good functioning of society, the competitiveness of industry in European and world markets and the quality of local and global environment. Efficient end-use technologies are expected to count for 60% of the greenhouse emission reductions on the short term and for 30% on the long term. The fo-cus of the EU strategy is the realisation of the significant economic potential of as much as

84 Resolution from the Council based on the white paper “Energy for the future: Renewable sources of energy”

(COM(97)599 final), in which the target of 12% of EU energy coming from renewables was put forward. In order to reach this ambitious goal, proactive steps were required, among others R&D funds for technological development, cost reduction and user experience.

85 Including 16 mil. Euro for RTD activities of a generic nature.



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18% of the 1995 energy consumption in 2010. This addresses all stages of the energy cycle: production, distribution and final use. According to the assessment report covering the period 1995-1999, the Non Nuclear Energy RTD programme of the 4th Framework programme gave a priority to renewable energy sources, with app. 45% of the total budget. For the 5th Framework programme, the support for renewable energy has been strongly requested by the European Parliament. Hence during 1999 the programme was shaped to assure an allocation of not less than 60% of funds to re-newable energy, of which 75% should be allocated to demonstration projects (Five Year As-sessment Report Related to the specific Programme: Energy, Environment and Sustainable Development covering the period 1995-1999, June 2000: 56).

11.3 Assessment of Non-Nuclear Energy Proposals Effective adjustment of the European energy research was the background for a qualitative assessment of energy proposals in 2001 (European Commission, 2001). The results have con-tributed to the redefinition of the energy work programme research, technology and develop-ment objectives and focused the calls for the remaining programme period. The results from the pilot assessment are framed by five qualitative criteria derived from the programme criteria and objective: • Innovation: scientific and technical value, novelty, consistency of proposal

• Environmental impact: potential of reducing impacts on environment and global climate • Cost-effectiveness: reduction of costs with respect to conventional solutions • Problem-solving: capacity of addressing effectively the main problems • Socio-economic effects: anticipated effects on European society. These criteria were used to assess proposals submitted, for which a score going from 0 to 3 was assigned (0 = not addressed at all; 1= below average; 2= average; 3 =best score). The assessment focused on sectors, which were grouped across the two key actions. These clusters do not include decentralised energy generation as a sector of its own, but do comprise differ-ent renewables as well as other specific problem areas such as storage and transmission. In the table below an overview of proposals and the scores of selected energy groupings are shown. Table 11-1: Ratings for selected groupings of energy proposals

Proposals submitted

Proposals retained

Innovation Environment Cost effec-tiveness

Problem solving

Socio-economics

Large scale gen-eration

149 46 2 1.9 1.3 2 1.6

Fuel cells 58 15 2.5 2.2 2.1 2.6 2.6 Biomass 207 30 2.4 1.7 1.8 2.1 2.2 Solar energy 109 23 2.5 1.8 2.1 2.3 2 Wind 89 18 2.6 2.3 2.1 2.4 2.2 Integration and storage

142 46 2.4 2 1.9 2.6 2.6

Others 459 117 N.a. N.a. N.a. N.a. N.a. Total 1,213 295 N.a. N.a. N.a. N.a. N.a.



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Following three public calls (deadlines 15.6.99, 4.10.99 and 31.5.00 respectively), a total of 1,213 proposals were submitted, of which 295 were retained, or 24% of the total proposals. Fuel cells, biomass, solar energy, wind and integration & storage, which is important to re-newables, accounted for 132, or 45% of total retained proposals. Large-scale generation com-prising a wide range of technologies accounted for 46, or 16% of proposals retained. From the assessment (or the project overview from the 5th Framework website) it is not possible to get an overview of how many funds each energy groupings have received. • Large-scale generation proposals cover a wide range of technologies and applications,

including addition of biomass or waste to coal combustion, improvement of conventional plants, gas turbines etc. The quality of the proposals is somewhat below average, in par-ticular regarding cost effectiveness.

• Fuel cells represent a promising energy in terms of high efficiency and environmental impact as they convert fuel (basically hydrogen) directly into electricity. Scores are higher than average.

• Biomass: A great variety of technologies can be utilised to transform biomass and waste into energy, in the form of electricity or heat or combined heat and power (CHP) or fuels. The emphasis of the programme is on electricity production and especially CHP. The quality of proposals is above average. Most of the proposals dealt with the utilisation of wastes. Very few proposals looked into the long-term perspective of energy crops.

• Solar energy or more specifically photovoltaics is expected to have the highest potential for cost reduction though learning and breakthroughs, but is still between 5-10 times more expensive than the conventional energy. Proposals include some highly innovative pro-jects as for example the Wembley Stadium with an integrated PV façade. Scores are above average, except for environment.

• Wind energy represents a competitive technology on the global markets. Proposals focus on cost reduction, better diffusion of the technology and improvement of large wind farms and turbines. The scores are all above average.

11.4 Results From the DECENT Futures study In the DECENT futures study (cf. chapter 4.3), two criteria were used to identify the top statements86. These criteria were: • Beneficial impact on global environment • Beneficial impact on cost of energy production Regarding the environment, fuel cells and wind have the highest high score in the quality as-sessment, while both biomass and photovoltaics have a lower score than large-scale genera-tion. This partly contradicts the findings from the futures study, where statements about bio-mass and photovoltaics are included in the top ten list along with statements about wind and fuel cells. For further details see the table below. It is worth mentioning that while the score of 86 The ranking is based on the average index of beneficial impact on global environment. It is calculated based

on the total numbers of respondents and weighted values of 100 (High), 0 (Medium), and –100 (Low), respec-tively.



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the quality assessment is the average of several proposals, the rating of the statements is ex-clusively made to this particular topic. Table 11-2: Top ten of beneficial impact on global environment

Ran

k

No.

Statement

E in

dex

1 2 10% of Europe’s electricity comes from wind power 52 2 26 30% of fuel cell fuels in EU are derived from renewable sources 45 3 1 10% of Europe’s power demand is covered by energy from renewable sources 40 4 3 50% cost reduction of wind produced electricity relative to 2001 40 5 5 More than one-third of wind turbine capacity in Europe comes from offshore sites 27 6 22 Widespread use of domestic and commercial fuel cell units 22 7 10 20% of EU’s electricity is based on biomass 18 8 24 10% of Europe’s domestic power demand is covered by fuel cells located in domestic

houses 15

9 9 Widespread use of photovoltaics integrated into roof tiles 15 10 8 50% cost reduction of electricity from photovoltaics relative to 2001 10

Taking a closer look on innovation, the wind proposals in the quality assessment represent the highest score with 2.6 where trends have been towards larger turbines and offshore instal-lations. It does not, however, include a totally new concept of wind turbine. Large-scale gen-eration represent the lowest score with not more than 2 as several proposals focus on im-provement of existing technologies towards higher efficiency and reduced emissions. It is therefore also interesting to notice that the cost reduction score is higher for all renewables than for large-scale generation. All in all, proposals retained within key action 5 and 6 are characterised by high scores of innovation and cost reductions compared to large-scale generation. This is quite interesting compared to the futures study where the beneficial impact on cost reduction were rated rela-tively low for most of the statements as can be seen from the table below. Only 9 statements were rated above or equal to zero. Topics on photovoltaics (no. 7 and No. 9) have high rankings, not surprisingly due to the implicit economy of scale. In the same field are topics such as fuel cells units with a 40,000 working hours (No. 23), 20% electricity based on biomass (No. 10), and 10% private micro CHP (No. 10). The new wind turbine concept is also expected to have beneficial impact on cost of energy.



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Table 11-3: Top list of beneficial impact on cost of energy R

ank

No.

Statement

C in

dex

1 7 5% of Europe’s electricity comes from photovoltaics 33 2 8 50% cost reduction of electricity from photovoltaics relative to 2001 18 3 25 75% cost reduction produced by stationary fuel cells relative to 2001 18 4 9 Widespread use of photovoltaics integrated into roof tiles 15 5 3 50% cost reduction of wind produced electricity relative to 2001 12 6 23 CHP fuel cell units will reach an expected life time of more than 40,000 working hours 8 7 6 Development of a new revolutionary and competitive wind turbine concept 5 8 10 20% of EU’s electricity is based on biomass 2 9 17 10% of private households in EU have micro CHP units installed. 0

11.5 The Future of European Energy Research The 6th Framework programme is currently being adopted and is expected to be launched end of 2002, dependent on the progress of the political debate and decision-making processes. According to the modified proposal for a Council decision concerning the 6th Framework pro-gramme (COM(2001)709final) a total of 16,270 mil. Euro has been allocated for the period 2002-2006, of which 1,850 mil. Euro is earmarked to Sustainable Development divided into three sub-programmes: Sustainable energy systems (630 mil. Euro), Sustainable surface trans-port (600 mil. Euro), and Global change and ecosystems (620 mil. Euro). In the table below an overview of funds for 5th and 6th Framework programme is presented. Table 11-4: Financial overview of 5th and 6th Framework Programmes

5th Framework Programme 6th Framework Programme Euratom 1,260 940 Sustainable development 2,125 1,850

Energy 1,042 630 Transport 600

Global change and eco.

1,083 620 Total 14,960 16,270

All costs in Million EUROs

As it can be seen from the table, there are fewer resources available for Sustainable develop-ment and in particular Energy in the 6th Framework Programme than in the previous one, al-though the total funds have increased. This implies a much more thorough prioritisation of resources in a situation where not more than 24% of total proposals tend to be approved. The sub-programme “Sustainable Energy Systems” is central to the support to decentralised energy systems. Among others, the strategic objective should address the increased use of renewable energy. Research priorities are for example87:

87 Amended proposals for Council Decisions concerning the specific programmes 2002-2006 of the EU for re-

search, technological development and demonstration activities 2002-2006 of 30.01.2002



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- Clean energy, in particular renewable energy sources and their integration in the energy system, including storage, distribution and use: Increased cost effectiveness, performance and reliability of the main new and renewable energy sources; integration of renewable energy and effective combination of decentralised sources, with cleaner con-ventional large-scale generation; validation of new concepts for energy storage, distribu-tion and use (short term).

- Energy savings and energy efficiency, including those to be achieved through the use of renewable raw materials: Improving savings and efficiency mainly in the urban con-text, in particular in buildings, through the optimisation and validation of new concepts and technologies, including combined heat and power and district heating/cooling sys-tems; opportunities offered by on-site production and use of renewable energy to improve energy efficiency in buildings (short term).

- Fuel cells, including their applications: Cost reduction in fuel cell production and in applications for buildings, transport and decentralised electricity production; advanced materials related to low and high temperature fuel cells for the above applications (long term).

- New technologies for energy carriers/transport and storage, in particular hydrogen: Clean cost effective production of hydrogen; for electricity the focus will be on new con-cepts, for analysis, planning, control and supervision of electricity supply and distribution and on enabling technologies, for storage, interactive transmissions and distribution net-works (long term).

- New and advanced concepts in renewable energy technologies with focus on technolo-gies with a significant future energy potential and requiring long-term research. For photovoltaics: the whole production chain from basic materials to PV systems, as well as on the integration of PV in habitat and large scale MW-size PV systems for production of electricity. For biomass barriers in the biomass supply-use chain will be addressed in the following areas: production, combustion technologies, gasification technologies for elec-tricity and H2/syngas production and biofuels for transport.

11.6 Conclusion On the one hand, the above mentioned action fields of the programme reflect largely the find-ings of the DECENT futures study. On the other hand, with less resources, enlargement, and globalisation resources should be focused and with a few, but well-defined targets. It would therefore be relevant to raise the following questions:

• How can a critical mass be developed within sectors of energy? For example fuel cells have a high score in the quality assessment, but to match international research and devel-opment, more focusing and concentration of efforts are needed.

• How should short term and long term impact be balanced and evaluated? For example the targets of the Kyoto Protocol requires actions to be undertaken now, but on the other hand profound changes in the energy system it needed for the longer run.

• How should environmental impact, innovation and cost reduction be balanced and evalu-ated and should other criteria such as socio-economics also be included?



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• How should the balance between bottom-up approach of proposers/researchers and the top-down approach of society/politics be assessed and evaluated? For example, should the Commission take a more active role in bringing proposers together in clusters, including producers and users of technology.

• How can EU and Member State energy research be linked? The future R&D priorities regarding renewables should take into consideration the questions raised above and develop criteria that reflect these concerns. The DECENT futures study in-dicates that these criteria should emphasise both environmental concerns as well as activities aiming at cost reduction.

DECENT Final Report Conclusions and recommendations


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12 Conclusions and recommendations The DECENT project has identified the main barriers and success factors to the implementa-tion of DG projects within the EU and has formulated a number of related recommendations to EU and Member State policy makers to enhance the feasibility of DG projects within the internal energy market. Most of the barriers that have been identified are attributable to electricity regulatory regimes which hardly recognise the values of DG, in particular those values related to environmental benefits, to electrical or grid services, and to security of supply in greater Europe. It is there-fore essential that future energy policies for the electricity sector acknowledge and value the qualities of DG. Considering the ongoing trend of liberalisation and the increased use of mar-ket mechanisms as policy instruments it is recommended to take an approach to policy devel-opment that is market compatible. The ultimate goal should be to design markets that ensure a level playing field for centralised and decentralised generation. Markets must be open and transparent, and should give fair chances to different types of actors. Finally, in the long run, the environmental values of DG should be acknowledged in a market compatible manner while energy prices reflect external costs.

12.1 DG interconnection and system integration While the Electricity Directive requires network operators to maintain a secure and reliable system, it does not presently require DSOs to consider the benefits of DG in their grid development planning. The amended proposal to amend the Electricity Directive would make such obligations explicit.88

This is based on the recognition that DG complements and augments the existing network infrastructure, and thus influences its development. Therefore provisions that relate to the development of the grid through expansion, upgrades and connection are fundamental to DG. The Renewables Directive (Article 7) does provide a framework to facilitate interconnection for RES developers, and similar provisions have been proposed for in the CHP Directive. This leads to the following recommendations: 1. Provide transparency on terms, conditions, and procedures for connection. Transparency

reduces uncertainty and project risks for a DG developer, and prevents lengthy negotia-tions with the distribution network operator.

2. Establish transparent and efficient rules relating to the allocation of costs of technical ad-aptations, such as grid connections and grid reinforcements, to all users of the grid, in-cluding future generators or consumers. Ideally, these rules should also acknowledge DG benefits to the network, such as avoided grid investments and grid losses. Examples for such cost-bearing or cost-allocation rules can be seen in Germany and Denmark. In Ger-many, all costs incurred by necessary grid reinforcements are to borne by the grid opera-tor, while direct connection costs are borne by the RES developer. In Denmark, however,

88 Article 11(5) would provide: "When planning the development of the distribution network, energy efficiency/demand-side management measures and/or distributed generation that might supplant the need to upgrade or replace electricity capacity shall be considered by the distribution system operator.”



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grid extensions for the connection of off-shore wind farms are considered a public good, and thus borne by the grid operator. Article 7 of the Renewables Directive requires Member States to set up a legal framework or require transmission system operators and distribution system operators to address these issues, and is proposed in the CHP directive. It is recommended to include similar provi-sions in the proposed amended Directive to amend the Electricity Directive, as this would have the advantage of covering all producers.

3. Adopt uniform technical standards for interconnection to the grid. This reduces the scope for dispute on the technical requirements associated with grid connection. In the process leading to this standardisation it is important that all relevant stakeholders are involved in the discussion, so that the standards do not introduce a bias in favour of any particular party. EU wide standardisation could take the form of an EN-norm issued by CENELEC. For renewable electricity the Renewables Directive provides the basis for the implementa-tion of such standards. It is recommended that the similar provisions be retained in the CHP Directive, as has been proposed.

However, the application of these recommendations may be insufficient when network com-panies have incentives not to connect DG under the applicable regulatory regime. In many countries, distribution network operators are subject to regulations requiring them to cut their costs annually. This may act as a disincentive to connect DG. Economic regulation of network companies should therefore be neutral to the integration of DG into the network. Price and quality regulation should provide incentives to network companies to deal with connection requests in a fair and efficient manner. Further research is required on different regulation models and cost allocation methodologies. Once interconnected, the charges for using the network may impose additional barriers, ad-dressed by the following recommendations. 4. Stricter unbundling of (distribution) network operation and ownership from generation

and supply should help ensure the independence of transmission and distribution system operators. This would prevent the influence of vested interest on the network operation, and significantly reduce the risk of excessive costs and other unfair conditions imposed on network use by independent electricity producers. However, Article 10 of the most recent proposal for an amended Electricity Directive (June 2002) gives Member States the possi-bility to exempt integrated electricity undertakings serving less than 100.000 customers from the duty of complete unbundling. Although this is a practical approach that protects smaller companies, specific rules are missing to ensure that access to, and use of, the net-work are provided under completely fair and transparent conditions in such cases.

5. Introduce ex ante approval & publication of grid use tariffs reflecting long-term marginal avoided network costs as stated in the proposed amendments to the Electricity Directive (Recital 14).

6. Ensure transparent, non-discriminatory and cost-reflective back-up power charges. This is particularly important for CHP and should be a provision in the proposed CHP Directive. Moreover, we recommend this provision to be included in the Electricity Directive to have it cover all autoproducers.



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12.2 DG authorisations and permitting Acquiring authorisation and planning consents for the establishment of DG installations is a major barrier to many projects, due to non-transparent and time-consuming procedures, and local opposition. Given the country-specific and local character of the planning and authorisa-tion processes and institutions, the scope for EU legislation is limited. The provisions in the Renewables Directive provide a good basis for Member States to review and improve their administrative procedures for planning and permitting processes. The communication towards Member States should stress that they should start their evaluation timely to be able to issue a first report to the Commission by October 2003. This leads to the following recommendations, formulated for the Member States. 1. Streamline and expedite planning and authorisation procedures, in conformity with the

requirements of Article 6 of the Renewables Directive and Article 5(3) of the amended proposal for amendment of the Electricity Directive.89

2. Review and improve national planning procedures on specific issues such as deadlines and clear reception points. Progress made on this issue is to be highlighted in the reports due according to the Renewables Directive, Article 6.

3. Proactive designation of areas in spatial plans (RES) and heat planning (CHP) enables local authorities to balance the interests of different parties and reduces the siting efforts for DG developers.

4. Involve local actors, because they can provide equity, and their involvement often reduces local resistance. Many schemes are possible, examples have been given in Chapter 9.2. Regional energy agencies can play a role in providing information, and the issue should be highlighted in the reports due according to the Renewables Directive, Article 6.

5. One step further could be to co-ordinate spatial planning, network planning and integra-tion of RES. When governments appoint specific locations within their jurisdiction for RES development, the most eligible sites are not always the most optimal sites from a network integration point of view. Those involved in spatial planning should have infor-mation on cost of connection (ex ante price signals in the network, facilitated by ICT). Network operators could take the designated DG development areas into account in their grid planning

12.3 Financing DG Due to the lack of a level playing field in present electricity markets, and because the external cost of electricity production are not reflected in the prices, many DG technologies need fi-nancial support to be viable under current market conditions. In the long run, DG should be integrated into current electricity markets not through subsidies or support mechanisms, but rather, upon the recognition of the environmental and other values of DG, the internalisation of external costs, the creation of a level playing field, and non-discriminatory and transparent 89 Article 5(3) of the amended proposal would require Member States to "take appropriate measures to stream-

line and expedite authorisation procedures for small and/or distributed generation. These measures shall apply to all facilities of less than 15 MW and to all distributed generation."



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treatment of DG, and proper incentivisation of distribution system operators. Thus, although we discuss and analyse the various support mechanisms in place, and their possible harmoni-sation, it should be clear that the indefinite perpetuation of the current support systems is not recommended. This leads to the following recommendations. 1. One of the major general problems of the development of DG installations is the uncer-

tainty that is connected with the existing and future legislative framework. This concerns both the completion of the internal market and national or EU-wide support mechanisms for RES and CHP. A quick finalisation of the policy packages, especially the amendment of the Directives concerning the internal markets for electricity and gas and the discussed CHP Directive, would significantly contribute to a higher planning security and thus to easier financing.

2. Support mechanisms should only be in place until DG technologies are financially viable due to internalisation of external costs and technology development. Examples of market compatible mechanisms are emission trading and Green or CHP certificates. These create added value for DG options by internalising their external benefits. Especially combined with mandatory national targets and annual timetables for DG development until 2010, such a system could achieve relative predictable conditions under (uncertain) market con-ditions and set the basis for coherent, measurable national policies to develop DG.

3. With a view to providing a more stable long-term policy framework it is desirable that long-term (2020) targets for the integration of renewables and cogeneration are fixed at the EU level. This would give a clear signal to investors and lenders.

4. To reduce the uncertainty to investors, support policies should take into account and an-ticipate the future harmonisation of support frameworks across the EU. Member States should anticipate harmonisation while the EU should provide clarity on harmonisation as soon as possible within the framework of the Renewables Directive. Note that after 2005, when the Commission will issue a report on the experiences gained and may include pro-posal for harmonisation, there is still a transition period of 7 years.

5. As many DG projects are set up by small-scale players, it is important to reduce their transaction costs in using support mechanisms and in operating on the electricity market.

12.4 The impact of DG on the security of supply Security of supply as a factor for the development of decentralised technologies is not only related to the dependence on imported fuels but also to the value of decentralised generation in the power system in a wider context. Several pros and cons of DG technologies in improv-ing security of supply have been identified.

• In general decentralised plants tend to substitute a high degree of imported fuels

• Due to their small sizes they are fairly easy to introduce into an existing power system. Technologies as wind power, hydropower and photovoltaics are very robust towards fu-ture changes in fuel prices.

• With regard to capacity availability decentralised plants are at least at the same level as conventional ones. With regard to the availability of the energy production wind power



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and photovoltaics are less reliable, due to their dependence on natural resources as wind and solar.

• Larger plants can to a much higher degree take advantage of economies to scale. With the exception of CHP and perhaps small hydropower plants most decentralised technologies do need some kind of subsidisation. Though wind power is moving fast towards being competitive with conventional plants.

• Though the analysis of financial risks shows an unclear picture, it tends towards a lower risk for most decentralised technologies compared with conventional ones.

• In general the vulnerability towards external disturbances is much lower for decentralised plants than for large centralised ones. Especially in situations with transmission line fail-ures, DG may benefit by having the possibility of keeping up the power with in its supply areas.

Thus although the picture is a little bit scattered, in general the deployment of decentralised generation technologies will improve security of supply within the EU. To diminish some of the barriers for DG to play a larger role in security of supply, the following policy actions are recommended:

1. The definition of security of supply should not be restricted to dependence of imported fuels – as is the case in the Green Paper on security of supply – but should include other characteristics of decentralised generation as well, among these robustness towards exter-nal changes, availability of capacity and vulnerability.

2. The possible deployment of decentralised technologies seems to depend heavily on the organisational set-up of the power industry in the Member States. Although economics of decentralised plants might be equivalent to large power plants, other considerations con-cerning the plants capabilities of contributing to the general load management or in keep-ing up the required reserve capacity might be more important in deciding what kind of plant to construct, especially if the power industry is not taking part in a liberalised power market. Thus part of this barrier could be abandoned if the power industry was liberalised in all EU Member States.

12.5 EU energy technology R&D Technology research and development plays a key role in developing and implementing de-centralised energy generation in the EU. This is confirmed by the DECENT future study, a survey conducted among a group of DG experts, who in particular stress the importance of R&D for PV and fuel cells, but also for achieving cost reduction in biomass technologies and for developing new wind turbine concepts. The analysis of current and planned EU R&D policies shows that these are to a large extent in line with these findings. On the other hand, with less resources, as announced in the future key actions for sustainable development of the 6th Framework Programme, EU enlargement, and globalisation, resources should be focused with a few, but well-defined targets. The DECENT future study indicates that these policies should emphasise both environmental concerns as well as activities aiming at cost reduction.



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12.6 Recommendations for further research There are many subjects that are important to the integration of DG in EU electricity systems which could not be studied within the DECENT project, but which deserve further attention in future research projects. First, given the expected growth of the market share of intermittent renewables and heat-based CHP, the costs of imbalances will become increasingly important, and the application of priority dispatch mechanisms may become increasingly less feasible. Therefore, further research on technical and market solutions to balancing problems is crucial. 1. Research on technical solutions to imbalances: due to the intermittent nature of mainly

wind real cost are incurred by the electricity system as a whole. These costs are not re-solved through priority dispatch. In order to enable DG operators to limit imbalances, re-search on electricity storage is needed.

2. Research on market solutions to balancing problems. Although in the short run, priority dispatch may be a mechanism to shield DG from the effects of balancing and settlement systems which have not been geared up to integrate DG, this will become more costly when the share of DG in the market increases. More economic research should be directed at how intermittent renewables and CHP can be treated in balancing and settlement mechanisms, how balancing costs should be allocated and how incentives can be given to different actors.

3. Finally, it is recommended that further research on the role of information and communi-cation technology (ICT) in co-ordinating market and network operations should be con-ducted. ICT systems can indicate what’s happening on the networks, and thus provide greater transparency to network operators.



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